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Williams Companies 10-K 2008 Documents found in this filing:
Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, DC 20549
Commission file number 1-4174
918-573-2000
(Registrant’s Telephone
Number, Including Area Code)
Securities registered pursuant to Section 12(g) of the
Act:
5.50% Junior Subordinated Convertible Debentures due 2033
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, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in
Rule 12b-2
of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity was last sold, as of the last
business day of the registrant’s most recently completed
second quarter was approximately $18,963,794,420.
The number of shares outstanding of the registrant’s common
stock outstanding at February 21, 2008 was 585,021,071.
THE
WILLIAMS COMPANIES, INC.
FORM 10-K
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We use the following oil and gas measurements in this report:
Bcfe — means one billion cubic feet of gas
equivalent determined using the ratio of one barrel of oil or
condensate to six thousand cubic feet of natural gas.
Bcf/d — means one billion cubic feet per day.
British Thermal Unit or BTU — means a unit of
energy needed to raise the temperature of one pound of water by
one degree Fahrenheit.
BBtud — means one billion BTUs per day.
Dekatherms or Dth or Dt — means a unit of
energy equal to one million BTUs.
Mbbls/d — means one thousand barrels per day.
Mcfe — means one thousand cubic feet of gas
equivalent using the ratio of one barrel of oil or condensate to
six thousand cubic feet of natural gas.
Mdt/d — means one thousand dekatherms per day.
MMcf — means one million cubic feet.
MMcf/d —
means one million cubic feet per day.
MMcfe — means one million cubic feet of gas
equivalent using the ratio of one barrel of oil or condensate to
six thousand cubic feet of natural gas.
MMdt — means one million dekatherms or
approximately one trillion BTUs.
MMdt/d — means one million dekatherms per day.
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In this report, Williams (which includes The Williams Companies,
Inc. and, unless the context otherwise requires, all of our
subsidiaries) is at times referred to in the first person as
“we,” “us” or “our.” We also
sometimes refer to Williams as the “Company.”
We file our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
proxy statements and other documents electronically with the
Securities and Exchange Commission (SEC) under the Securities
Exchange Act of 1934, as amended (Exchange Act). You may read
and copy any materials that we file with the SEC at the
SEC’s Public Reference Room at 450 Fifth Street, N.W.,
Washington, DC 20549. You may obtain information on the
operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330.
You may also obtain such reports from the SEC’s Internet
website at
http://www.sec.gov.
Our Internet website is
http://www.williams.com.
We make available free of charge on or through our Internet
website our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act as soon as
reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. Our Corporate
Governance Guidelines, Code of Ethics, board committee charters
and Code of Business Conduct are also available on our Internet
website. We will also provide, free of charge, a copy of any of
our corporate documents listed above upon written request to our
Secretary at Williams, One Williams Center, Suite 4700,
Tulsa, Oklahoma 74172.
We are a natural gas company originally incorporated under the
laws of the state of Nevada in 1949 and reincorporated under the
laws of the state of Delaware in 1987. We were founded in 1908
when two Williams brothers began a construction company in
Fort Smith, Arkansas. Today, we primarily find, produce,
gather, process and transport natural gas. Our operations are
concentrated in the Pacific Northwest, Rocky Mountains, Gulf
Coast, and the Eastern Seaboard.
We continue to use Economic Value
Added®(EVA®)1
as the basis for disciplined decision making around the use of
capital.
EVA®
is a tool that considers both financial earnings and a cost of
capital in measuring performance. It is based on the idea that
earning profits from an economic perspective requires that a
company cover not only all of its operating expenses but also
all of its capital costs. The two main components of
EVA®
are net operating profit after taxes and a charge for the
opportunity cost of capital. We derive these amounts by making
various adjustments to our reported results and financial
position, and by applying a cost of capital. We look for
opportunities to improve
EVA®
because we believe there is a strong correlation between
EVA®
improvement and creation of shareholder value.
Our goal is to create superior sustainable growth in
EVA®
and shareholder value. In early 2006, we set some ambitious
three-year goals referred to as our game plan for growth. Our
success in achieving the game plan for growth contributed to our
significant accomplishments in 2007 designed to increase
shareholder value, including:
1 Economic
Value
Added®
(EVA®)
is a registered trademark of Stern, Stewart & Co.
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Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172. Our telephone number is
918-573-2000.
During third-quarter 2007, we formed Williams Pipeline Partners
L.P. (WMZ) to own and operate natural gas transportation and
storage assets. In January 2008, WMZ completed its initial
public offering of 16.25 million common units at a price of
$20.00 per unit. The underwriters also exercised their option to
purchase an additional 1.65 million common units at the
same price.
In December 2007, Williams Partners L.P. (WPZ) acquired certain
of our membership interests in Wamsutter LLC, the limited
liability company that owns the Wamsutter system, from us for
$750 million.
In December 2007, we repurchased $213 million of
7.125 percent notes due September 2011 and $22 million
of 8.125 percent notes due March 2012.
On November 28, 2007, Transcontinental Gas Pipe Line
Corporation (Transco) filed a formal stipulation and agreement
with the Federal Energy Regulatory Commission (FERC) resolving
all substantive issues in Transco’s pending 2006 rate case.
Final resolution of the rate case is subject to approval by the
FERC.
On November 9, 2007, we closed on the sale of substantially
all of our power business to Bear Energy, LP, a unit of The Bear
Stearns Companies, Inc., for $496 million, subject to
post-closing adjustments. The assets sold included tolling
contracts, full requirements contracts, tolling resales, heat
rate options, related hedges and other related assets including
certain property and software. This sale reduces the risk and
complexity of our overall business.
In November 2007, our credit ratings were raised to investment
grade based on improvements in our credit outlook. As we
continue to invest and grow our natural gas businesses, our
improved credit rating is expected to provide greater access to
capital and more favorable loan terms. See additional discussion
of credit ratings in Management’s Discussion and
Analysis of Financial Condition.
In July 2007, our Board of Directors authorized the repurchase
of up to $1 billion of our common stock. We intend to
purchase shares of our stock from time to time in open-market
transactions or through privately negotiated or structured
transactions at our discretion, subject to market conditions and
other factors. This stock-repurchase program does not have an
expiration date. During 2007, we repurchased approximately
16 million shares for $526 million (including
transaction costs) at an average cost of $33.08 per share.
In April 2007, our Board of Directors approved a regular
quarterly dividend of 10 cents per share, which reflects an
increase of 11 percent compared to the 9 cents per share
that we paid in each of the four prior quarters and marks the
fourth increase in our dividend since late 2004.
On March 30, 2007, the FERC approved the stipulation and
settlement agreement with respect to the rate case for Northwest
Pipeline GP (Northwest Pipeline), formerly Northwest Pipeline
Corporation.
See Note 17 of our Notes to Consolidated Financial
Statements for information with respect to each segment’s
revenues, profits or losses and total assets. See Note 9
for information with respect to property, plant and equipment
for each segment.
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Substantially all our operations are conducted through our
subsidiaries. To achieve organizational and operating
efficiencies, our activities are primarily operated through the
following business segments:
This report is organized to reflect this structure.
Detailed discussion of each of our business segments follows.
Our Exploration & Production segment, which is
comprised of several wholly owned and partially owned
subsidiaries, including Williams Production Company LLC and
Williams Production RMT Company (RMT), produces, develops, and
manages natural gas reserves primarily located in the Rocky
Mountain (primarily New Mexico, Wyoming and Colorado) and
Mid-Continent (Oklahoma and Texas) regions of the United States.
We specialize in natural gas production from tight-sands and
shale formations and coal bed methane reserves in the Piceance,
San Juan, Powder River, Arkoma, Green River and
Fort Worth basins. Over 99 percent of
Exploration & Production’s domestic reserves are
natural gas. Our Exploration & Production segment also
has international oil and gas interests, which include a
69 percent equity interest in Apco Argentina Inc. (Apco
Argentina), an oil and gas exploration and production company
with operations in Argentina, and a four percent equity interest
in Petrowayu S.A., a Venezuelan corporation that is the operator
of a 100 percent interest in the La Concepcion block
located in Western Venezuela.
Exploration & Production’s primary strategy is to
utilize its expertise in the development of tight-sands, shale,
and coal bed methane reserves. Exploration &
Production’s current proved undeveloped and probable
reserves provide us with strong capital investment opportunities
for several years into the future. Exploration &
Production’s goal is to drill its existing proved
undeveloped reserves, which comprise approximately
46 percent of proved reserves and to drill in areas of
probable reserves. In addition, Exploration &
Production provides a significant amount of equity production
that is gathered
and/or
processed by our Midstream facilities in the San Juan basin.
Information for our Exploration & Production segment
relates only to domestic activity unless otherwise noted. We use
the terms “gross” to refer to all wells or acreage in
which we have at least a partial working interest and
“net” to refer to our ownership represented by that
working interest.
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The following table summarizes our U.S. natural gas
reserves as of December 31 (using market prices on December 31
held constant) for the year indicated:
No major discovery or other favorable or adverse event has
caused a significant change in estimated gas reserves since
year-end 2007. We have not filed on a recurring basis estimates
of our total proved net oil and gas reserves with any
U.S. regulatory authority or agency other than the
Department of Energy (DOE) and the SEC. The estimates furnished
to the DOE have been consistent with those furnished to the SEC,
although Exploration & Production has not yet filed
any information with respect to its estimated total reserves at
December 31, 2007, with the DOE. Certain estimates filed
with the DOE may not necessarily be directly comparable due to
special DOE reporting requirements, such as the requirement to
report gross operated reserves only. In 2006 and 2005 the
underlying estimated reserves for the DOE did not differ by more
than five percent from the underlying estimated reserves
utilized in preparing the estimated reserves reported to the SEC.
Approximately 98 percent of our year-end 2007 United States
proved reserves estimates were audited in each separate basin by
Netherland, Sewell & Associates, Inc. (NSAI). When
compared on a
well-by-well
basis, some of our estimates are greater and some are less than
the estimates of NSAI. However, in the opinion of NSAI, the
estimates of our proved reserves are in the aggregate reasonable
by basin and have been prepared in accordance with generally
accepted petroleum engineering and evaluation principles. These
principles are set forth in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information
promulgated by the Society of Petroleum Engineers. NSAI is
satisfied with our methods and procedures in preparing the
December 31, 2007 reserve estimates and saw nothing of an
unusual nature that would cause NSAI to take exception with the
estimates, in the aggregate, as prepared by us. Reserve
estimates related to properties underlying the Williams Coal
Seam Gas Royalty Trust, which comprise approximately two percent
of our total U.S. proved reserves, were prepared by Miller
and Lents, LTD.
On December 12, 2007, the SEC issued a “Concept
Release” to obtain information about the extent and nature
of the public’s interest in revising oil and gas reserves
disclosure requirements which exist in their current form in
Regulation S-K
and
Regulation S-X
under the Securities Act of 1933 and the Securities Exchange Act
of 1934. The Commission adopted the current oil and gas reserves
disclosure requirement between 1978 and 1982. The Concept
Release is intended to address significant changes in the oil
and gas industry. Some commentators have expressed concern that
the Commission’s rules have not adapted to current
practices and may not provide investors with the most useful
picture of oil and gas reserves public companies hold. Comments
were due to the Commission on February 19, 2008. At this
time it is not possible to determine what effect changes the SEC
may make, if any, will have on our reserve estimates and
disclosures.
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The table below summarizes 2007 activity and reserves for each
of our areas, with further discussion following the table.
The Piceance basin is located in northwestern Colorado and is
our largest area of concentrated development. During 2007 we
operated an average of 25 drilling rigs in the basin. As of
December 2007, 14 of these rigs were the new high efficiency
rigs designed to drill up to 22 wells from one location.
This area has approximately 1,760 undrilled proved locations in
inventory. Within this basin we own and operate natural gas
gathering facilities including some 280 miles of gathering
lines and associated field compression. Approximately 88% of the
gas gathered is our own equity production. The gathering system
also includes six processing plants and associated treating
facilities with a total capacity of 900,000 Mcfd. During
2007, these plants recovered approximately 54 million
gallons of natural gas liquids (NGL’s) which were marketed
separately from the residue natural gas.
San Juan
basin
The San Juan basin is located in northwest New Mexico and
southwest Colorado.
The Powder River basin is located in northeast Wyoming. The
Powder River basin includes large areas with multiple coal seam
potential, targeting thick coal bed methane formations at
shallow depths. We have a significant inventory of undrilled
locations, providing long-term drilling opportunities.
The Mid-Continent properties are located in the southeastern
Oklahoma portion of the Arkoma basin and the Barnett Shale in
the Fort Worth basin of Texas.
Other properties are primarily comprised of interests in the
Green River basin in southwestern Wyoming. Also included is
exploration activity and other miscellaneous activity.
The following table summarizes our leased acreage as of
December 31, 2007:
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We focus on lower-risk development drilling. Our drilling
success rate was 99 percent in 2007, 2006 and 2005. The
following tables summarize domestic drilling activity by number
and type of well for the periods indicated:
Because we currently have a low-risk drilling program in proven
basins, the main component of risk that we manage is price risk.
In February 2007, we entered into a five-year unsecured credit
agreement with certain banks in order to reduce margin
requirements related to our hedging activities as well as lower
transaction fees. Margin requirements, if any, under this new
facility are dependent on the level of hedging with the banks
and on natural gas reserves value. Exploration &
Production natural gas hedges for 2008 domestic natural gas
production consist of NYMEX fixed price contracts of 70 MMcf/d
(whole year) and approximately 397 MMcf/d in regional collars
(whole year). Our natural gas production hedges in 2007
consisted of 172 MMcf/d in NYMEX fixed price hedges and an
additional 271 MMcf/d in NYMEX and basin level collars. A collar
is an option contract that sets a gas price floor and ceiling
for a certain volume of natural gas. Hedging decisions are made
considering the overall Williams commodity risk exposure and are
not executed independently by Exploration &
Production; there are expected future gas purchases for other
Williams entities which when taken as a net position may offset
price risk related to Exploration & Production’s
expected future gas sales.
The following table summarizes our domestic sales and cost
information for the years indicated:
Through transactions totaling approximately $77 million,
Exploration & Production expanded its acreage position
and purchased producing properties in the Fort Worth basin
in north-central Texas and also expanded its acreage position in
the Highlands area of the Piceance basin.
In January 2008, we sold a contractual right to a production
payment on certain future international hydrocarbon production
in Peru for approximately $148 million. We have received
$118 million in cash and $29 million has been placed
in escrow subject to certain post-closing conditions and
adjustments. We will recognize a pre-tax gain of approximately
$118 million in the first quarter of 2008 related to the
initial cash received. As a result of the contract termination,
we have no further interests associated with the crude oil
concession. We had obtained these interests through our
acquisition of Barrett Resources Corporation in 2001.
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In 1993, Exploration & Production conveyed a net
profits interest in certain of its properties to the Williams
Coal Seam Gas Royalty Trust. Substantially all of the production
attributable to the properties conveyed to the trust was from
the Fruitland coal formation and constituted coal seam gas. We
subsequently sold trust units to the public in an underwritten
public offering and retained 3,568,791 trust units then
representing 36.8 percent of outstanding trust units. We
have previously sold trust units on the open market, with our
last sales in June 2005. As of February 1, 2008, we own
789,291 trust units.
We also have investments in international oil and gas interests.
If combined with our domestic proved reserves, our international
interests would make up approximately 3.6 percent of our
total proved reserves.
Gas
Pipeline
We own and operate, through Williams Gas Pipeline Company, LLC
(WMZ) and its subsidiaries, a combined total of approximately
14,200 miles of pipelines with a total annual throughput of
approximately 2,700 trillion British Thermal Units of natural
gas and
peak-day
delivery capacity of approximately 12 MMdt of gas. Gas
Pipeline consists of Transcontinental Gas Pipe Line Corporation
and Northwest Pipeline GP. Gas Pipeline also holds interests in
joint venture interstate and intrastate natural gas pipeline
systems including a 50 percent interest in Gulfstream
Natural Gas System, L.L.C. Gas Pipeline also includes our new
master limited partnership, Williams Pipeline Partners, L.P.
Transco is an interstate natural gas transportation company that
owns and operates a 10,300-mile natural gas pipeline system
extending from Texas, Louisiana, Mississippi and the offshore
Gulf of Mexico through Alabama, Georgia, South Carolina, North
Carolina, Virginia, Maryland, Pennsylvania, and New Jersey to
the New York City metropolitan area. The system serves customers
in Texas and 11 southeast and Atlantic seaboard states,
including major metropolitan areas in Georgia, North Carolina,
New York, New Jersey, and Pennsylvania.
At December 31, 2007, Transco’s system had a mainline
delivery capacity of approximately 4.7 MMdt of natural gas
per day from its production areas to its primary markets. Using
its Leidy Line along with market-area storage and transportation
capacity, Transco can deliver an additional 3.7 MMdt of
natural gas per day for a system-wide delivery capacity total of
approximately 8.4 MMdt of natural gas per day.
Transco’s system includes 45 compressor stations, five
underground storage fields, two liquefied natural gas (LNG)
storage facilities. Compression facilities at a sea level-rated
capacity total approximately 1.5 million horsepower.
Transco’s major natural gas transportation customers are
public utilities and municipalities that provide service to
residential, commercial, industrial and electric generation end
users. Shippers on Transco’s system include public
utilities, municipalities, intrastate pipelines, direct
industrial users, electrical generators, gas marketers and
producers. One customer accounted for approximately
12 percent of Transco’s total revenues in 2007.
Transco’s firm transportation agreements are generally
long-term agreements with various expiration dates and account
for the major portion of Transco’s business. Additionally,
Transco offers storage services and interruptible transportation
services under short-term agreements.
Transco has natural gas storage capacity in five underground
storage fields located on or near its pipeline system or market
areas and operates three of these storage fields. Transco also
has storage capacity in an LNG storage facility and operates the
facility. The total usable gas storage capacity available to
Transco and its customers in such underground storage fields and
LNG storage facility and through storage service contracts is
approximately 216 billion cubic feet of gas. In addition,
wholly owned subsidiaries of Transco operate and hold a
35 percent ownership interest in Pine Needle LNG Company,
LLC, an LNG storage facility with 4 billion cubic feet of
storage
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capacity. Storage capacity permits Transco’s customers to
inject gas into storage during the summer and off-peak periods
for delivery during peak winter demand periods.
The pipeline projects listed below were completed during 2007 or
are future pipeline projects for which we have customer
commitments.
In November 2007, we placed into service the Potomac Expansion
Project, an expansion of our existing natural gas transmission
system from receipt points in North Carolina to delivery points
in the greater Baltimore and Washington, D.C. metropolitan
areas. The second phase of the project involving installation of
certain appurtenant facilities will be completed in fall 2008.
The capital cost of the project is estimated to be approximately
$88 million.
In December 2007, we placed into service the Leidy to Long
Island Expansion Project, an expansion of our existing natural
gas transmission system in Zone 6 from the Leidy Hub in
Pennsylvania to Long Island, New York. The capital cost of the
project is estimated to be approximately $169 million.
The Sentinel Expansion Project will involve an expansion of our
existing natural gas transmission system from the Leidy Hub in
Clinton County, Pennsylvania and from the Pleasant Valley
interconnection with Cove Point LNG in Fairfax County, Virginia
to various delivery points requested by the shippers under the
project. The capital cost of the project is estimated to be up
to approximately $169 million. Transco plans to place the
project into service in phases, in late 2008 and late 2009.
The Pascagoula Expansion Project will involve the construction
of a new pipeline to be jointly owned with Florida Gas
Transmission connecting Transco’s existing Mobile Bay
Lateral to the outlet pipeline of a proposed liquefied natural
gas import terminal in Mississippi. Transco’s share of the
estimated capital cost of the project is up to $37 million.
Transco plans to place the project into service in mid-2011.
The following table summarizes transportation data for the
Transco system for the periods indicated:
Transco’s facilities are divided into eight rate zones.
Five are located in the production area, and three are located
in the market area. Long-haul transportation involves gas that
Transco receives in one of the production-area
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zones and delivers to a market-area zone. Market-area
transportation involves gas that Transco both receives and
delivers within the market-area zones. Production-area
transportation involves gas that Transco both receives and
delivers within the production-area zones.
Northwest Pipeline is an interstate natural gas transportation
company that owns and operates a natural gas pipeline system
extending from the San Juan basin in northwestern New
Mexico and southwestern Colorado through Colorado, Utah,
Wyoming, Idaho, Oregon and Washington to a point on the Canadian
border near Sumas, Washington. Northwest Pipeline provides
services for markets in California, Arizona, New Mexico,
Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington
directly or indirectly through interconnections with other
pipelines.
At December 31, 2007, Northwest Pipeline’s system,
having long-term firm transportation agreements with peaking
capacity of approximately 3.4 MMdt of natural gas per day,
was composed of approximately 3,900 miles of mainline and
lateral transmission pipelines and 41 transmission compressor
stations having a combined sea level-rated capacity of
approximately 473,000 horsepower.
Northwest implemented new rates effective January 1, 2007
that were approved by FERC. The rate case settlement established
that general system firm transportation rates on
Northwest’s system increased from $0.30760 to $0.40984 per
Dth.
In 2007, Northwest Pipeline served a total of 132 transportation
and storage customers. Transportation customers include
distribution companies, municipalities, interstate and
intrastate pipelines, gas marketers and direct industrial users.
The two largest customers of Northwest Pipeline in 2007
accounted for approximately 20 percent and
11.5 percent, of its total operating revenues. No other
customer accounted for more than 10 percent of Northwest
Pipeline’s total operating revenues in 2007. Northwest
Pipeline’s firm transportation agreements are generally
long-term agreements with various expiration dates and account
for the major portion of Northwest Pipeline’s business.
Additionally, Northwest Pipeline offers interruptible and
short-term firm transportation service.
As a part of its transportation services, Northwest Pipeline
utilizes underground storage facilities in Utah and Washington
enabling it to balance daily receipts and deliveries. Northwest
Pipeline also owns and operates an LNG storage facility in
Washington that provides service for customers during a few days
of extreme demands. These storage facilities have an aggregate
firm delivery capacity of approximately 600 million cubic
feet of gas per day.
The pipeline projects listed below were completed during 2007 or
are future pipeline projects for which we have customer
commitments.
The Jackson Prairie Storage Project, connected to
Northwest’s transmission system near Chehalis, Washington,
is operated by Puget Sound Energy and is jointly owned by
Northwest, Puget Sound Energy and Avista Corporation. A phased
capacity expansion is currently underway and a deliverability
expansion is planned for 2008. Northwest’s one-third
interest in the project includes 104 MMcf per day of
planned 2008 deliverability expansion and approximately
1.2 Bcf of working natural gas storage capacity to be
developed over approximately a four year period from 2007
through 2010. Northwest’s one-third share of the cost of
the deliverability expansion is estimated to be
$16 million. Northwest’s estimated capital cost for
the capacity expansion component of the new storage service is
$6.1 million, primarily for base natural gas.
Northwest has proposed installing a new lateral to connect the
White River Hub near Meeker, Colorado to Northwest’s
mainline near Sand Springs, Colorado. This project is referred
to as the Colorado Hub
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Connection, or CHC Project. It is estimated that the
construction of the CHC Project would cost up to
$53 million and could begin service as early as November
2009.
Northwest placed its Parachute Lateral facilities in service on
May 16, 2007, and began collecting revenues of
approximately $0.87 million per month. The expansion
increased capacity by 450 Mdt/d at a cost of approximately
$86 million.
On August 24, 2007, Northwest filed an application with
FERC to amend its certificate of public convenience and
necessity issued for the Parachute Lateral to allow the transfer
of the ownership of its Parachute Lateral facilities to a newly
created entity, Parachute Pipeline LLC (Parachute), which is
owned by Midstream through one of its wholly-owned subsidiaries
Williams Field Services Company, LLC (Williams Field Services).
This application was approved by FERC on November 15, 2007,
and Northwest sold the Parachute on December 31, 2007. The
Parachute Lateral facilities are located in Rio Blanco and
Garfield counties, Colorado.
As contemplated in the application for amendment, Parachute has
leased the facilities back to Northwest, and as a result of the
sale has become a Midstream subsidiary. Northwest will continue
to operate the facilities under the FERC certificate. When
Midstream completes its Willow Creek Processing Plant, the lease
(subject to further regulatory approval) will terminate, and
Parachute will assume full operational control and
responsibility for the Parachute Lateral.
The following table summarizes volume and capacity data for the
Northwest Pipeline system for the periods indicated:
Gulfstream is a natural gas pipeline system extending from the
Mobile Bay area in Alabama to markets in Florida. Gas Pipeline
and Spectra Energy (formerly known as Duke Energy), through
their respective subsidiaries, each holds a 50 percent
ownership interest in Gulfstream and provides operating services
for Gulfstream. At December 31, 2007, our equity investment
in Gulfstream was $439 million.
Gulfstream has entered into a precedent agreement and a related
firm transportation service agreement pursuant to which, subject
to the receipt of all necessary regulatory approvals and other
conditions precedent therein, Gulfstream intends to extend the
pipeline system into South Florida and fully subscribe the
remaining 345 Mdt/d of firm capacity on the existing pipeline
system on a long-term basis. The estimated capital cost of this
project is anticipated to be up to approximately
$130 million, with Gas Pipeline’s share being
50 percent of such costs. Gulfstream also has executed a
precedent agreement and a related firm transportation service
agreement pursuant to which, subject to the receipt of all
necessary regulatory approvals and other conditions precedent
therein, it intends to construct and fully subscribe on a
long-term basis the first incremental expansion of
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Gulfstream’s mainline capacity, increasing the current
mainline capacity of 1.1 MMdt/d to 1.255 MMdt/d. The
estimated capital cost of this expansion is anticipated to be up
to approximately $153 million, with Gas Pipeline’s
share being 50 percent of such costs. No significant
increase in operations personnel is expected as a result of
these two projects.
WMZ was formed to own and operate natural gas transportation and
storage assets. We currently own approximately 45.7 percent
limited partnership interest and a 2 percent general
partner interest in WMZ. WMZ provides us with lower cost of
capital that is expected to enable growth of our Gas Pipeline
business. WMZ also creates a vehicle to monetize our qualifying
assets. Such transactions, which are subject to approval by the
boards of directors of Williams and WMZ’s general partner,
allow us to retain control of the assets through our ownership
interest in WMZ. A subsidiary of ours serves as the general
partner of WMZ. The initial asset of WMZ is a 35 percent
interest in Northwest Pipeline.
Our Midstream segment, one of the nation’s largest natural
gas gatherers and processors, has primary service areas
concentrated in the major producing basins in Colorado, New
Mexico, Wyoming, the Gulf of Mexico, Venezuela and western
Canada. Midstream’s primary businesses — natural
gas gathering, treating, and processing; NGL fractionation,
storage and transportation; and oil transportation —
fall within the middle of the process of taking natural gas and
crude oil from the wellhead to the consumer. NGLs, ethylene and
propylene are extracted/produced at our plants, including our
Canadian and Gulf Coast olefins plants. These products are used
primarily for the manufacture of plastics, home heating and
refinery feedstock.
Although most of our gas services are performed for a
volumetric-based fee, a portion of our gas processing contracts
are commodity-based and include two distinct types of commodity
exposure. The first type includes “Keep Whole”
processing contracts whereby we own the rights to the value from
NGLs recovered at our plants and have the obligation to replace
the lost heating value with natural gas. Under these contracts,
we are exposed to the spread between NGLs and natural gas
prices. The second type consists of “Percent of
Liquids” contracts whereby we receive a portion of the
extracted liquids with no direct exposure to the price of
natural gas. Under these contracts, we are only exposed to NGL
price movements.
Our Canadian and Gulf Liquids olefin facilities have commodity
price exposure. In Canada, we are exposed to the spread between
the price for natural gas and the olefinic products we produce.
In the Gulf Coast, our feedstock for the ethane cracker is
ethane and propane; as a result, we are exposed to the price
spread between ethane and propane and ethylene and propylene. In
the Gulf Coast, we also purchase refinery grade propylene and
fractionate it into polymer grade propylene and propane; as a
result we are exposed to the price spread between those
commodities.
Key variables for our business will continue to be:
We own
and/or
operate domestic gas gathering and processing assets primarily
within the western states of Wyoming, Colorado and New Mexico,
and the onshore and offshore shelf and deepwater areas in and
around the Gulf Coast states of Texas, Louisiana, Mississippi
and Alabama. These assets consist of approximately
8,700 miles of gathering pipelines, nine processing plants
(one partially owned) and five natural gas treating plants with
a combined daily inlet capacity of nearly 6.5 billion cubic
feet per day. Some of these assets are owned through our
interest in WPZ (see William Partners L.P. section below).
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Geographically, our Midstream natural gas assets are positioned
to maximize commercial and operational synergies with our other
assets. For example, most of our offshore gathering and
processing assets attach and process or condition natural gas
supplies delivered to the Transco pipeline. Also, our gathering
and processing facilities in the San Juan Basin handle
about 85 percent of our Exploration & Production
group’s wellhead production in this basin. Both our
San Juan Basin and Southwest Wyoming systems deliver gas
volumes into Northwest Pipeline’s interstate system in
addition to third party interstate systems.
Included in the natural gas assets listed above are the assets
of Discovery Producer Services LLC and its subsidiary Discovery
Gas Transmission Services LLC (Discovery). WPZ owns a partial
interest in Discovery and we operate its facilities.
Discovery’s assets include a cryogenic natural gas
processing plant near Larose, Louisiana, a natural gas liquids
fractionator plant near Paradis, Louisiana and an offshore
natural gas gathering and transportation system in the Gulf of
Mexico.
In addition to these natural gas assets, we own and operate
three crude oil pipelines totaling approximately 310 miles
with a capacity of more than 300,000 barrels per day. This
includes our Mountaineer, Alpine and BANJO crude oil pipeline
systems in the deepwater Gulf of Mexico.
The BANJO oil pipeline and Seahawk gas pipeline run parallel and
deliver production across two producer-owned spar-type floating
production systems from the Anadarko Petroleum Corporation
(Anadarko) operated Boomvang and Nansen field areas in the
western Gulf of Mexico. These pipelines were placed in service
in 2002.
Our 18 inch oil pipeline, Alpine, which became operational
in 2003, is our second western gulf crude oil pipeline. The
pipeline extends 96 miles from Garden Banks Block 668
in the central Gulf of Mexico to our
shallow-water
platform at Galveston Area Block A244. From this platform, the
oil is delivered onshore through ExxonMobil’s Hoover
Offshore Oil Pipeline System under a joint tariff agreement.
This production is coming from the Gunnison field, which is
located in 3,150 feet of water and operated by Anadarko.
Our Devils Tower floating production system and associated
pipelines were placed in service in 2004. Initially built to
serve the Devils Tower field, the floating production system is
located in Mississippi Canyon Block 773, approximately
150 miles south-southwest of Mobile, Alabama. During the
fourth quarter of 2005, the platform’s service expanded to
include tie-backs of production from the Triton and Goldfinger
fields in addition to the host Devils Tower field. Construction
is currently underway to add topside capacity for the recently
dedicated Bass Lite gas discovery. Full field production from
Bass Lite is expected mid-year 2008. Located in 5,610 feet
of water, it is the world’s deepest dry tree spar. The
platform, which is operated by ENI Petroleum on our behalf, is
capable of producing
60 MMcf/d
of natural gas and 60 Mbbls/d of oil.
The Devils Tower project includes gas and oil pipelines. The
139-mile
Canyon Chief gas pipeline consists of
18-inch
diameter pipe. The
155-mile
Mountaineer oil pipeline is a combination of 18- and
20-inch
diameter pipe. The gas is delivered into Transco’s
pipeline, and processed at our Mobile Bay plant to recover the
NGLs. The oil is transported to ChevronTexaco’s Empire
Terminal in Plaquemines Parish, Louisiana. These associated
pipelines are significantly oversized relative to the Devils
Tower spar top-side capacity.
We own a 10/12 interest in and are the operator for an ethane
cracker at Geismar, Louisiana, with a total production capacity
of 1.3 billion pounds per year of ethylene. In July 2007,
we exercised our right of first refusal to acquire BASF’s
5/12th ownership
interest in the Geismar olefins facility bringing our ownership
position up to the current 10/12 interest. We also own an ethane
pipeline system and a propylene splitter and its related
pipeline system in Louisiana.
Our Canadian operations include an olefin liquids extraction
plant located near Ft. McMurray, Alberta and an olefin
fractionation facility near Edmonton, Alberta. Our facilities
extract olefinic liquids from the off-gas produced from third
party oil sands bitumen upgrading and then fractionate, treat,
store, terminal and sell the propane, propylene, butane and
condensate recovered from this process. We continue to be the
only olefins fractionator in Western Canada and the only
treater-processor of oil sands upgrader off-gas. These
operations extract valuable
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petrochemical feedstocks from upgrader off-gas streams allowing
the upgraders to burn cleaner natural gas streams and reduce
overall air emissions. The extraction plant has processing
capacity in excess of
100 MMcf/d
with the ability to recover in excess of 15 Mbbls/d of
olefin and NGL products.
Our Venezuelan investments involve gas compression and gas
processing and natural gas liquids fractionation operations. We
own controlling interests and operate three gas compressor
facilities which provide roughly 70 percent of the gas
injections in eastern Venezuela. These facilities help stabilize
the reservoir and enhance the recovery of crude oil by
re-injecting natural gas at high pressures. We also own a
49.25 percent interest in two
400 MMcf/d
natural gas liquids extraction plants, a 50,000 barrels per
day natural gas liquids fractionation plant and associated
storage and refrigeration facilities.
We own interests in
and/or
operate NGL fractionation and storage assets. These assets
include two partially owned NGL fractionation facilities near
Conway, Kansas and Baton Rouge, Louisiana that have a combined
capacity in excess of 167,000 barrels per day. We also own
approximately 20 million barrels of NGL storage capacity in
central Kansas. Some of these assets are owned through our
interest in WPZ.
We also own a 14.6% interest in Aux Sable Liquid Products and
its Channahon, Illinois gas processing and NGL fractionation
facility near Chicago. The facility is capable of processing up
to 2.1 Bcf/d of natural gas from the Alliance Pipeline
system and fractionating approximately 87,000 barrels per
day of extracted liquids into NGL products.
WPZ was formed to engage in the business of gathering,
transporting and processing natural gas and fractionating and
storing NGLs. We currently own approximately a 21.6 percent
limited partnership interest and a 2 percent general
partner interest in WPZ. WPZ provides us with lower cost of
capital that is expected to enable growth of our Midstream
business. WPZ also creates a vehicle to monetize our qualifying
assets. Such transactions, which are subject to approval by the
boards of directors of both Williams and WPZ’s general
partner, allow us to retain control of the assets through our
ownership interest in WPZ.
WPZ’s asset portfolio at its initial public offering in
2005 consisted of a 40 percent interest in Discovery, the
Carbonate Trend gathering pipeline, three integrated NGL storage
facilities near Conway, Kansas and a 50 percent interest in
an NGL fractionator near Conway, Kansas.
During 2006, WPZ acquired Williams Four Corners, LLC which owns
a 3,500-mile natural gas gathering system in the San Juan
Basin in New Mexico and Colorado with capacity of nearly
2 Bcf/d; the Ignacio natural gas processing plant in
Colorado and the Kutz and Lybrook natural gas processing plants
in New Mexico, which have a combined processing capacity of
760 MMcf/d; and the Milagro and Esperanza natural gas
treating plants in New Mexico, which are designed to remove
carbon dioxide from up to 750 MMcf of natural gas per day.
In June 2007, WPZ acquired an additional 20 percent
interest in Discovery. WPZ now owns a 60 percent interest
in the Discovery gathering, transportation, processing and NGL
fractionation system, the remainder of which is owned by third
parties.
In December 2007, WPZ acquired certain ownership interests in
Wamsutter LLC from us for $750 million. Wamsutter LLC owns
a 1,700 mile natural gas gathering system in the Washakie
Basin in south-central Wyoming and the Echo Springs natural gas
processing plant in Sweetwater County, Wyoming.
Expansion
projects
During the first quarter of 2007, we completed construction at
our existing gas processing complex located near Opal, Wyoming,
to add a fifth cryogenic gas processing train capable of
processing up to 350 MMcf/d,
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bringing total Opal capacity to approximately 1.5 Bcf/d.
This plant expansion increased Opal’s processing capacity
by more than 30 percent and became operational during the
first quarter.
In the first quarter of 2007, we also announced plans to
construct and operate the Willow Creek facility a
450 MMcf/d natural gas processing plant in the Piceance
Basin of western Colorado, where Exploration and Production has
its most significant volume of natural gas production, reserves
and development activity. Exploration and Production’s
existing Piceance Basin processing plants are primarily designed
to condition the natural gas to meet quality specifications for
pipeline transmission, not to maximize the extraction of NGLs.
We expect the new Willow Creek facility to recover
25,000 barrels per day of NGLs at startup, which is
expected to be in the third quarter of 2009.
In December 2007, Midstream purchased the Parachute Lateral
system from Gas Pipeline. The system is a 37.6-mile expansion,
originally placed in service by Gas Pipelines in May 2007, and
provides capacity of 450 Mdt/d through a 30-inch diameter line,
transporting residue gas from the Piceance basin to the
Greasewood Hub in northwest Colorado. The Willow Creek facility
will straddle the Parachute Lateral pipeline and will process
gas flowing through the pipeline. In an arrangement approved by
the FERC, Midstream will lease the pipeline to Gas Pipeline, who
will continue to operate the pipeline until completion of a
planned FERC abandonment filing.
In addition, Midstream acquired an existing natural gas pipeline
from Gas Pipeline, and has begun the process of converting it
from natural gas to NGL service and constructing additional
pipeline to create a pipeline alternative for NGLs currently
being transported by truck from Exploration &
Production’s existing Piceance basin processing plants to a
major NGL transportation pipeline system.
In 2006, we entered into an agreement to develop new pipeline
capacity for transporting NGLs from production areas in
southwestern Wyoming to central Kansas. The other party to the
agreement reimbursed us for the development costs we had
incurred for the proposed pipeline and acquired 99 percent
of the pipeline, known as Overland Pass Pipeline Company, LLC.
We retained a 1 percent interest and have the option to
increase our ownership to 50 percent and become the
operator within two years of the pipeline becoming operational.
Start-up is
planned for mid-2008. Additionally, we have agreed to dedicate
our equity NGL volumes from our two Wyoming plants and the new
Willow Creek facility for transport under a long-term shipping
agreement. The terms represent significant savings compared with
the existing tariff and other alternatives considered.
The deepwater Gulf continues to be an attractive growth area for
our Midstream business. Since 1997, we have invested almost
$1.3 billion in new midstream assets in the Gulf of Mexico.
These facilities provide both onshore and offshore services
through pipelines, platforms and processing plants. The new
facilities could also attract incremental gas volumes to
Transco’s pipeline system in the southeastern United States.
During 2007, we have continued construction activities on the
Perdido Norte project which includes oil and gas lines that
would expand the scale of our existing infrastructure in the
western deepwater of the Gulf of Mexico. In addition, we
completed agreements with certain producers to provide
gathering, processing and transportation services over the life
of the reserves. We also intend to expand our onshore Markham
gas processing facility to adequately serve this new gas
production. The scale of the project has increased to include
additional pipeline and more efficient processing capacity and
is now estimated to cost approximately $560 million and to
be in service in the third quarter of 2009.
Chevron and Anadarko are dedicating to us the transport of
production from their current and future ownership in a defined
area surrounding the Blind Faith discovery in the deepwater Gulf
of Mexico. To accommodate production from the Blind Faith
acreage and the surrounding blocks, we have agreed to extend our
Canyon Chief and Mountaineer pipelines to the producer-owned
floating production facility. We expect to have the extensions
ready for service in the second quarter of 2008. The
approximately $250 million project will facilitate a
37-mile
extension of each pipeline. The agreement also creates
opportunities for us to move natural gas from the Blind Faith
discovery through our Mobile Bay, Alabama, processing plant and
our Transco and Gulfstream interstate pipeline systems.
Recovered NGLs from Blind Faith also could be fractionated at
our facilities in Baton Rouge or Paradis, Louisiana.
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Our domestic gas gathering and processing customers are
generally natural gas producers who have proved
and/or
producing natural gas fields in the areas surrounding our
infrastructure. During 2007, these operations gathered and
processed gas for approximately 215 gas gathering and processing
customers. Our top three gathering and processing customers
accounted for about 45 percent of our domestic gathering
and processing revenue. Our gathering and processing agreements
are generally long-term agreements.
In addition to our gathering and processing operations, we
market NGLs and petrochemical products to a wide range of users
in the energy and petrochemical industries. We provide these
products to third parties from the production at our domestic
facilities. The majority of domestic sales are based on supply
contracts of less than one year in duration. The production from
our Canadian facilities is marketed in Canada and in the United
States.
Our Venezuelan assets were constructed and are currently
operated for the exclusive benefit of Petróleos de
Venezuela S.A under long-term contracts. These significant
contracts have a remaining term between 10 and 14 years and
our revenues are based on a combination of fixed capital
payments, throughput volumes, and, in the case of one of the gas
compression facilities, a minimum throughput guarantee. The
Venezuelan government has continued its public criticism of
U.S. economic and political policy, has implemented
unilateral changes to existing energy related contracts, and
continues to publicly declare that additional energy contracts
will be unilaterally amended and privately held assets will be
expropriated, escalating our concern regarding political risk in
Venezuela.
The following table summarizes our significant operating
statistics for Midstream:
Gas Marketing Services primarily supports our natural gas
businesses by providing marketing and risk management services,
which include marketing and hedging the gas produced by
Exploration & Production, and procuring fuel and
shrink gas and hedging natural gas liquids sales for Midstream.
In addition, Gas Marketing manages various natural gas-related
contracts such as transportation, storage, and related hedges,
and provides services to third-parties, such as producers.
Gas Marketing Services’ natural gas sales volumes,
including sales volumes to other segments, were 2.3 Bcf/d, 2.1
Bcf/d and 2.1 Bcf/d for the years ending December 31, 2007,
2006 and 2005, respectively. Gas Marketing Services’
natural gas purchase volumes, including purchases from other
segments, were 2.4 Bcf/d, 2.3 Bcf/d and 2.2 Bcf/d for the same
periods.
As of December 31, 2007, Gas Marketing Services has
approximately 159 customers compared with approximately 163
customers at the end of 2006.
Our Exploration and Production and Midstream segments may
execute commodity hedges with Gas Marketing Services. In turn,
Gas Marketing Services may execute offsetting derivative
contracts with unrelated third parties.
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As a result of the sale of a substantial portion of our Power
business in the fourth quarter of 2007, Gas Marketing Services
also is responsible for certain remaining legacy natural gas
contracts and positions. We intend to liquidate a substantial
portion of these legacy contracts. During 2007, we substantially
reduced the overall legacy positions remaining. Until such
legacy positions are liquidated, segment results may experience
mark- to-market volatility from commodity-based derivatives that
represent economic hedges but are not designated as hedges for
accounting purposes or do not qualify for hedge accounting.
However, this
mark-to-market
volatility is expected to be significantly reduced compared to
previous levels.
At December 31, 2007, we owned approximately
99.3 percent of the Class B Interests in Longhorn
Partners Pipeline LP (Longhorn), which owned a refined petroleum
products pipeline from Houston, Texas to El Paso, Texas.
The Class B Interests are preferred interests but
subordinate to other preferred interests, and the common
interests are subordinate to both. It is uncertain whether we
will ever receive any payments related to our Class B
Interests or our common interests, however any such amounts
related to these interests were fully impaired in 2005, and will
only be recognized as income when received.
We continue to receive payments associated with the 2005
transfer of the First Amended and Restated Pipeline Operating
Services Agreement to a third party. The management of Longhorn
completed an installment sale of the pipeline during the third
quarter of 2006. The sale of the pipeline did not impact these
ongoing payments which are recognized as income when received.
Our ongoing business segments are accounted for as continuing
operations in the accompanying financial statements and notes to
financial statements included in Part II.
Operations related to certain assets in “Discontinued
Operations” have been reclassified from their traditional
business segment to “Discontinued Operations” in the
accompanying financial statements and notes to financial
statements included in Part II.
Our corporate parent company performs certain management, legal,
financial, tax, consultative, information technology,
administrative and other services for our subsidiaries.
Our corporate parent company’s principal sources of cash
are from external financings, dividends and advances from our
subsidiaries, investments, payments by subsidiaries for services
rendered, sales of master partnership units to the public,
interest payments from subsidiaries on cash advances and net
proceeds from asset sales. The amount of dividends available to
us from subsidiaries largely depends upon each subsidiary’s
earnings and operating capital requirements. The terms of
certain of our subsidiaries’ borrowing arrangements limit
the transfer of funds to our corporate parent.
We believe that we have adequate sources and availability of raw
materials and commodities for existing and anticipated business
needs. In support of our energy commodity activities, primarily
conducted through Gas Marketing Services, our counterparties
require us to provide various forms of credit support such as
margin, adequate assurance amounts and pre-payments for gas
supplies. Our pipeline systems are all regulated in various ways
resulting in the financial return on the investments made in the
systems being limited to standards permitted by the regulatory
agencies. Each of the pipeline systems has ongoing capital
requirements for efficiency and mandatory improvements, with
expansion opportunities also necessitating periodic capital
outlays.
Exploration & Production. Our
Exploration & Production business is subject to
various federal, state and local laws and regulations on
taxation and payment of royalties, and the development,
production and marketing of oil and gas, and environmental and
safety matters. Many laws and regulations require drilling
permits and govern the spacing of wells, rates of production,
water discharge, prevention of waste and other matters. Such
laws and regulations have increased the costs of planning,
designing, drilling, installing, operating and abandoning our
oil
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and gas wells and other facilities. In addition, these laws and
regulations, and any others that are passed by the jurisdictions
where we have production, could limit the total number of wells
drilled or the allowable production from successful wells, which
could limit our reserves.
Gas Pipeline. Gas Pipeline’s interstate
transmission and storage activities are subject to FERC
regulation under the Natural Gas Act of 1938 (NGA) and under the
Natural Gas Policy Act of 1978, and, as such, its rates and
charges for the transportation of natural gas in interstate
commerce, its accounting, and the extension, enlargement or
abandonment of its jurisdictional facilities, among other
things, are subject to regulation. Each gas pipeline company
holds certificates of public convenience and necessity issued by
the FERC authorizing ownership and operation of all pipelines,
facilities and properties for which certificates are required
under the NGA. Each gas pipeline company is also subject to the
Natural Gas Pipeline Safety Act of 1968, as amended, which
regulates safety requirements in the design, construction,
operation and maintenance of interstate natural gas transmission
facilities. FERC Standards of Conduct govern how our interstate
pipelines communicate and do business with their marketing
affiliates. Among other things, the Standards of Conduct require
that interstate pipelines not operate their systems to
preferentially benefit their marketing affiliates.
Each of our interstate natural gas pipeline companies
establishes its rates primarily through the FERC’s
ratemaking process. Key determinants in the ratemaking process
are:
The allowed rate of return is determined in each rate case. Rate
design and the allocation of costs between the demand and
commodity rates also impact profitability. As a result of these
proceedings, certain revenues previously collected may be
subject to refund.
Midstream. For our Midstream segment, onshore
gathering is subject to regulation by states in which we operate
and offshore gathering is subject to the Outer Continental Shelf
Lands Act (OCSLA). Of the states where Midstream gathers gas,
currently only Texas actively regulates gathering activities.
Texas regulates gathering primarily through complaint mechanisms
under which the state commission may resolve disputes involving
an individual gathering arrangement. Although gathering
facilities located offshore are not subject to the NGA (although
offshore transmission pipelines may be), some controversy exists
as to how the FERC should determine whether offshore facilities
function as gathering. These issues are currently before the
FERC. Most gathering facilities offshore are subject to the
OCSLA, which provides in part that outer continental shelf
pipelines “must provide open and nondiscriminatory access
to both owner and non-owner shippers.”
Midstream also owns interests in and operates two offshore
transmission pipelines that are regulated by the FERC because
they are deemed to transport gas in interstate commerce. Black
Marlin Pipeline Company provides transportation service for
offshore Texas production in the High Island area and redelivers
that gas to intrastate pipeline interconnects near Texas City.
Discovery provides transportation service for offshore Louisiana
production from the South Timbalier, Grand Isle, Ewing Bank and
Green Canyon (deepwater) areas to an onshore processing facility
and downstream interconnect points with major interstate
pipelines. FERC regulation requires all terms and conditions of
service, including the rates charged, to be filed with and
approved by the FERC before any changes can go into effect. In
2007, Black Marlin filed and settled a major rate change
application before the FERC resulting in increased rates for
service. In November 2007, Discovery filed a settlement in lieu
of a rate change filing that if approved would increase its
rates for service.
Our remaining Midstream Canadian assets are regulated by the
Alberta Energy & Utilities Board (AEUB) and Alberta
Environment. The regulatory system for the Alberta oil and gas
industry incorporates a large measure of self-regulation,
providing that licensed operators are held responsible for
ensuring that their operations are conducted in accordance with
all provincial regulatory requirements. For situations in which
non-compliance with the applicable regulations is at issue, the
AEUB and Alberta Environment have implemented an enforcement
process with escalating consequences.
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Gas Marketing Services. Our Gas Marketing
business is subject to a variety of laws and regulations at the
local, state and federal levels, including the FERC and the
Commodity Futures Trading Commission regulations. In addition,
natural gas markets continue to be subject to numerous and
wide-ranging federal and state regulatory proceedings and
investigations. We are also subject to various federal and state
actions and investigations regarding, among other things, market
structure, behavior of market participants, market prices, and
reporting to trade publications. We may be liable for refunds
and other damages and penalties as a result of ongoing actions
and investigations. The outcome of these matters could affect
our creditworthiness and ability to perform contractual
obligations as well as other market participants’
creditworthiness and ability to perform contractual obligations
to us.
See Note 15 of our Notes to Consolidated Financial
Statements for further details on our regulatory matters.
Our generation facilities, processing facilities, natural gas
pipelines, and exploration and production operations are subject
to federal environmental laws and regulations as well as the
state and tribal laws and regulations adopted by the
jurisdictions in which we operate. We could incur liability to
governments or third parties for any unlawful discharge of oil,
gas or other pollutants into the air, soil, or water, as well as
liability for clean up costs. Materials could be released into
the environment in several ways including, but not limited to:
Because the requirements imposed by environmental laws and
regulations are frequently changed, we cannot assure you that
laws and regulations enacted in the future, including changes to
existing laws and regulations, will not adversely affect our
business. In addition we may be liable for environmental damage
caused by former operators of our properties.
We believe compliance with environmental laws and regulations
will not have a material adverse effect on capital expenditures,
earnings or competitive position. However, environmental laws
and regulations could affect our business in various ways from
time to time, including incurring capital and maintenance
expenditures, fines and penalties, and creating the need to seek
relief from the FERC for rate increases to recover the costs of
certain capital expenditures and operation and maintenance
expenses.
For a discussion of specific environmental issues, see
“Environmental” under Management’s Discussion and
Analysis of Financial Condition and Results of Operations and
“Environmental Matters” in Note 15 of our Notes
to Consolidated Financial Statements.
Exploration & Production. Our
Exploration & Production segment competes with other
oil and gas concerns, including major and independent oil and
gas companies in the development, production and marketing of
natural gas. We compete in areas such as acquisition of oil and
gas properties and obtaining necessary equipment, supplies and
services. We also compete in recruiting and retaining skilled
employees.
Gas Pipeline. The natural gas industry has
undergone significant change over the past two decades. A
highly-liquid competitive commodity market in natural gas and
increasingly competitive markets for natural gas services,
including competitive secondary markets in pipeline capacity,
have developed. As a result, pipeline capacity is being used
more efficiently, and peaking and storage services are
increasingly effective substitutes for annual pipeline capacity.
Local distribution company (LDC) and electric industry
restructuring by states have affected pipeline markets. Pipeline
operators are increasingly challenged to accommodate the
flexibility demanded by customers and allowed
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under tariffs, but the changes implemented at the state level
have not required renegotiation of LDC contracts. The state
plans have in some cases discouraged LDCs from signing long-term
contracts for new capacity.
Several states are considering re-regulation and extending price
caps because many regulators and legislators believe that
deregulation has not worked. States are in the process of
developing new energy plans that may require utilities to
encourage energy saving measures and diversify their energy
supplies to include renewable sources. This could lower the
growth of gas demand.
These factors have increased the risk that customers will reduce
their contractual commitments for pipeline capacity. Future
utilization of pipeline capacity will also depend on competition
from LNG imported into markets and new pipelines from the
Rockies and other new producing areas, many of which are
utilizing master limited partnership structures with a lower
cost of capital, and on growth of natural gas demand.
Midstream. In our Midstream segment, we face
regional competition with varying competitive factors in each
basin. Our gathering and processing business competes with other
midstream companies, interstate and intrastate pipelines,
producers and independent gatherers and processors. We primarily
compete with five to ten companies across all basins in which we
provide services. Numerous factors impact any given
customer’s choice of a gathering or processing services
provider, including rate, location, term, timeliness of services
to be provided, pressure obligations and contract structure. We
also compete in recruiting and retaining skilled employees. In
2005 we formed WPZ to help compete against other master limited
partnerships for midstream projects. By virtue of the master
limited partnership structure, WPZ provides us with an
alternative and low-cost source of capital. We expect the
alternative, low-cost capital will allow WPZ to compete
favorably from a cost of capital perspective with other MLPs
when pursuing acquisition opportunities of gathering and
processing assets.
Gas Marketing Services. In our Gas Marketing
Services segment, we compete directly with large independent
energy marketers, marketing affiliates of regulated pipelines
and utilities, and natural gas producers. We also compete with
brokerage houses, energy hedge funds and other energy-based
companies offering similar services.
At February 1, 2008, we had approximately
4,319 full-time employees including 898 at the corporate
level, 681 at Exploration & Production, 1,732 at Gas
Pipeline, 984 at Midstream, and 24 at Gas Marketing Services.
None of our employees are represented by unions or covered by
collective bargaining agreements.
See Note 17 of our Notes to Consolidated Financial
Statements for amounts of revenues during the last three fiscal
years from external customers attributable to the United States
and all foreign countries. Also see Note 17 of our Notes to
Consolidated Financial Statements for information relating to
long-lived assets during the last three fiscal years, located in
the United States and all foreign countries.
Certain matters contained in this report include
“forward-looking statements” within the meaning of
section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as
amended. These statements discuss our expected future results
based on current and pending business operations. We make those
forward-looking statements in reliance on the safe harbor
protections provided under the Private Securities Litigation
Reform Act of 1995.
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All statements, other than statements of historical facts,
included in this report which address activities, events or
developments that we expect, believe or anticipate will exist or
may occur in the future, are forward-looking statements.
Forward-looking statements can be identified by various forms of
words such as “anticipates,” “believes,”
“could,” “may,” “should,”
“continues,” “estimates,”
“expects,” “forecasts,” “might,”
“planned,” “potential,”
“projects,” “scheduled” or similar
expressions. These forward-looking statements include, among
others, statements regarding:
Forward-looking statements are based on numerous assumptions,
uncertainties and risks that could cause future events or
results to be materially different from those stated or implied
in this document. Many of the factors that will determine these
results are beyond our ability to control or project. Specific
factors which could cause actual results to differ from those in
the forward-looking statements include:
Given the uncertainties and risk factors that could cause our
actual results to differ materially from those contained in any
forward-looking statement, we caution investors not to unduly
rely on our forward-looking statements. We disclaim any
obligations to and do not intend to update the above list to
announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or
developments.
In addition to causing our actual results to differ, the factors
listed above and referred to below may cause our intentions to
change from those statements of intention set forth in this
report. Such changes in our intentions may also cause our
results to differ. We may change our intentions, at any time and
without notice, based upon changes in such factors, our
assumptions, or otherwise.
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Because forward-looking statements involve risks and
uncertainties, we caution that there are important factors, in
addition to those listed above, that may cause actual results to
differ materially from those contained in the forward-looking
statements. These factors include the following:
You should carefully consider the following risk factors in
addition to the other information in this report. Each of these
factors could adversely affect our business, operating results,
and financial condition as well as adversely affect the value of
an investment in our securities.
Risks
Inherent to our Industry and Business
The
long-term financial condition of our natural gas transportation
and midstream businesses is dependent on the continued
availability of natural gas supplies in the supply basins that
we access, demand for those supplies in our traditional markets,
and market demand for natural gas.
The development of the additional natural gas reserves that are
essential for our gas transportation and midstream businesses to
thrive requires significant capital expenditures by others for
exploration and development drilling and the installation of
production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered
to our pipeline systems. Low prices for natural gas, regulatory
limitations, or the lack of available capital for these projects
could adversely affect the development and production of
additional reserves, as well as gathering, storage, pipeline
transportation and import and export of natural gas supplies,
adversely impacting our ability to fill the capacities of our
gathering, transportation and processing facilities.
Additionally, in some cases, new LNG import facilities built
near our markets could result in less demand for our gathering
and transportation facilities.
Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured
in an exact manner. Reserves that are “proved
reserves” are those estimated quantities of crude oil,
natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty are
recoverable in future years from known reservoirs under existing
economic and operating conditions, but should not be considered
as a guarantee of results for future drilling projects.
The process relies on interpretations of available geological,
geophysical, engineering and production data. There are numerous
uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing
of developmental expenditures, including many factors beyond the
control of the producer. The reserve data included in this
report represent estimates. In addition, the estimates of future
net revenues from our proved reserves and the present value of
such estimates are based upon certain assumptions about future
production levels, prices and costs that may not prove to be
correct over time.
Quantities of proved reserves are estimated based on economic
conditions in existence during the period of assessment. Changes
to oil and gas prices in the markets for such commodities may
have the impact of shortening the economic lives of certain
fields because it becomes uneconomic to produce all recoverable
reserves on such fields, which reduces proved property reserve
estimates.
If negative revisions in the estimated quantities of proved
reserves were to occur, it would have the effect of increasing
the rates of depreciation, depletion and amortization on the
affected properties, which would decrease earnings or result in
losses through higher depreciation, depletion and amortization
expense. The revisions may also be sufficient to trigger
impairment losses on certain properties which would result in a
further non-cash charge to earnings. The revisions could also
possibly affect the evaluation of Exploration &
Production’s goodwill for impairment purposes.
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Our past success rate for drilling projects in 2007 should not
be considered a predictor of future performance.
Performance of our exploration and production business is
affected in part by factors beyond our control (any of which
could cause the results of this business to decrease
materially), such as:
Our operations are subject to all the risks and hazards
typically associated with the development and exploration for,
and the production and transportation of oil and gas. These
operating risks include, but are not limited to:
In addition, there are inherent in our gas gathering, processing
and transporting properties a variety of hazards and operating
risks, such as leaks, spills, explosions and mechanical problems
that could cause substantial financial losses. In addition,
these risks could result in loss of human life, significant
damage to property, environmental pollution, impairment of our
operations and substantial losses to us. In accordance with
customary industry practice, we maintain insurance against some,
but not all, of these risks and losses, and only at levels we
believe to be appropriate. The location of certain segments of
our pipelines in or near populated areas, including residential
areas, commercial business centers and industrial sites, could
increase the level of damages resulting from these risks. In
spite of our precautions, an event could cause considerable harm
to people or property, and could have a material adverse effect
on our financial condition, particularly if the event is not
fully covered by insurance. Accidents or other operating risks
could further result in loss of service available to our
customers. Such circumstances could materially impact our
ability to meet contractual obligations and retain customers,
with a resulting impact on our results of operations.
Our operations are subject to extensive environmental regulation
pursuant to a variety of federal, provincial, state and
municipal laws and regulations. Such laws and regulations
impose, among other things, restrictions, liabilities and
obligations in connection with the generation, handling, use,
storage, extraction, transportation, treatment and disposal of
hazardous substances and wastes, in connection with spills,
releases and emissions of
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various substances into the environment, and in connection with
the operation, maintenance, abandonment and reclamation of our
facilities.
Compliance with environmental laws requires significant
expenditures, including for clean up costs and damages arising
out of contaminated properties. In addition, the possible
failure to comply with environmental laws and regulations might
result in the imposition of fines and penalties. We are
generally responsible for all liabilities associated with the
environmental condition of our facilities and assets, whether
acquired or developed, regardless of when the liabilities arose
and whether they are known or unknown. In connection with
certain acquisitions and divestitures, we could acquire, or be
required to provide indemnification against, environmental
liabilities that could expose us to material losses, which may
not be covered by insurance. In addition, the steps we could be
required to take to bring certain facilities into compliance
could be prohibitively expensive, and we might be required to
shut down, divest or alter the operation of those facilities,
which might cause us to incur losses. Although we do not expect
that the costs of complying with current environmental laws will
have a material adverse effect on our financial condition or
results of operations, no assurance can be given that the costs
of complying with environmental laws in the future will not have
such an effect.
Changes in federal laws or regulations could reduce the
availability or increase the cost of our interstate pipeline
capacity or gas supply, and thereby reduce our earnings.
Congress and certain states have for some time been considering
various forms of legislation related to greenhouse gas
emissions. There is a possibility that, when and if enacted, the
final form of such legislation could increase our costs of
compliance with environmental laws.
We make assumptions and develop expectations about possible
expenditures related to environmental conditions based on
current laws and regulations and current interpretations of
those laws and regulations. If the interpretation of laws or
regulations, or the laws and regulations themselves, change, our
assumptions may change. Our regulatory rate structure and our
contracts with customers might not necessarily allow us to
recover capital costs we incur to comply with the new
environmental regulations. Also, we might not be able to obtain
or maintain from time to time all required environmental
regulatory approvals for certain development projects. If there
is a delay in obtaining any required environmental regulatory
approvals or if we fail to obtain and comply with them, the
operation of our facilities could be prevented or become subject
to additional costs, resulting in potentially material adverse
consequences to our results of operations.
Revenues from certain segments of our business can have seasonal
characteristics. In many parts of the country, demand for
natural gas and other fuels peaks during the winter. As a
result, our overall operating results in the future might
fluctuate substantially on a seasonal basis. Demand for natural
gas and other fuels could vary significantly from our
expectations depending on the nature and location of our
facilities and pipeline systems and the terms of our natural gas
transportation arrangements relative to demand created by
unusual weather patterns. Additionally, changes in the price of
natural gas could benefit one of our business units, but
disadvantage another. For example, our Exploration &
Production business may benefit from higher natural gas prices,
and Midstream, which uses gas as a feedstock, may not.
Our
investments and projects located outside of the United States
expose us to risks related to the laws of other countries, and
the taxes, economic conditions, fluctuations in currency rates,
political conditions and policies of foreign governments. These
risks might delay or reduce our realization of value from our
international projects.
We currently own and might acquire
and/or
dispose of material energy-related investments and projects
outside the United States. The economic and political conditions
in certain countries where we have interests or in which we
might explore development, acquisition or investment
opportunities present risks of delays in construction and
interruption of business, as well as risks of war,
expropriation, nationalization, renegotiation, trade sanctions
or nullification of existing contracts and changes in law or tax
policy, that are greater than in the United States. The
uncertainty of the legal environment in certain foreign
countries in which we develop or acquire
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projects or make investments could make it more difficult to
obtain non-recourse project financing or other financing on
suitable terms, could adversely affect the ability of certain
customers to honor their obligations with respect to such
projects or investments and could impair our ability to enforce
our rights under agreements relating to such projects or
investments. Recent events in certain South American countries,
particularly the continued threat of nationalization of certain
energy-related assets in Venezuela, could have a material
negative impact on our results of operations. We may not receive
adequate compensation, or any compensation, if our assets in
Venezuela are nationalized.
Operations and investments in foreign countries also can present
currency exchange rate and convertibility, inflation and
repatriation risk. In certain situations under which we develop
or acquire projects or make investments, economic and monetary
conditions and other factors could affect our ability to convert
to U.S. dollars our earnings denominated in foreign
currencies. In addition, risk from fluctuations in currency
exchange rates can arise when our foreign subsidiaries expend or
borrow funds in one type of currency, but receive revenue in
another. In such cases, an adverse change in exchange rates can
reduce our ability to meet expenses, including debt service
obligations. We may or may not put contracts in place designed
to mitigate our foreign currency exchange risks. We have some
exposures that are not hedged and which could result in losses
or volatility in our results of operations.
Certain of our debt agreements contain covenants that restrict
or limit among other things, our ability to create liens, sell
assets, make certain distributions, repurchase equity and incur
additional debt. In addition, our debt agreements contain, and
those we enter into in the future may contain, financial
covenants and other limitations with which we will need to
comply. Our ability to comply with these covenants may be
affected by many events beyond our control, and we cannot assure
you that our future operating results will be sufficient to
comply with the covenants or, in the event of a default under
any of our debt agreements, to remedy that default.
Our failure to comply with the covenants in our debt agreements
and other related transactional documents could result in events
of default. Upon the occurrence of such an event of default, the
lenders could elect to declare all amounts outstanding under a
particular facility to be immediately due and payable and
terminate all commitments, if any, to extend further credit. An
event of default or an acceleration under one debt agreement
could cause a cross-default or cross-acceleration of another
debt agreement. Such a cross-default or cross-acceleration could
have a wider impact on our liquidity than might otherwise arise
from a default or acceleration of a single debt instrument. If
an event of default occurs, or if other debt agreements
cross-default, and the lenders under the affected debt
agreements accelerate the maturity of any loans or other debt
outstanding to us, we may not have sufficient liquidity to repay
amounts outstanding under such debt agreements.
A downgrade of our credit rating might increase our cost of
borrowing. Our ability to access capital markets could also be
limited by a downgrade of our credit rating and other
disruptions. Such disruptions could include:
Credit rating agencies perform independent analysis when
assigning credit ratings. Given the significant changes in
capital markets and the energy industry over the last few years,
credit rating agencies continue to review the criteria for
attaining investment grade ratings and make changes to those
criteria from time to time. Our corporate family credit rating
and the credit ratings of Transco and Northwest Pipeline were
raised to investment
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grade in 2007 by Standard & Poor’s, Moody’s
Corporation, and Fitch Ratings, Ltd., and our senior unsecured
debt ratings were raised to investment grade by Moody’s and
Fitch. No assurance can be given that the credit rating agencies
will assign us investment grade ratings even if we meet or
exceed their criteria for investment grade ratios or that our
senior unsecured debt rating will be raised to investment grade
by all of the credit rating agencies.
Our revenues, operating results, future rate of growth and the
value of certain segments of our businesses depend primarily
upon the prices we receive for natural gas liquids, natural gas,
or other commodities, and the differences between prices of
these commodities. Prices also affect the amount of cash flow
available for capital expenditures and our ability to borrow
money or raise additional capital.
The markets for natural gas liquids, natural gas and other
commodities are likely to continue to be volatile. Wide
fluctuations in prices might result from relatively minor
changes in the supply of and demand for these commodities,
market uncertainty and other factors that are beyond our
control, including:
Our portfolio of derivative and other energy contracts consists
of wholesale contracts to buy and sell commodities, including
contracts for natural gas, natural gas liquids and other
commodities that are settled by the delivery of the commodity or
cash throughout the United States. If the values of these
contracts change in a direction or manner that we do not
anticipate or cannot manage, it could negatively affect our
results of operations. In the past, certain marketing and
trading companies have experienced severe financial problems due
to price volatility in the energy commodity markets. In certain
instances this volatility has caused companies to be unable to
deliver energy commodities that they had guaranteed under
contract. If such a delivery failure were to occur in one of our
contracts, we might incur additional losses to the extent of
amounts, if any, already paid to, or received from,
counterparties. In addition, in our businesses, we often extend
credit to our counterparties. Despite performing credit analysis
prior to extending credit, we are exposed to the risk that we
might not be able to collect amounts
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owed to us. If the counterparty to such a transaction fails to
perform and any collateral that secures our counterparty’s
obligation is inadequate, we will suffer a loss.
If we are unable to perform under our energy agreements, we
could be required to pay damages. These damages generally would
be based on the difference between the market price to acquire
replacement energy or energy services and the relevant contract
price. Depending on price volatility in the wholesale energy
markets, such damages could be significant.
Our interstate natural gas sales, transportation, and storage
operations conducted through our Gas Pipelines business are
subject to the FERC’s rules and regulations in accordance
with the Natural Gas Act of 1938 and the Natural Gas Policy Act
of 1978. The FERC’s regulatory authority extends to:
Regulatory actions in these areas can affect our business in
many ways, including decreasing tariff rates and revenues,
decreasing volumes in our pipelines, increasing our costs and
otherwise altering the profitability of our business. Regulatory
decisions could also affect our costs for compression,
processing and dehydration of natural gas, which could have a
negative effect on our results of operations.
The FERC has taken certain actions to strengthen market forces
in the natural gas pipeline industry that have led to increased
competition throughout the industry. In a number of key markets,
interstate pipelines are now facing competitive pressure from
other major pipeline systems, enabling local distribution
companies and end users to choose a transportation provider
based on considerations other than location.
We have numerous competitors in all aspects of our businesses,
and additional competitors may enter our markets. Other
companies with which we compete may be able to respond more
quickly to new laws or regulations or emerging technologies, or
to devote greater resources to the construction, expansion or
refurbishment of their facilities than we can. In addition,
current or potential competitors may make strategic acquisitions
or have greater financial resources than we do, which could
affect our ability to make investments or acquisitions. There
can be no assurance that we will be able to compete successfully
against current and future competitors and any failure to do so
could have a material adverse effect on our businesses and
results of operations.
A substantial portion of the operating revenues of our Gas
Pipelines are generated through firm transportation agreements
that expire periodically and must be renegotiated and extended
or replaced. We cannot give any assurance as to whether any of
these agreements will be extended or replaced or that the terms
of any renegotiated agreements will be as favorable as the
existing agreements. Upon the expiration of these agreements,
should customers turn back or substantially reduce their
commitments, we could experience a negative effect to our
results of operations.
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We depend on transportation and distribution facilities owned
and operated by utilities and other energy companies to deliver
the commodities we buy and sell in the wholesale market. If
transportation is disrupted, if capacity is inadequate, or if
credit requirements or rates of such utilities or energy
companies are increased, our ability to sell and deliver
products might be hindered. Further, although there are laws and
regulations designed to encourage competition in wholesale
market transactions, some companies may fail to provide fair and
equal access to their transportation systems or may not provide
sufficient transportation capacity for other market participants.
Existing regulations might be revised or reinterpreted, new laws
and regulations might be adopted or become applicable to us, our
facilities or our customers, and future changes in laws and
regulations might have a detrimental effect on our business.
Over the past few years, certain restructured energy markets
have experienced supply problems and price volatility. In some
of these markets, proposals have been made by governmental
agencies and other interested parties to re-regulate areas of
these markets which have previously been deregulated. Various
forms of market controls and limitations including price caps
and bid caps have already been implemented and new controls and
market restructuring proposals are in various stages of
development, consideration and implementation. We cannot assure
you that changes in market structure and regulation will not
adversely affect our business and results of operations. We also
cannot assure you that other proposals to re-regulate will not
be made or that legislative or other attention to these
restructured energy markets will not cause the deregulation
process to be delayed or reversed or otherwise adversely affect
our business and results of operations.
We have a pending rate case with the FERC to request changes to
the rates we charge on Transco. We have sought FERC approval of
a settlement of the significant issues in the rate case but
until FERC approves the settlement, the outcome of the rate case
remains uncertain. There is a risk that rates set by the FERC
will lower our return on the capital we have invested in our
assets or might not be adequate to recover increases in
operating costs. There is also the risk that higher rates will
cause our customers to look for alternative ways to transport
their natural gas.
Public and regulatory scrutiny of the energy industry and of the
capital markets has resulted in increased regulation being
either proposed or implemented. Such scrutiny has also resulted
in various inquiries, investigations and court proceedings in
which we are a named defendant. Both the shippers on our
pipelines and regulators have rights to challenge the rates we
charge under certain circumstances. Any successful challenge
could materially affect our results of operations.
Certain inquiries, investigations and court proceedings are
ongoing and continue to adversely affect our business as a
whole. We might see these adverse effects continue as a result
of the uncertainty of these ongoing inquiries and proceedings,
or additional inquiries and proceedings by federal or state
regulatory agencies or private plaintiffs. In addition, we
cannot predict the outcome of any of these inquiries or whether
these inquiries will lead to additional legal proceedings
against us, civil or criminal fines or penalties, or other
regulatory action, including legislation, which might be
materially adverse to the operation of our business and our
revenues and net income or increase our operating costs in other
ways. Current legal proceedings or other matters against us
arising out of our ongoing and discontinued operations including
environmental matters, disputes over gas measurement, royalty
payments, shareholder class action suits, regulatory appeals and
similar matters might result in adverse decisions
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against us. The result of such adverse decisions, either
individually or in the aggregate, could be material and may not
be covered fully or at all by insurance.
Regulators and legislators continue to take a renewed look at
accounting practices, financial disclosures, companies’
relationships with their independent registered public
accounting firms, and retirement plan practices. We cannot
predict the ultimate impact of any future changes in accounting
regulations or practices in general with respect to public
companies or the energy industry or in our operations
specifically.
In addition, the Financial Accounting Standards Board (FASB) or
the SEC could enact new accounting standards that might impact
how we are required to record revenues, expenses, assets,
liabilities and equity.
Although we have systems in place that use various methodologies
to quantify commodity price risk associated with our businesses,
these systems might not always be followed or might not always
be effective. Further, such systems do not in themselves manage
risk, particularly risks outside of our control, and adverse
changes in energy commodity market prices, volatility, adverse
correlation of commodity prices, the liquidity of markets,
changes in interest rates and other risks discussed in this
report might still adversely affect our earnings, cash flows and
balance sheet under applicable accounting rules, even if risks
have been identified.
In an effort to manage our financial exposure related to
commodity price and market fluctuations, we have entered into
contracts to hedge certain risks associated with our assets and
operations. In these hedging activities, we have used
fixed-price, forward, physical purchase and sales contracts,
futures, financial swaps and option contracts traded in the
over-the-counter markets or on exchanges. Nevertheless, no
single hedging arrangement can adequately address all risks
present in a given contract. For example, a forward contract
that would be effective in hedging commodity price volatility
risks would not hedge the contract’s counterparty credit or
performance risk. Therefore, unhedged risks will always continue
to exist. While we attempt to manage counterparty credit risk
within guidelines established by our credit policy, we may not
be able to successfully manage all credit risk and as such,
future cash flows and results of operations could be impacted by
counterparty default.
Our use of hedging arrangements through which we attempt to
reduce the economic risk of our participation in commodity
markets could result in increased volatility of our reported
results. Changes in the fair values (gains and losses) of
derivatives that qualify as hedges under SFAS No. 133,
“Accounting for Derivative Instruments and Hedging
Activities,” (SFAS 133) to the extent that such
hedges are not fully effective in offsetting changes to the
value of the hedged commodity, as well as changes in the fair
value of derivatives that do not qualify or have not been
designated as hedges under SFAS 133, must be recorded in
our income. This creates the risk of volatility in earnings even
if no economic impact to the Company has occurred during the
applicable period.
The impact of changes in market prices for natural gas on the
average gas prices received by us may be reduced based on the
level of our hedging strategies. These hedging arrangements may
limit our potential gains if the market prices for natural gas
were to rise substantially over the price established by the
hedge. In addition, our hedging arrangements expose us to the
risk of financial loss in certain circumstances, including
instances in which:
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In certain segments of our business, institutional knowledge
resides with employees who have many years of service. As these
employees reach retirement age, we may not be able to replace
them with employees of comparable knowledge and experience. In
addition, we may not be able to retain or recruit other
qualified individuals and our efforts at knowledge transfer
could be inadequate. If knowledge transfer, recruiting and
retention efforts are inadequate, access to significant amounts
of internal historical knowledge and expertise could become
unavailable to us.
Some studies indicate a high failure rate of outsourcing
relationships. Although we have taken steps to build a
cooperative and mutually beneficial relationship with our
outsourcing providers and to closely monitor their performance,
a deterioration in the timeliness or quality of the services
performed by the outsourcing providers or a failure of all or
part of these relationships could lead to loss of institutional
knowledge and interruption of services necessary for us to be
able to conduct our business.
Certain of our accounting, information technology, application
development, and help desk services are currently provided by an
outsourcing provider from service centers outside of the United
States. The economic and political conditions in certain
countries from which our outsourcing providers may provide
services to us present similar risks of business operations
located outside of the United States previously discussed,
including risks of interruption of business, war, expropriation,
nationalization, renegotiation, trade sanctions or nullification
of existing contracts and changes in law or tax policy, that are
greater than in the United States.
Our assets and operations, including those located offshore, can
be adversely affected by hurricanes, earthquakes, tornadoes and
other natural phenomena and weather conditions including extreme
temperatures, making it more difficult for us to realize the
historic rates of return associated with these assets and
operations.
Our assets and the assets of our customers and others may be
targets of terrorist activities that could disrupt our business
or cause significant harm to our operations, such as full or
partial disruption to our ability to produce, process, transport
or distribute natural gas, natural gas liquids or other
commodities. Acts of terrorism as well as events occurring in
response to or in connection with acts of terrorism could cause
environmental repercussions that could result in a significant
decrease in revenues or significant reconstruction or
remediation costs, which could have a material adverse effect on
our financial condition, results of operations and cash flows.
None.
We own property in 30 states plus the District of Columbia
in the United States and in Argentina, Canada and Venezuela.
Gas Marketing’s primary assets are its term contracts,
related systems and technological support. In our Gas Pipeline
and Midstream segments, we generally own our facilities,
although a substantial portion of our pipeline and gathering
facilities is constructed and maintained pursuant to
rights-of-way, easements, permits, licenses or
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consents on and across properties owned by others. In our
Exploration & Production segment, the majority of our
ownership interest in exploration and production properties is
held as working interests in oil and gas leaseholds.
The information called for by this item is provided in
Note 15 of the Notes to Consolidated Financial Statements
of this report, which information is incorporated by reference
into this item.
None.
The name, age, period of service, and title of each of our
executive officers as of February 21, 2008, are listed
below.
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Our common stock is listed on the New York Stock Exchange under
the symbol “WMB.” At the close of business on
February 21, 2008, we had approximately 11,153 holders of
record of our common stock. The high and low closing sales price
ranges (New York Stock Exchange composite transactions) and
dividends declared by quarter for each of the past two years are
as follows:
Some of our subsidiaries’ borrowing arrangements limit the
transfer of funds to us. These terms have not impeded, nor are
they expected to impede, our ability to pay dividends.
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Set forth below is a line graph comparing our cumulative total
stockholder return on our common stock (assuming reinvestment of
dividends) with the cumulative total return of the S&P 500
Stock Index and the Bloomberg U.S. Pipeline Index for the
period of five fiscal years commencing January 1, 2003. The
Bloomberg U.S. Pipeline Index is composed of El Paso,
Equitable Resources, Questar, Oneok, TransCanada, Spectra
Energy, Enbridge and Williams. The graph below assumes an
investment of $100 at the beginning of the period.
Cumulative
Total Shareholder Return
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The following financial data should be read in conjunction 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.
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We are primarily a natural gas company, engaged in finding,
producing, gathering, processing, and transporting natural gas.
Our operations are located principally in the United States and
are organized into the following reporting segments:
Exploration & Production, Gas Pipeline, Midstream
Gas & Liquids (Midstream), and Gas Marketing Services.
(See Note 1 of Notes to Consolidated Financial Statements
for further discussion of reporting segments.)
Unless indicated otherwise, the following discussion of critical
accounting estimates, discussion and analysis of results of
operations and financial condition and liquidity relates to our
current continuing operations and should be read in conjunction
with the consolidated financial statements and notes thereto
included in Part II Item 8 of this document.
Our plan for 2007 was focused on continued disciplined growth.
Objectives and highlights of this plan included:
Our 2007 income from continuing operations increased to
$847 million, as compared to $347 million in 2006. Our
net cash provided by operating activities was
$2.2 billion in 2007 compared to $1.9 billion in 2006.
These comparative results reflect:
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Natural gas prices in the Rocky Mountain areas (Rockies) trended
lower throughout 2007 due to strong drilling activities
increasing third-party supplies while constrained by limited
pipeline capacity. This trend has benefited Midstream as the
lower regional gas prices contributed to increased NGL margins
in the West region. Exploration & Production utilizes
firm transportation contracts, which allow a substantial portion
of their Rockies production to be sold at more advantageous
market points, and basin-level collars and fixed-price hedges to
reduce exposure to this trend.
See additional discussion in Results of Operations.
During third-quarter 2007, we formed Williams Pipeline Partners
L.P. (WMZ) to own and operate natural gas transportation and
storage assets. In January 2008, WMZ completed its initial
public offering of 16.25 million common units at a price of
$20.00 per unit. In February 2008, the underwriters also
exercised their right to purchase an additional
1.65 million common units at the same price. A subsidiary
of ours serves as the general partner of WMZ. The initial asset
of the partnership is a 35 percent interest in Northwest
Pipeline GP, formerly Northwest Pipeline Corporation. Upon
completion of the transaction, we hold approximately
47.7 percent of the interests in WMZ, including the
interests of the general partner.
In December 2007, Williams Partners L.P. acquired certain of our
membership interests in Wamsutter LLC, the limited liability
company that owns the Wamsutter system, from us for
$750 million. Williams Partners L.P. completed the
transaction after successfully closing a public equity offering
of 9.25 million common units that yielded net proceeds of
approximately $335 million. The partnership financed the
remainder of the purchase price primarily through utilizing
$250 million of term loan borrowings and issuing
approximately $157 million of common units to us. Since
Williams Partners L.P. is consolidated within our consolidated
financial statements, the debt and equity issued by Williams
Partners L.P. is reported as a component of our consolidated
debt balance and minority interest balance, respectively. (See
Note 1 of Notes to Consolidated Financial Statements.)
In December 2007, we repurchased $213 million of
7.125 percent notes due September 2011 and $22 million
of 8.125 percent notes due March 2012. In conjunction with
these early retirements, we paid premiums of approximately
$19 million. These premiums, as well as related fees and
expenses are recorded as early debt retirement costs in
the Consolidated Statement of Income.
On November 9, 2007, we closed on the sale of substantially
all of our power business to Bear Energy, LP, a unit of The Bear
Stearns Companies, Inc., for $496 million, subject to
post-closing adjustments. The assets sold included tolling
contracts, full requirements contracts, tolling resales, heat
rate options, related hedges and other related assets including
certain property and software. This sale reduces the risk and
complexity of our overall business model.
In November 2007, our credit ratings were raised to investment
grade based on improvements in our credit outlook. As we
continue to invest and grow our natural gas businesses, our
improved credit rating is expected to provide greater access to
capital and more favorable loan terms. See additional discussion
of credit ratings in Management’s Discussion and
Analysis of Financial Condition.
On November 28, 2007, Transco filed a formal stipulation
and agreement with the FERC resolving all substantive issues in
Transco’s pending 2006 rate case. Final resolution of the
rate case is subject to approval by the FERC.
In July 2007, our Board of Directors authorized the repurchase
of up to $1 billion of our common stock. We intend to
purchase shares of our stock from time to time in open-market
transactions or through privately negotiated
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or structured transactions at our discretion, subject to market
conditions and other factors. This stock-repurchase program does
not have an expiration date. During 2007, we repurchased
approximately 16 million shares for $526 million at an
average cost of $33.08 per share. We are funding this program
with cash on hand.
In April 2007, our Board of Directors approved a regular
quarterly dividend of 10 cents per share, which reflected an
increase of 11 percent compared to the 9 cents per share
that we paid in each of the four prior quarters and marked the
fourth increase in our dividend since late 2004.
On March 30, 2007, the FERC approved the stipulation and
settlement agreement with respect to the rate case for Northwest
Pipeline. The settlement establishes an increase in general
system firm transportation rates on Northwest Pipeline’s
system from $0.30760 to $0.40984 per Dth (dekatherm), effective
January 1, 2007.
Our plan for 2008 is focused on continued disciplined growth.
Objectives of this plan include:
Potential risks
and/or
obstacles that could prevent us from achieving these objectives
include:
We continue to address these risks through utilization of
commodity hedging strategies, focused efforts to resolve
regulatory issues and litigation claims, disciplined investment
strategies, and maintaining our desired level of at least
$1 billion in liquidity from cash and cash equivalents and
unused revolving credit facilities.
Accounting standards that have been issued and are not yet
effective may have an effect on our Consolidated Financial
Statements in the future. These include:
See Recent Accounting Standards in Note 1 of Notes
to Consolidated Financial Statements for further information on
these and other recently issued accounting standards.
Critical
Accounting Estimates
The preparation of financial statements, in conformity with
generally accepted accounting principles, requires management to
make estimates and assumptions that affect the reported amounts
therein. We have discussed the
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following accounting estimates and assumptions as well as
related disclosures with our Audit Committee. We believe that
the nature of these estimates and assumptions is material due to
the subjectivity and judgment necessary, or the susceptibility
of such matters to change, and the impact of these on our
financial condition or results of operations.
We hold a portfolio of energy trading and nontrading contracts.
We review these contracts to determine whether they are
nonderivatives or derivatives. If they are derivatives, we
further assess whether the contracts qualify for either cash
flow hedge accounting or the normal purchases and normal sales
exception.
The determination of whether a derivative contract qualifies as
a cash flow hedge includes an analysis of historical market
price information to assess whether the derivative is expected
to be highly effective in achieving offsetting cash flows
attributed to the hedged risk. We also assess whether the hedged
forecasted transaction is probable of occurring. This assessment
requires us to exercise judgment and consider a wide variety of
factors in addition to our intent, including internal and
external forecasts, historical experience, changing market and
business conditions, our financial and operational ability to
carry out the forecasted transaction, the length of time until
the forecasted transaction is projected to occur, and the
quantity of the forecasted transaction. In addition, we compare
actual cash flows to those that were expected from the
underlying risk. If a hedged forecasted transaction is not
probable of occurring, or if the derivative contract is not
expected to be highly effective, the derivative does not qualify
for hedge accounting.
For derivatives that are designated as cash flow hedges, we do
not reflect the effective portion of changes in their fair value
in earnings until the associated hedged item affects earnings.
For those that have not been designated as hedges or do not
qualify for hedge accounting, we recognize the net change in
their fair value in income currently (marked to market).
For derivatives that are designated as cash flow hedges, we
prospectively discontinue hedge accounting and recognize future
changes in fair value directly in earnings if we no longer
expect the hedge to be highly effective, or if we believe that
the hedged forecasted transaction is no longer probable of
occurring. If the forecasted transaction becomes probable of not
occurring, we reclass amounts previously recorded in other
comprehensive income into earnings in addition to prospectively
discontinuing hedge accounting. If the effectiveness of the
derivative improves and is again expected to be highly effective
in offsetting cash flows attributed to the hedged risk, or if
the forecasted transaction again becomes probable, we may
prospectively re-designate the derivative as a hedge of the
underlying risk.
Derivatives for which the normal purchases and normal sales
exception has been elected are accounted for on an accrual
basis. In determining whether a derivative is eligible for this
exception, we assess whether the contract provides for the
purchase or sale of a commodity that will be physically
delivered in quantities expected to be used or sold over a
reasonable period in the normal course of business. In making
this assessment, we consider numerous factors, including the
quantities provided under the contract in relation to our
business needs, delivery locations per the contract in relation
to our operating locations, duration of time between entering
the contract and delivery, past trends and expected future
demand, and our past practices and customs with regard to such
contracts. Additionally, we assess whether it is probable that
the contract will result in physical delivery of the commodity
and not net financial settlement.
The fair value of derivative contracts is determined based on
the nature of the transaction and the market in which
transactions are executed. We also incorporate assumptions and
judgments about counterparty performance and credit
considerations in our determination of their fair value.
Contracts are executed in the following environments:
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The number of transactions executed without quoted market prices
is limited. We estimate the fair value of these contracts by
using readily available price quotes in similar markets and
other market analyses. The fair value of all derivative
contracts is continually subject to change as the underlying
commodity market changes and our assumptions and judgments
change.
Additional discussion of the accounting for energy contracts at
fair value is included in Energy Trading Activities within
Item 7 and Note 1 of Notes to Consolidated Financial
Statements.
We use the successful efforts method of accounting for our oil-
and gas-producing activities. Estimated natural gas and oil
reserves and forward market prices for oil and gas are a
significant part of our financial calculations. Following are
examples of how these estimates affect financial results:
The process of estimating natural gas and oil reserves is very
complex, requiring significant judgment in the evaluation of all
available geological, geophysical, engineering, and economic
data. After being estimated internally, 99 percent of our
reserve estimates are either audited or prepared by independent
experts. (See Part I Item 1 for further discussion.)
The data may change substantially over time as a result of
numerous factors, including additional development activity,
evolving production history, and a continual reassessment of the
viability of production under changing economic conditions. As a
result, material revisions to existing reserve estimates could
occur from time to time. A revision of our reserve estimates
within reasonably likely parameters is not expected to result in
an impairment of our oil and gas properties or goodwill.
However, reserve estimate revisions would impact our
depreciation and depletion expense prospectively. For example, a
change of approximately 10 percent in oil and gas reserves
for each basin would change our annual depreciation,
depletion and amortization expense between approximately
$33 million and $41 million. The actual impact would
depend on the specific basins impacted and whether the change
resulted from proved developed, proved undeveloped or a
combination of these reserve categories.
Forward market prices, which are utilized in our impairment
analyses, include estimates of prices for periods that extend
beyond those with quoted market prices. This forward market
price information is consistent with that generally used in
evaluating our drilling decisions and acquisition plans. These
market prices for future periods impact the production economics
underlying oil and gas reserve estimates. The prices of natural
gas and oil are volatile and change from period to period, thus
impacting our estimates. An unfavorable change in the forward
price curve within reasonably likely parameters is not expected
to result in an impairment of our oil and gas properties or
goodwill.
We record liabilities for estimated loss contingencies,
including environmental matters, when we assess that a loss is
probable and the amount of the loss can be reasonably estimated.
Revisions to contingent liabilities are generally reflected in
income in the period in which new or different facts or
information become known or circumstances change that affect the
previous assumptions with respect to the likelihood or amount of
loss. Liabilities for contingent losses are based upon our
assumptions and estimates and upon advice of legal counsel,
engineers, or other third parties regarding the probable
outcomes of the matter. As new developments occur or more
information becomes available, our assumptions and estimates of
these liabilities may change. Changes in our assumptions and
estimates or outcomes different from our current assumptions and
estimates could materially affect future results of operations
for any particular quarterly or annual period. See Note 15
of Notes to Consolidated Financial Statements.
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We have deferred tax assets resulting from certain investments
and businesses that have a tax basis in excess of the book basis
and from tax carry-forwards generated in the current and prior
years. We must evaluate whether we will ultimately realize these
tax benefits and establish a valuation allowance for those that
may not be realizable. This evaluation considers tax planning
strategies, including assumptions about the availability and
character of future taxable income. At December 31, 2007,
we have $717 million of deferred tax assets for which a
$57 million valuation allowance has been established. When
assessing the need for a valuation allowance, we considered
forecasts of future company performance, the estimated impact of
potential asset dispositions and our ability and intent to
execute tax planning strategies to utilize tax carryovers. We do
not expect to be able to utilize $57 million of foreign
deferred tax assets primarily related to carryovers. The
ultimate amount of deferred tax assets realized could be
materially different from those recorded, as influenced by
potential changes in jurisdictional income tax laws and the
circumstances surrounding the actual realization of related tax
assets.
We regularly face challenges from domestic and foreign tax
authorities regarding the amount of taxes due. These challenges
include questions regarding the timing and amount of deductions
and the allocation of income among various tax jurisdictions.
Beginning January 1, 2007, we evaluate the liability
associated with our various filing positions by applying the two
step process of recognition and measurement as required by
Financial Accounting Standards Board (FASB) Interpretation
No. 48, “Accounting for Uncertainty in Income Taxes,
an interpretation of FASB Statement No. 109”
(FIN 48). The ultimate disposition of these contingencies
could have a significant impact on net cash flows. To the extent
we were to prevail in matters for which accruals have been
established or were required to pay amounts in excess of our
accrued liability, our effective tax rate in a given financial
statement period may be materially impacted.
See Note 5 of Notes to Consolidated Financial Statements
for additional information regarding FIN 48 and tax
carryovers.
We have employee benefit plans that include pension and other
postretirement benefits. Net periodic benefit expense and
obligations are impacted by various estimates and assumptions.
These estimates and assumptions include the expected long-term
rates of return on plan assets, discount rates, expected rate of
compensation increase, health care cost trend rates, and
employee demographics, including retirement age and mortality.
These assumptions are reviewed annually and adjustments are made
as needed. The assumptions utilized to compute expense and the
benefit obligations are shown in Note 7 of Notes to
Consolidated Financial Statements. The following table presents
the estimated increase (decrease) in net periodic benefit
expense and obligations resulting from a one-percentage-point
change in the specified assumption.
The expected long-term rates of return on plan assets are
determined by combining a review of historical returns realized
within the portfolio, the investment strategy included in the
plans’ Investment Policy Statement, and capital market
projections for the asset classifications in which the portfolio
is invested as well as the target
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weightings of each asset classification. These rates are
impacted by changes in general market conditions, but because
they are long-term in nature, short-term market swings do not
significantly impact the rates. Changes to our target asset
allocation would also impact these rates. Our expected long-term
rate of return on plan assets used for our pension plans is
7.75 percent for 2007. This rate was 7.75 percent in
2006 and 8.5 percent from
2002-2005.
Over the past ten years, our actual average return on plan
assets for our pension plans has been approximately
7.7 percent.
The discount rates are used to measure the benefit obligations
of our pension and other postretirement benefit plans. The
objective of the discount rates is to determine the amount, if
invested at the December 31 measurement date in a portfolio of
high-quality debt securities, that will provide the necessary
cash flows when benefit payments are due. Increases in the
discount rates decrease the obligation and, generally, decrease
the related expense. The discount rates for our pension and
other postretirement benefit plans were determined separately
based on an approach specific to our plans and their respective
expected benefit cash flows as described in Note 7 of Notes
to Consolidated Financial Statements. Our discount rate
assumptions are impacted by changes in general economic and
market conditions that affect interest rates on long-term
high-quality debt securities as well as the duration of our
plans’ liabilities.
The expected rate of compensation increase represents average
long-term salary increases. An increase in this rate causes
pension obligation and expense to increase.
The assumed health care cost trend rates are based on our actual
historical cost rates that are adjusted for expected changes in
the health care industry. An increase in this rate causes other
postretirement benefit obligation and expense to increase.
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Results
of Operations
Consolidated
Overview
The following table and discussion is a summary of our
consolidated results of operations for the three years ended
December 31, 2007. The results of operations by segment are
discussed in further detail following this consolidated overview
discussion.
2007 vs.
2006
The increase in revenues is due primarily to higher
Midstream revenues associated with increased natural gas liquid
(NGL) and olefins marketing revenues and increased production of
olefins and NGLs. Exploration & Production experienced
higher revenues also due to increases in production volumes and
net realized average prices. Additionally, Gas Pipeline revenues
increased primarily due to increased rates in effect since the
first quarter of 2007. These increases are partially offset by a
mark-to-market loss recognized at Gas Marketing Services on a
legacy derivative natural gas sales contract that we expect to
assign to another party in 2008 under an asset transfer
agreement that we executed in December 2007.
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The increase in costs and operating expenses is due
primarily to increased NGL and olefins marketing purchases and
increased costs associated with our olefins production business
at Midstream. Additionally, Exploration & Production
experienced higher depreciation, depletion and amortization and
lease operating expenses due primarily to higher production
volumes.
The increase in selling, general and administrative expenses
(SG&A) is primarily due to increased staffing in
support of increased drilling and operational activity at
Exploration & Production, the absence of a
$25 million gain in 2006 related to the sale of certain
receivables at Gas Marketing Services, and a $9 million
charge related to certain international receivables at Midstream.
Other (income) expense — net within
operating income in 2007 includes:
Other (income) expense — net within
operating income in 2006 includes:
The increase in general corporate expenses is
attributable to various factors, including higher
employee-related costs, increased levels of charitable
contributions and information technology expenses. The higher
employee-related costs are primarily the result of higher stock
compensation expense. (See Note 1 of Notes to Consolidated
Financial Statements.)
The securities litigation settlement and related costs is
primarily the result of our 2006 settlement related to
class-action
securities litigation filed on behalf of purchasers of our
securities between July 24, 2000 and July 22, 2002.
(See Note 15 of Notes to Consolidated Financial Statements.)
The increase in operating income reflects record high NGL
margins at Midstream, continued strong natural gas production
growth at Exploration & Production, the positive
effect of new rates at Gas Pipeline, and the absence of 2006
litigation expenses associated with shareholder lawsuits and
Gulf Liquids litigation.
Interest accrued — net includes a decrease of
$19 million in interest expense associated with our Gulf
Liquids litigation contingency, offset by changes in our debt
portfolio, most significantly the issuance of new debt in
December 2006 by Williams Partners L.P.
The increase in investing income is due to:
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These increases are partially offset by the absence of an
approximately $7 million gain on the sale of an
international investment in 2006.
Early debt retirement costs in 2007 includes
$19 million of premiums and fees related to the December
2007 repurchase of senior unsecured notes. (See Note 11 of
Notes to Consolidated Financial Statements.) Early debt
retirement costs in 2006 includes $27 million in
premiums and fees related to the January 2006 debt conversion
and $4 million of accelerated amortization of debt expenses
related to the retirement of the debt secured by assets of
Williams Production RMT Company.
Minority interest in income of consolidated subsidiaries
increased primarily due to the growth in the minority
interest holdings of Williams Partners L.P.
Provision for income taxes was significantly higher in
2007 due primarily to higher pre-tax earnings. The effective
income tax rate for 2007 is slightly higher than the federal
statutory rate primarily due to the effect of taxes on foreign
operations and an accrual for income tax contingencies,
partially offset by the utilization of charitable contribution
carryovers not previously benefited. The effective income tax
rate for 2006 is slightly higher than the federal statutory rate
primarily due to state income taxes, the effect of taxes on
foreign operations, nondeductible convertible debenture expenses
and an accrual for income tax contingencies, partially offset by
the favorable resolution of federal income tax litigation and
the utilization of charitable contribution carryovers not
previously benefited. The 2006 effective income tax rate has
been increased by an adjustment to increase overall deferred
income tax liabilities. (See Note 5 of Notes to
Consolidated Financial Statements.)
Income (loss) from discontinued operations in 2007
primarily includes the operating results of substantially all of
our power business and the sale of that business, which was
completed in November 2007. (See Note 2 of Notes to
Consolidated Financial Statements.) These results include the
following pre-tax items:
Income (loss) from discontinued operations in 2006
includes:
2006 vs.
2005
The decrease in revenues is primarily due to lower
natural gas realized revenues at Gas Marketing Services
associated with lower natural gas sales prices. Additionally,
the effect of a change in forward prices on legacy natural gas
derivative contracts not designated as cash flow hedges had an
unfavorable impact on revenues. Partially
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offsetting these decreases are increased crude, olefin and NGL
marketing revenues, higher NGL production revenue at Midstream
and increased production revenue at Exploration &
Production.
The decrease in costs and operating expenses is largely
due to reduced natural gas purchase prices at Gas Marketing
Services. Partially offsetting these decreases are increased
crude, olefin and NGL marketing purchases and operating expenses
at Midstream and increased depreciation, depletion and
amortization and lease operating expense at
Exploration & Production.
The increase in SG&A expenses is primarily due to
increased personnel costs, insurance expense, higher information
systems support costs and the absence of a $17 million
reduction of pension expense at Gas Pipeline in 2005.
Additionally, Exploration & Production experienced
higher costs due to increased staffing in support of increased
drilling and operational activity.
Other (income) expense — net within
operating income in 2005 includes:
General corporate expenses decreased primarily due to the
absence of $14 million of insurance settlement charges in
2005 associated with certain insurance coverage allocation
issues.
The decrease in operating income primarily reflects the
negative effect of a change in forward prices on natural gas
derivative contracts at Gas Marketing Services, higher operating
and administrative costs at Gas Pipeline and 2006 litigation
expenses associated with shareholder lawsuits and Gulf Liquids
litigation. These decreases are partially offset by higher
margins at Midstream and the absence a 2005 accrual for
estimated litigation contingencies associated primarily with
agreements reached to substantially resolve exposure related to
natural gas price and volume reporting issues.
Interest accrued — net in 2006 includes
$22 million in interest expense associated with our Gulf
Liquids litigation contingency.
The increase in investing income is due to:
These increases are partially offset by:
The increase in minority interest in income of consolidated
subsidiaries is primarily due to the growth of Williams
Partners L.P.
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Provision for income taxes was significantly lower in
2006 due primarily to lower pre-tax earnings. The effective
income tax rate for 2006 is slightly higher than the federal
statutory rate primarily due to state income taxes, the effect
of taxes on foreign operations, nondeductible convertible
debenture expenses and an accrual for income tax contingencies,
partially offset by the favorable resolution of federal income
tax litigation and the utilization of charitable contribution
carryovers not previously benefited. The 2006 effective income
tax rate has been increased by an adjustment to increase overall
deferred income tax liabilities. The effective income tax rate
for 2005 is higher than the federal statutory rate due primarily
to state income taxes, nondeductible expenses and the inability
to utilize charitable contribution carryovers. The 2005
effective income tax rate was reduced by an adjustment to reduce
overall deferred income tax liabilities and favorable
settlements on federal and state income tax matters. (See
Note 5 of Notes to Consolidated Financial Statements.)
Income (loss) from discontinued operations in 2005
includes a $155 million net-of-tax loss related to our
discontinued power business. (See Note 2 of Notes to
Consolidated Financial Statements.)
Cumulative effect of change in accounting principle in
2005 is due to the implementation of FIN 47.
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We are currently organized into the following segments:
Exploration & Production, Gas Pipeline, Midstream, Gas
Marketing Services, and Other. Other primarily consists of
corporate operations. Our management currently evaluates
performance based on segment profit (loss) from operations. (See
Note 17 of Notes to Consolidated Financial Statements.)
In 2007, we continued our strategy of a rapid execution of our
development drilling program in our growth basins. Accordingly,
we:
2007 vs
2006 Domestic Production
Average
daily domestic production grew 21 percent or 161 MMcfe per
day
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The benefits of higher production volumes and higher net
realized average prices were partially offset by increased
operating costs. The increase in operating costs was primarily
due to increased production volumes and higher well service and
industry costs. In addition, higher production volumes increased
depletion, depreciation and amortization expense.
In February 2007, we entered into a five-year unsecured credit
agreement with certain banks in order to reduce margin
requirements related to our hedging activities as well as lower
transaction fees. Margin requirements, if any, under this new
facility are dependent on the level of hedging and on natural
gas reserves value. (See Note 11 of Notes to Consolidated
Financial Statements.) We may also execute hedges with the Gas
Marketing Services segment, which, in turn, executes offsetting
derivative contracts with unrelated third parties. In this
situation, Gas Marketing Services, generally, bears the
counterparty performance risks associated with unrelated third
parties. Hedging decisions primarily are made considering our
overall commodity risk exposure and are not executed
independently by Exploration & Production.
In May and July 2007, we increased our position in the
Fort Worth basin by acquiring producing properties and
leasehold acreage for approximately $41 million. These
acquisitions are consistent with our growth strategy of
leveraging our horizontal drilling expertise by acquiring and
developing low-risk properties in the Barnett Shale formation.
In July 2007, we increased our position in the Piceance basin by
acquiring additional undeveloped leasehold acreage for
approximately $36 million.
Our expectations and objectives for 2008 include:
Natural gas prices in the Rocky Mountain areas trended lower
throughout 2007 due to strong drilling activities increasing
supplies while constrained by limited pipeline capacity.
However, we will continue to utilize firm transportation
contracts which allow a substantial portion of our Rockies
production to be sold at more advantageous market points. Our
continued use of basin-level collars and fixed-price hedges
should also reduce our exposure to this trend. The construction
of a new third-party pipeline that began transporting gas from
the Rocky Mountain areas in the beginning of 2008 should lessen
pipeline transportation capacity constraints and provided an
additional alternative market for the sale of production.
Approximately 70 MMcf of our forecasted 2008 daily domestic
production is hedged by NYMEX and basis fixed-price contracts at
prices that average $3.97 per Mcf at a basin level. In addition,
we have the following collar agreements for our forecasted 2008
daily domestic production, shown at basin-level weighted-average
prices and weighted-average volumes:
Risks to achieving our expectations include unfavorable natural
gas market price movements which are impacted by numerous
factors including weather conditions and domestic natural gas
production and consumption. Also, achievement of expectations
can be affected by costs of services associated with drilling.
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In January 2008, we sold a contractual right to a production
payment on certain future international hydrocarbon production
for approximately $148 million. We have received
$118 million in cash and $29 million has been placed
in escrow subject to certain post-closing conditions and
adjustments. We will recognize a pre-tax gain of approximately
$118 million in the first quarter of 2008 related to the
initial cash received. As a result of the contract termination,
we have no further interests associated with the crude oil
concession, which is located in Peru. We had obtained these
interests through our acquisition of Barrett Resources
Corporation in 2001.
2007 vs.
2006
Total segment revenues increased $605 million, or
41 percent, primarily due to the following:
These increases were partially offset by a $30 million
decrease relating to hedge ineffectiveness. In 2006, there were
$14 million in net unrealized gains from hedge
ineffectiveness as compared to $16 million in net
unrealized losses in 2007.
To manage the commodity price risk and volatility of owning
producing gas properties, we enter into derivative forward sales
contracts that fix the sales price relating to a portion of our
future production. Approximately 19 percent of domestic
production in 2007 was hedged by NYMEX and basis fixed-price
contracts at a weighted-average price of $3.90 per Mcf at a
basin level compared to 40 percent hedged at a
weighted-average price of $3.82 per Mcf for 2006. Also,
approximately 30 percent and 15 percent of 2007 and
2006 domestic production was
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hedged in the following collar agreements shown at basin-level
weighted-average prices and weighted-average volumes:
Total segment costs and expenses increased
$404 million, primarily due to the following:
The $204 million increase in segment profit is
primarily due to the 21 percent increase in domestic
production volumes sold as well as the 15 percent increase
in net realized average prices, partially offset by the increase
in segment costs and expenses.
2006 vs.
2005
Total segment revenues increased $219 million, or
17 percent, primarily due to the following:
In 2005, approximately 47 percent of domestic production
was hedged by NYMEX and basis fixed-price contracts at a
weighted-average price of $3.99 per Mcf. Approximately
10 percent of domestic production was hedged by a NYMEX
collar agreement for approximately 50 MMcf per day at a
floor price of $7.50 per Mcf and a
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ceiling price of $10.49 per Mcf in the first quarter and at a
floor price of $6.75 per Mcf and a ceiling price of $8.50 per
Mcf in the second, third, and fourth quarters, and a Northwest
Pipeline/Rockies collar agreement for approximately 50 MMcf
per day in the fourth quarter at a floor price of $6.10 per Mcf
and a ceiling price of $7.70 per Mcf.
Total segment costs and expenses increased
$257 million, primarily due to the following:
The $35 million decrease in segment profit is
primarily due to lower net realized average prices and higher
segment costs and expenses as discussed previously, and
the absence in 2006 of $30 million of gains on the sales of
properties in 2005. Partially offsetting these decreases are a
23 percent increase in domestic production volumes sold and
increase in income from ineffectiveness and forward
mark-to-market gains. Segment profit also includes an
$8 million increase in our international operations
primarily due to higher revenue and equity earnings as a result
of increases in net realized average prices for crude oil
production volumes sold.
Gas
Pipeline
Our strategy to create value for our shareholders focuses on
maximizing the utilization of our pipeline capacity by providing
high quality, low cost transportation of natural gas to large
and growing markets.
Gas Pipeline’s interstate transmission and storage
activities are subject to regulation by the FERC and as such,
our rates and charges for the transportation of natural gas in
interstate commerce, and the extension, expansion or abandonment
of jurisdictional facilities and accounting, among other things,
are subject to regulation. The rates are established through the
FERC’s ratemaking process. Changes in commodity prices and
volumes transported have little impact on revenues because the
majority of cost of service is recovered through firm capacity
reservation charges in transportation rates.
Significant events of 2007 include:
During third-quarter 2007, we formed Williams Pipeline Partners
L.P. (WMZ) to own and operate natural gas transportation and
storage assets. In January 2008, WMZ completed its initial
public offering of 16.25 million common units at a price of
$20.00 per unit. In February 2008, the underwriters also
exercised their right to purchase an additional
1.65 million common units at the same price. A subsidiary
of ours serves as the general partner of WMZ. The initial asset
of the partnership is a 35 percent interest in Northwest
Pipeline GP, formerly Northwest Pipeline Corporation. Upon
completion of the transaction, we hold approximately
47.7 percent of the interests in WMZ, including the
interests of the general partner.
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During 2006, Northwest Pipeline and Transco each filed general
rate cases with the FERC for increases in rates. The new rates
were effective, subject to refund, on January 1, 2007, for
Northwest Pipeline and on March 1, 2007, for Transco.
On March 30, 2007, the FERC approved the stipulation and
settlement agreement with respect to the rate case for Northwest
Pipeline. The settlement establishes an increase in general
system firm transportation rates on Northwest Pipeline’s
system from $0.30760 to $0.40984 per Dth (dekatherm), effective
January 1, 2007.
On November 28, 2007, Transco filed a formal stipulation
and agreement with the FERC resolving all substantive issues in
Transco’s pending 2006 rate case. Final resolution of the
rate case is subject to approval by the FERC.
In May 2007, we placed into service a 37.6-mile expansion of
30-inch
diameter line in northwest Colorado. The expansion increased
capacity by 450 Mdt/d at a cost of approximately
$86 million. In December 2007, this asset was purchased by
Midstream. In an arrangement approved by the FERC, Midstream
will lease the pipeline to Gas Pipeline, who will continue to
operate the pipeline until completion of a planned FERC
abandonment filing.
In December 2007, we placed into service an expansion of certain
existing pipeline facilities in the northeast United States. The
project increased firm transportation capacity by 100 Mdt/d at
an approximate cost of $169 million.
In November 2007, we placed into service 16.5 miles of
42-inch
pipeline in the Mid-Atlantic region of the United States. The
second phase of the project involving installation of certain
facilities will be completed in the fall of 2008. The project
provides 165 Mdt/d of incremental firm capacity at an
approximate total cost of $88 million.
Outlook
for 2008
In June 2007, our equity method investee, Gulfstream, received
FERC approval to extend its existing pipeline approximately
34 miles within Florida. The extension will fully subscribe
the remaining 345 Mdt/d of firm capacity on the existing
pipeline. Construction began in January 2008. The estimated cost
of this project is approximately $130 million and is
expected to be placed into service in July 2008.
In September 2007, Gulfstream received FERC approval to
construct 17.5 miles of
20-inch
pipeline and to install a new compressor facility. Construction
began in December 2007. The pipeline expansion will increase
capacity by 155 Mdt/d and is expected to be placed into service
in September 2008. The compressor facility is expected to be
placed into service in January 2009. The estimated cost of this
project is approximately $153 million.
In December 2007, we filed an application with the FERC to
construct an expansion in the northeast United States. The
estimated cost of the project is approximately
$169 million. The expansion will increase capacity by 142
Mdt/d and is expected to be placed into service in two phases,
occurring in November 2008 and November 2009.
We own a one-third interest in the Jackson Prairie underground
storage facility located in Washington, with the remaining
interests owned by two of our distribution customers. In
February 2007, we received FERC approval to
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expand the Jackson Prairie facility. The expansion will increase
our one-third share of the capacity by 104 Mdt/d and is expected
to be placed into service in November 2008.
2007 vs.
2006
Revenues increased $262 million, or 19 percent,
due primarily to a $173 million increase in transportation
revenue and a $25 million increase in storage revenue
resulting primarily from new rates effective in the first
quarter of 2007. In addition, revenues increased
$59 million due to the sale of excess inventory gas.
Costs and operating expenses increased $86 million,
or 11 percent, due primarily to:
Partially offsetting these increases is a decrease of
$12 million in contract and outside service costs and a
decrease of $7 million in materials and supplies expense.
Other (income) expense — net changed favorably
by $15 million due primarily to $18 million of income
associated with payments received for a terminated firm
transportation agreement on Northwest Pipeline’s Grays
Harbor lateral. Also included in the favorable change is
$17 million of income recorded in the second quarter of
2007 for a change in estimate related to a regulatory liability
at Northwest Pipeline, partially offset by $18 million of
expense related to higher asset retirement obligations.
Equity earnings increased $14 million due primarily to a
$14 million increase in equity earnings from Gulfstream.
Gulfstream’s higher earnings were primarily due to a
decrease in property taxes from a favorable litigation outcome
as well as improved operating results.
The $206 million, or 44 percent, increase in
segment profit is due primarily to $262 million
higher revenues, $14 million higher equity earnings and
$15 million favorable other (income) expense —
net as previously discussed. Partially offsetting these
increases are higher costs and operating expenses as
previously discussed.
2006 vs.
2005
Operating results for 2005 included:
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Revenues decreased $65 million, or 5 percent,
due primarily to $75 million lower revenues associated with
exchange imbalance settlements (offset in costs and operating
expenses). Partially offsetting this decrease is a
$9 million increase in revenue due to an adjustment for the
recovery of state income tax rate changes (offset in
provision for income taxes).
Costs and operating expenses decreased $17 million,
or 2 percent, due primarily to:
Partially offsetting these decreases are:
SG&A expenses increased $77 million, or
92 percent, due primarily to:
The $119 million, or 20 percent, decrease in
segment profit is due primarily to the absence of
significant 2005 adjustments as previously discussed, increases
in costs and operating expenses and SG&A expenses
as previously discussed, and the absence of a
$5 million construction completion fee recognized in 2005
related to our investment in Gulfstream.
Midstream’s ongoing strategy is to safely and reliably
operate large-scale midstream infrastructure where our assets
can be fully utilized and drive low
per-unit
costs. Our business is focused on consistently attracting new
business by providing highly reliable service to our customers.
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Significant events during 2007 include the following:
Continued
favorable commodity price margins
The average realized natural gas liquid (NGL) per unit margins
at our processing plants during 2007 was a record high 55 cents
per gallon. NGL margins exceeded Midstream’s rolling
five-year average for the last seven quarters. The geographic
diversification of Midstream assets contributed significantly to
our realized unit margins resulting in margins generally greater
than that of the industry benchmarks for gas processed in the
Henry Hub area and fractionated and sold at Mont Belvieu. The
largest impact was realized at our western United States gas
processing plants, which benefited from lower regional market
natural gas prices.
Domestic
Gathering and Processing Per Unit NGL Margin with Production
and
Sales Volumes by Quarter (excludes partially owned plants) 
Consistent with our strategy, we continued to expand our
midstream operations where we have large-scale assets in growth
basins.
During the first quarter of 2007, we completed construction at
our existing gas processing complex located near Opal, Wyoming,
to add a fifth cryogenic gas processing train capable of
processing up to
350 MMcf/d,
bringing total Opal capacity to approximately
1,450 MMcf/d.
This plant expansion became operational during the first
quarter. We also have several expansion projects ongoing in the
West region to lower field pressures and increase production
volumes for our customers who continue robust drilling
activities in the region.
We continue construction of
37-mile
extensions of both of our oil and gas pipelines from our Devils
Tower spar to the Blind Faith prospect located in Mississippi
Canyon. These extensions, estimated to cost approximately
$250 million, are expected to be ready for service by the
second quarter of 2008.
During 2007, we have continued construction activities on the
Perdido Norte project which includes oil and gas lines that
would expand the scale of our existing infrastructure in the
western deepwater of the Gulf of Mexico. In addition, we
completed agreements with certain producers to provide
gathering, processing and transportation services over the life
of the reserves. We also intend to expand our Markham gas
processing facility to adequately serve this new gas production.
The scale of the project has increased to include additional
pipeline and more
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efficient processing capacity. The estimated cost is now
approximately $560 million, and it is expected to be in
service in the third quarter of 2009.
In July 2007, we exercised our right of first refusal to acquire
BASF’s 5/12th ownership interest in the Geismar
olefins facility for approximately $62 million. The
acquisition increases our total ownership to 10/12th.
In March 2007, we announced plans to construct and operate the
new Willow Creek facility, a
450 MMcf/d
natural gas processing plant in western Colorado’s Piceance
basin, where Exploration & Production has its most
significant volume of natural gas production, reserves and
development activity. Exploration & Production’s
existing Piceance basin processing plants are primarily designed
to condition the natural gas to meet quality specifications for
pipeline transmission, not to maximize the extraction of NGLs.
We expect the new Willow Creek facility to recover
25,000 barrels per day of NGLs at startup, which is
expected to be in the third quarter of 2009.
In December 2007, we purchased the Parachute Lateral system from
Gas Pipeline. The system is a 37.6-mile expansion, originally
placed in service by Gas Pipeline in May 2007, and provides
capacity of 450 Mdt/d through a
30-inch
diameter line, transporting residue gas from the Piceance basin
to the Greasewood Hub in northwest Colorado. The Willow Creek
facility will straddle the Parachute Lateral pipeline and will
process gas flowing through the pipeline. In an arrangement
approved by the FERC, Midstream will lease the pipeline to Gas
Pipeline, who will continue to operate the pipeline until
completion of a planned FERC abandonment filing.
In addition, we have acquired an existing natural gas pipeline
from Gas Pipeline, and begun the process of converting it from
natural gas to NGL service and constructing additional pipeline
to create a pipeline alternative for NGLs currently being
transported by truck from Exploration &
Production’s existing Piceance basin processing plants to a
major NGL transportation pipeline system.
We have also agreed to dedicate our equity NGL volumes from
Willow Creek, along with our two Wyoming plants, for transport
under a long-term shipping agreement with Overland Pass Pipeline
Company, LLC. We currently have a 1 percent interest in
Overland Pass Pipeline Company, LLC and have the option to
increase our ownership to 50 percent and become the
operator within two years of the pipeline becoming operational.
Start-up is
planned for mid-2008. The terms of the shipping agreement
represent significant savings compared with agreements we are
now utilizing.
We currently own approximately 23.6 percent of Williams
Partners L.P., including the interests of the general partner,
which is wholly owned by us. Considering the control of the
general partner in accordance with EITF Issue
No. 04-5,
Williams Partners L.P. is consolidated within the Midstream
segment. (See Note 1 of Notes to Consolidated Financial
Statements.) Midstream’s segment profit includes
100 percent of Williams Partners L.P.’s segment
profit, with the minority interest’s share deducted below
segment profit. The debt and equity issued by Williams Partners
L.P. to third parties is reported as a component of our
consolidated debt balance and minority interest balance,
respectively.
In June 2007, Williams Partners L.P. completed its acquisition
of our 20 percent interest in Discovery Producer Services,
LLC (Discovery). Williams Partners L.P. now owns a
60 percent interest in Discovery.
In December 2007, Williams Partners L.P. acquired certain of our
membership interests in Wamsutter LLC, the limited liability
company that owns the Wamsutter system, from us for
$750 million. Williams Partners L.P. completed the
transaction after successfully closing a public equity offering
of 9.25 million common units that yielded net proceeds of
approximately $335 million. The partnership primarily
financed the remainder of the purchase price through utilizing
$250 million of term loan borrowings and issuing
approximately $157 million of common units to us. The
$250 million term loan is under Williams Partners
L.P.’s new $450 million five-year senior unsecured
credit facility that became effective simultaneous with the
closing of the Wamsutter transaction. (See Note 11 of Notes
to Consolidated Financial Statements.)
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On November 28, 2007, there was a fire at the Ignacio gas
processing plant. This fire resulted in severe damage to the
facility’s cooling tower, control room, adjacent warehouse
buildings and control systems. The plant was shut down until
January 18, 2008. There were no injuries as a result of
this incident and the plant now has full cryogenic recovery
capability available for operation. The impact of the fire was
immaterial to our results of operations.
The following factors could impact our business in 2008 and
beyond.
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In order to provide additional clarity, our management’s
discussion and analysis of operating results separately reflects
the portion of general and administrative expense not allocated
to an asset group as indirect general and administrative
expense. These charges represent any overhead cost not
directly attributable to one of the specific asset groups noted
in this discussion.
2007 vs.
2006
The $1,021 million, or 25 percent, increase in
segment revenues is largely due to:
These increases are partially offset by a $35 million
decrease in fee revenues.
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Segment costs and expenses increased $645 million,
or 18 percent, primarily as a result of:
These increases are partially offset by;
The $397 million, or 59 percent, increase in
Midstream’s segment profit reflects
$339 million higher NGL margins and the absence of the
previously mentioned $73 million Gulf Liquids litigation
charge in 2006, as well as the other previously described
changes in segment revenues and segment costs and
expenses. A more detailed analysis of the segment profit of
Midstream’s various operations is presented as follows.
Domestic
gathering & processing
The $266 million increase in domestic gathering and
processing segment profit includes a $308 million
increase in the West region, partially offset by a
$42 million decrease in the Gulf Coast region.
The $308 million increase in our West region’s
segment profit primarily results from higher NGL margins,
higher processing fee based revenues and income from a favorable
litigation outcome, partially offset by higher operating
expenses and lower gathering fee revenues. The significant
components of this increase include the following:
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The $42 million decrease in the Gulf Coast region’s
segment profit is primarily a result of lower volumes
from our deepwater facilities, losses on impairments, and the
absence of gains on assets in 2006, partially offset by higher
NGL margins and higher other fee revenues. The significant
components of this decrease include the following:
Venezuela
Segment profit for our Venezuela assets decreased
$9 million. The decrease is primarily due to the absence of
a $9 million gain from the settlement of a contract dispute
in 2006, $6 million lower fee revenues due primarily to the
discontinuance in 2007 of revenue recognition related to labor
escalation receivables, $7 million higher operating
expenses, and $8 million higher bad debt expense related to
labor escalation receivables, partially offset by
$19 million of higher currency exchange gains and
$1 million higher equity earnings.
Other
The significant components of the $158 million increase in
segment profit of our other operations include the
following:
These increases are partially offset by:
Effective January 1, 2007, we adopted FASB Staff Position
(FSP) No. AUG AIR-1, Accounting for Planned Major
Maintenance Activities. As a result, we recognized as other
income an $8 million reversal of an accrual for major
maintenance on our Geismar ethane cracker. We did not apply the
FSP retrospectively because the impact to our first quarter 2007
and estimated full year 2007 earnings, as well as the impact to
prior periods, is not material. We have adopted the deferral
method for accounting for these costs going forward.
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Indirect
general and administrative expense
The $18 million, or 26 percent, increase in indirect
general and administrative expense is due primarily to higher
technical support services and other charges for various
administrative support functions and higher employee expenses.
2006 vs.
2005
The $868 million, or 26 percent, increase in
segment revenues is largely due to:
These increases were partially offset by an $84 million
reduction in NGL revenues due to a change in classification of
NGL transportation and fractionation expenses from costs of
goods sold to net revenues (offset in costs and operating
expenses).
Segment costs and expenses increased $688 million,
or 23 percent, primarily as a result of:
These increases were partially offset by:
The $215 million, or 47 percent, increase in Midstream
segment profit is primarily due to higher NGL margins,
higher deepwater production handling revenues, higher gathering
and processing revenues, higher margins from our olefins unit,
and a settlement of an international contract dispute, and the
absence of a $23 million impairment of our equity
investment in Aux Sable Liquid Products L.P. (Aux Sable)
recorded in 2005. These increases were largely offset by the
$73 million charge related to the Gulf Liquids litigation
contingency combined with higher operating costs and lower
margins related to the marketing of olefins and NGLs. A more
detailed analysis of the segment profit of
Midstream’s various operations is presented as follows.
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Domestic
gathering & processing
The $242 million increase in domestic gathering and
processing segment profit includes a $138 million
increase in the West region and a $104 million increase in
the Gulf Coast region.
The $138 million increase in our West region’s
segment profit primarily results from higher product
margins and higher gathering and processing revenues, partially
offset by higher operating expenses. The significant components
of this increase include the following:
The $104 million increase in the Gulf Coast region’s
segment profit is primarily a result of higher NGL
margins, higher volumes from our deepwater facilities, partially
offset by higher operating expenses. The significant components
of this increase include the following:
Venezuela
Segment profit for our Venezuela assets increased
$3 million and includes $9 million resulting from the
settlement of a contract dispute and $1 million in higher
revenues due to higher natural gas volumes and prices at our
compression facility. These are partially offset by
$4 million in higher expenses related to higher insurance,
personnel and contract labor costs and a $2 million
increase in the reserve for uncollectible accounts.
Other
The $26 million decrease in segment profit of our
other operations is largely due to the $73 million of
charges related to the Gulf Liquids litigation contingency
combined with $13 million in lower margins related to the
marketing of olefins. The decrease also reflects
$12 million in lower margins related to the marketing of
NGLs due to more favorable changes in pricing while product was
in transit during 2005 as compared to 2006. These were partially
offset by the absence of a $23 million impairment of our
equity investment in Aux Sable in 2005, $24 million in
higher margins in our olefins unit, $7 million in higher
earnings from our equity investment in
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Discovery Producer Services, L.L.C. (Discovery), $7 million
in higher fractionation, storage and other fee revenues, and a
$4 million favorable transportation settlement.
Gas Marketing Services (Gas Marketing) primarily supports our
natural gas businesses by providing marketing and risk
management services, which include marketing and hedging the gas
produced by Exploration & Production, and procuring
fuel and shrink gas and hedging natural gas liquids sales for
Midstream. In addition, Gas Marketing manages various natural
gas-related contracts such as transportation, storage, and
related hedges, including certain legacy natural gas contracts
and positions, and provides services to third parties, such as
producers.
Gas Marketing’s operating results for 2007 were primarily
driven by a loss of approximately $166 million related to
certain legacy derivative natural gas contracts that we expect
to assign to another party in 2008 under an asset transfer
agreement that we executed in December 2007. In addition, a
decrease in forward natural gas basis prices against a net long
legacy derivative position contributed to the losses as well.
For 2008, Gas Marketing intends to focus on providing services
that support our natural gas businesses. Certain legacy natural
gas contracts and positions from our former Power segment remain
in the Gas Marketing segment. Gas Marketing’s earnings may
continue to reflect mark-to-market volatility from
commodity-based derivatives that represent economic hedges but
are not designated as hedges for accounting purposes or do not
qualify for hedge accounting. However, this mark-to-market
volatility is expected to be significantly reduced compared with
previous levels.
2007 vs.
2006
Realized revenues represent (1) revenue from the
sale of natural gas and (2) gains and losses from the net
financial settlement of derivative contracts. Realized
revenues decreased $237 million primarily due to a
decrease in net financial settlements of derivative contracts.
This is partially offset by an increase in physical natural gas
revenue as a result of a 9 percent increase in natural gas
sales volumes partially offset by a 6 percent decrease in
average prices on physical natural gas sales.
Net forward unrealized mark-to-market gains (losses)
primarily represent changes in the fair values of certain
legacy derivative contracts with a future settlement or delivery
date that are not designated as hedges for accounting purposes
or do not qualify for hedge accounting. A $156 million loss
related to a legacy derivative natural gas sales contract, that
we expect to assign to another party in 2008 under an asset
transfer agreement that we executed in
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December 2007, primarily caused the unfavorable change in net
forward unrealized mark-to-market gains (losses). Prior to
the execution of the asset transfer agreement, we accounted for
this legacy contract on an accrual basis under the normal
purchases and normal sales exception of SFAS 133. Due to
the pending assignment of the legacy contract, we no longer
consider the contract to be in the normal course of business.
Therefore, we recognized a loss to reflect the current negative
fair value of the contract. In addition, losses on gas purchase
contracts caused by a decrease in forward natural gas prices
were greater in 2007 than in 2006.
The $321 million decrease in Gas Marketing’s costs
and operating expenses is primarily due to a 7 percent
decrease in average prices on physical natural gas purchases,
partially offset by a 4 percent increase in natural gas
purchase volumes.
The unfavorable change in selling, general and administrative
(income) expense is due primarily to the absence of a
$25 million gain from the sale of certain receivables to a
third party in 2006.
Other (income) expense — net in 2007 includes a
$20 million accrual for litigation contingencies.
The $142 million increase in segment loss is
primarily due to the loss recognized on a legacy derivative
sales contract previously treated as a normal purchase and
normal sale, a $20 million accrual for litigation
contingencies, and the absence of a $25 million gain from
the sale of certain receivables as described above, partially
offset by an improvement in accrual gross margin.
2006 vs.
2005
Realized revenues decreased $962 million primarily
due to a 17 percent decrease in average prices on physical
natural gas sales.
The effect of a change in forward prices on legacy natural gas
derivative contracts primarily caused the $324 million
unfavorable change in net forward unrealized mark-to-market
gains (losses). A decrease in forward natural gas prices
during 2006 caused losses on legacy net forward gas fixed-price
purchase contracts, while an increase in forward natural gas
prices during 2005 caused gains on legacy net forward gas
fixed-price purchase contracts.
The $980 million decrease in Gas Marketing’s costs
and operating expenses is primarily due to an
18 percent decrease in average prices on physical natural
gas purchases.
The favorable change in selling, general and administrative
(income) expense is due primarily to increased gains from
the sale of certain receivables to a third party. Gas Marketing
recognized a $25 million gain in 2006 compared to a
$10 million gain in 2005.
Other (income) expense — net in 2005 includes
an $82 million accrual for estimated litigation
contingencies, primarily associated with agreements reached to
substantially resolve exposure related to natural gas price and
volume reporting issues (see Note 15 of Notes to
Consolidated Financial Statements) and a $5 million accrual
for a regulatory settlement.
The $204 million change from a segment profit to a
segment loss is primarily due to the effect of a change
in forward prices on legacy natural gas derivative contracts,
partially offset by favorable changes in other (income)
expense — net described above.
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2007 vs.
2006
The improvement in segment loss for 2007 is primarily
driven by $5 million of net gains on the sale of land.
2006 vs.
2005
Other segment loss for 2005 includes $87 million of
impairment charges, of which $38 million was recorded
during the fourth quarter, related to our investment in
Longhorn. In a related matter, we wrote off $4 million of
capitalized project costs associated with Longhorn. We also
recorded $24 million of equity losses associated with our
investment in Longhorn. Partially offsetting these charges and
losses was a $9 million fourth quarter gain on the sale of
land.
The chart below reflects the fair value of derivatives held for
trading purposes as of December 31, 2007. We have presented
the fair value of assets and liabilities by the period in which
they would be realized under their contractual terms and not as
a result of a sale. We have reported the fair value of a portion
of these derivatives in assets and liabilities of discontinued
operations. (See Note 2 of Notes to Consolidated Financial
Statements.)
As the table above illustrates, we are not materially engaged in
trading activities. However, we hold a substantial portfolio of
nontrading derivative contracts. Nontrading derivative contracts
are those that hedge or could possibly hedge forecasted
transactions on an economic basis. We have designated certain of
these contracts as cash flow hedges of Exploration &
Production’s forecasted sales of natural gas production and
Midstream’s forecasted sales of natural gas liquids under
SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (SFAS 133). Of the
total fair value of nontrading derivatives, SFAS 133 cash
flow hedges had a net liability value of $268 million as of
December 31, 2007. The chart below reflects the fair value
of derivatives held for nontrading purposes as of
December 31, 2007, for Gas Marketing Services,
Exploration & Production, Midstream, and nontrading
derivatives reported in assets and liabilities of discontinued
operations.
Net
Assets (Liabilities) — Nontrading
(Millions)
Most of the derivatives we hold settle in active periods and
markets in which quoted market prices are available. These
include futures contracts, option contracts, swap agreements and
physical commodity purchases and sales in the commodity markets
in which we transact. While an active market may not exist for
the entire period, quoted prices can generally be obtained for
natural gas through 2012.
These prices reflect current economic and regulatory conditions
and may change because of market conditions. The availability of
quoted market prices in active markets varies between periods
and commodities based
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upon changes in market conditions. The ability to obtain quoted
market prices also varies greatly from region to region. The
time periods noted above are an estimation of aggregate
availability of quoted prices. An immaterial portion of our
total net derivative liability value of $368 million
relates to periods in which active quotes cannot be obtained. We
estimate energy commodity prices in these illiquid periods by
incorporating information about commodity prices in actively
quoted markets, quoted prices in less active markets, and other
market fundamental analysis. Modeling and other valuation
techniques, however, are not used significantly in determining
the fair value of our derivatives.
We include an assessment of the risk of counterparty
nonperformance in our estimate of fair value for all contracts.
Such assessment considers (1) the credit rating of each
counterparty as represented by public rating agencies such as
Standard & Poor’s and Moody’s Investors
Service, (2) the inherent default probabilities within
these ratings, (3) the regulatory environment that the
contract is subject to and (4) the terms of each individual
contract.
Risks surrounding counterparty performance and credit could
ultimately impact the amount and timing of expected cash flows.
We continually assess this risk. We have credit protection
within various agreements to call on additional collateral
support if necessary. At December 31, 2007, we held
collateral support, including letters of credit, of
$215 million.
We also enter into master netting agreements to mitigate
counterparty performance and credit risk. During 2007 and 2006,
we did not incur any significant losses due to recent
counterparty bankruptcy filings.
The gross credit exposure from our derivative contracts, a
portion of which is included in assets of discontinued
operations (see Note 2 of Notes to Consolidated Financial
Statements), as of December 31, 2007, is summarized below.
We assess our credit exposure on a net basis to reflect master
netting agreements in place with certain counterparties. We
offset our credit exposure to each counterparty with amounts we
owe the counterparty under derivative contracts. The net credit
exposure from our derivatives as of December 31, 2007, is
summarized below.
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We have policies and procedures that govern our trading and risk
management activities. These policies cover authority and
delegation thereof in addition to control requirements,
authorized commodities and term and exposure limitations.
Value-at-risk
is limited in aggregate and calculated at a 95 percent
confidence level.
Management’s
Discussion and Analysis of Financial Condition
We believe we have, or have access to, the financial resources
and liquidity necessary to meet future requirements for working
capital, capital and investment expenditures and debt payments
while maintaining a sufficient level of liquidity to reasonably
protect against unforeseen circumstances requiring the use of
funds. We also expect to maintain our investment grade status.
In 2008, we expect to maintain liquidity from cash and cash
equivalents and unused revolving credit facilities of at least
$1 billion. We maintain adequate liquidity to manage margin
requirements related to significant movements in commodity
prices, unplanned capital spending needs, near term scheduled
debt payments, and litigation and other settlements. We expect
to fund capital and investment expenditures, debt payments,
dividends, stock repurchases and working capital requirements
through cash flow from operations, which is currently estimated
to be between $2.3 billion and $2.7 billion in 2008,
proceeds from debt issuances and sales of units of Williams
Partners L.P. and Williams Pipeline Partners L.P., as well as
cash and cash equivalents on hand as needed.
We enter 2008 positioned for continued growth through
disciplined investments in our natural gas businesses. Examples
of this planned growth include:
We estimate capital and investment expenditures will total
approximately $2.6 billion to $2.9 billion in 2008. As
a result of increasing our development drilling program,
$1.45 billion to $1.65 billion of the total estimated
2008 capital expenditures is related to Exploration &
Production. Also within the total estimated expenditures for
2008 is approximately $180 million to $260 million for
compliance and maintenance-related projects at Gas Pipeline,
including Clean Air Act compliance. Commitments for construction
and acquisition of property, plant and equipment are
approximately $484 million at December 31, 2007.
Potential risks associated with our planned levels of liquidity
and the planned capital and investment expenditures discussed
above include:
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In August 2006, the Pension Protection Act of 2006 was signed
into law. The Act makes significant changes to the requirements
for employer-sponsored retirement plans, including revisions
affecting the funding of defined benefit pension plans beginning
in 2008. We have assessed the impact of the legislation on our
future funding requirements and do not expect a significant
increase in minimum funding requirements over current levels,
assuming long-term rates of return on assets and current
discount rates do not experience a significant decline.
In February 2007, Exploration & Production entered
into a five-year unsecured credit agreement with certain banks
in order to reduce margin requirements related to our hedging
activities as well as lower transaction fees. Under the credit
agreement, Exploration & Production is not required to
post collateral as long as the value of its domestic natural gas
reserves, as determined under the provisions of the agreement,
exceeds by a specified amount certain of its obligations
including any outstanding debt and the aggregate
out-of-the-money positions on hedges entered into under the
credit agreement. Exploration & Production is subject
to additional covenants under the credit agreement including
restrictions on hedge limits, the creation of liens, the
incurrence of debt, the sale of assets and properties, and
making certain payments, such as dividends, under certain
circumstances.
On April 4, 2007, Northwest Pipeline retired
$175 million of 8.125 percent senior notes due 2010.
Northwest Pipeline paid premiums of approximately
$7 million in conjunction with the early debt retirement.
On April 5, 2007, Northwest Pipeline issued
$185 million aggregate principal amount of
5.95 percent senior unsecured notes due 2017 to certain
institutional investors in a private debt placement. Northwest
Pipeline initiated an exchange offer on July 26, 2007,
which expired on August 23, 2007. Northwest Pipeline
received full participation in the exchange offer. (See
Note 11 of Notes to Consolidated Financial Statements.)
In July 2007, our Board of Directors authorized the repurchase
of up to $1 billion of our common stock. We intend to
purchase shares of our stock from time to time in open market
transactions or through privately negotiated or structured
transactions at our discretion, subject to market conditions and
other factors. This stock-repurchase program does not have an
expiration date. We plan to fund this program with cash on hand.
In 2007, we purchased approximately 16 million shares for
$526 million under the program at an average cost of $33.08
per share.
During third-quarter 2007, we formed Williams Pipeline Partners
L.P. (WMZ) to own and operate natural gas transportation and
storage assets. In January 2008, WMZ completed its initial
public offering of 16.25 million common units at a price of
$20.00 per unit. In February 2008, the underwriters also
exercised their right to purchase an additional
1.65 million common units at the same price. A subsidiary
of ours serves as the general partner of WMZ. The initial asset
of the partnership is a 35 percent interest in Northwest
Pipeline GP, formerly Northwest Pipeline Corporation. Upon
completion of the transaction, we hold approximately
47.7 percent of the interests in WMZ, including the
interests of the general partner.
In December 2007, Williams Partners L.P. acquired certain of our
membership interests in Wamsutter LLC, the limited liability
company that owns the Wamsutter system, from us for
$750 million. Williams Partners L.P. completed the
transaction after successfully closing a public equity offering
of 9.25 million common units that yielded net proceeds of
approximately $335 million. The partnership financed the
remainder of the purchase price primarily through utilizing
$250 million of term loan borrowings and issuing
approximately $157 million of common units to us. The
$250 million term loan is under Williams Partners
L.P.’s new $450 million five-year senior unsecured
credit facility that became effective simultaneous with the
closing of the Wamsutter transaction. The remaining
$200 million of capacity under the new facility is
available for revolving credit borrowings.
In December 2007, we repurchased $213 million of our
7.125 percent senior unsecured notes due September 2011 and
$22 million of our 8.125 percent senior unsecured
notes due March 2012. In conjunction with these early
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retirements, we paid premiums of approximately $19 million.
These premiums, as well as related fees and expenses are
recorded as early debt retirement costs in the
Consolidated Statement of Income.
On March 19, 2007, Standard & Poor’s raised
our senior unsecured debt rating from a BB− to a BB with a
stable ratings outlook. On May 21, 2007,
Standard & Poor’s revised its ratings outlook to
positive from stable. On November 9, 2007,
Standard & Poor’s raised our senior unsecured
debt rating from a BB to a BB+ and our corporate credit rating
from a BB+ to a BBB− with a ratings outlook of stable.
With respect to Standard & Poor’s, a rating of
“BBB” or above indicates an investment grade rating. A
rating below “BBB” indicates that the security has
significant speculative characteristics. A “BB” rating
indicates that Standard & Poor’s believes the
issuer has the capacity to meet its financial commitment on the
obligation, but adverse business conditions could lead to
insufficient ability to meet financial commitments.
Standard & Poor’s may modify its ratings with a
“+” or a “− ” sign to show the
obligor’s relative standing within a major rating category.
On May 21, 2007, Moody’s Investors Service placed our
ratings under review for possible upgrade. On November 15,
2007, Moody’s Investors Service raised our senior unsecured
debt rating from a Ba2 to a Baa3 with a ratings outlook of
stable. With respect to Moody’s, a rating of
“Baa” or above indicates an investment grade rating. A
rating below “Baa” is considered to have speculative
elements. A “Ba” rating indicates an obligation that
is judged to have speculative elements and is subject to
substantial credit risk. The “1”, “2” and
“3” modifiers show the relative standing within a
major category. A “1” indicates that an obligation
ranks in the higher end of the broad rating category,
“2” indicates a mid-range ranking, and “3”
ranking at the lower end of the category.
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