WILLIAMS COMPANIES, INC.
10-Ks and 10-Qs
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Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C. 20549
Washington, D.C. 20549
Form 10-K
| (Mark One) | ||
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the fiscal year ended December 31, 2009 | ||
|
or
|
||
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period from to | ||
Commission file number 1-4174
The Williams Companies,
Inc.
(Exact name of Registrant as
Specified in Its Charter)
|
Delaware
(State or Other Jurisdiction of Incorporation or Organization) |
73-0569878
(IRS Employer Identification No.) |
|
|
One Williams Center, Tulsa, Oklahoma
(Address of Principal Executive Offices) |
74172
(Zip Code) |
918-573-2000
(Registrant’s Telephone
Number, Including Area Code)
Securities registered pursuant
to Section 12(b) of the Act:
|
Name of Each Exchange
|
||
|
Title of Each Class
|
on Which Registered
|
|
|
Common Stock, $1.00 par value
|
New York Stock Exchange | |
|
Preferred Stock Purchase Rights
|
New York Stock Exchange |
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 whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes
þ
No
o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405) 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):
|
Large accelerated
filer
þ
|
Accelerated filer o |
Non-accelerated
filer
o
(Do not check if a smaller reporting company) |
Smaller reporting company o |
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 $9,096,736,726.
The number of shares outstanding of the registrant’s common
stock outstanding at February 19, 2010 was 583,598,142.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statement for
the Registrant’s 2010 Annual Meeting of Stockholders to be
held on May 20, 2010, are incorporated into Part III,
as specifically set forth in Part III.
THE
WILLIAMS COMPANIES, INC.
FORM 10-K
FORM 10-K
TABLE OF
CONTENTS
i
Table of Contents
DEFINITIONS
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.
TBtu
— means one trillion BTUs.
ii
Table of Contents
| Item 1. | Business |
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.”
WEBSITE
ACCESS TO REPORTS AND OTHER INFORMATION
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 100 F Street,
N.E., 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
Corporate Secretary, One Williams Center, Suite 4700,
Tulsa, Oklahoma 74172.
GENERAL
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, Eastern Seaboard, and the province of Alberta in Canada.
Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172. Our telephone number is
918-573-2000.
In 2009, we used 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.
STRATEGIC
RESTRUCTURING
On February 17, 2010, we completed a strategic
restructuring, which involved contributing a substantial
majority of our domestic midstream and gas pipeline businesses,
including our limited- and general-partner interests in Williams
Pipeline Partners L.P. (WMZ), into Williams Partners L.P. (WPZ).
As consideration for the asset contributions, we received
proceeds from WPZ’s debt issuance of approximately
$3.5 billion, less WPZ’s transaction fees and
expenses, as well as 203 million WPZ Class C units,
which are identical to common units, except for a prorated
initial distribution. We also maintained our 2 percent
general-partner interest. WPZ assumed
1
Economic
Value
Added
®
(EVA
®
)
is a registered trademark of Stern, Stewart & Co.
1
Table of Contents
approximately $2 billion of existing debt associated with
the gas pipeline assets. In connection with the restructuring,
we retired $3 billion of our debt and paid
$574 million in related premiums. These amounts, as well as
other transaction costs, were primarily funded with the cash
consideration received from WPZ. As a result of our
restructuring, we are better positioned to drive additional
growth and pursue value-adding growth strategies. Our new
structure is designed to lower capital costs, enhance reliable
access to capital markets, and create a greater ability to
pursue development projects and acquisitions. (See Note 19
of Notes to Consolidated Financial Statements.)
In conjunction with the restructuring, WPZ has announced its
intention to launch an exchange offer for the publicly traded
common units of WMZ at a future date. WPZ will offer a fixed
exchange ratio of 0.7584 of its common units for each WMZ common
unit. The ratio is based on closing prices on the New York Stock
Exchange on Friday, January 15, 2010, the business day
before WPZ’s intention to make the exchange offer was
announced, of $23.35 for WMZ and $30.79 for WPZ. The exact
timing of the launch will be based upon the filing of necessary
offering documents with the SEC and upon market conditions. If
WPZ acquires ownership of more than 75% of WMZ’s
outstanding common units pursuant to this offer, WPZ will
consider causing the general partner of WMZ to
(i) deregister WMZ under the Exchange Act or cause its
common units to no longer be traded on the New York Stock
Exchange, if these options are available, (ii) exercise its
right under the WMZ’s limited partnership agreement to
purchase all of the remaining common units or
(iii) exercise any other available options.
Beginning with reporting of first-quarter 2010 results, we will
change our segment reporting structure to align with the new
parent-level focus, resource allocation management and related
governance provisions resulting from the restructuring. Our
reporting segments will be Williams Partners,
Exploration & Production, and Other.
Exploration & Production will include our current Gas
Marketing Services (Gas Marketing) segment and Other will
include certain midstream and gas pipeline businesses that were
not contributed to WPZ, such as our Canadian and olefins
midstream businesses and the remaining 25.5 percent
interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream),
as well as corporate operations.
Information in this report has generally been prepared to be
consistent with the reportable segment presentation in our
consolidated financial statements in Part II, Item 8
of this document, which reflects our segment reporting structure
prior to the restructuring. These segments are discussed in
further detail in the following sections.
FINANCIAL
INFORMATION ABOUT SEGMENTS
See “Item 8 — Financial Statements and
Supplementary Data — Notes to Consolidated Financial
Statements — Note 18” of our Notes to
Consolidated Financial Statements for information with respect
to each segment’s revenues, profits or losses and total
assets.
BUSINESS
SEGMENTS
Substantially all our operations are conducted through our
subsidiaries. To achieve organizational and operating
efficiencies, our activities in 2009 were primarily operated
through the following business segments:
| • | Exploration & Production — produces, develops and manages natural gas reserves primarily located in the Rocky Mountain and Mid-Continent regions of the United States and is comprised of several wholly owned and partially owned subsidiaries including Williams Production Company, LLC, and Williams Production RMT Company (RMT). | |
| • | Gas Pipeline — includes our interstate natural gas pipelines and pipeline joint venture investments organized under our wholly owned subsidiary, Williams Gas Pipeline Company, LLC (WGP). Gas Pipeline also includes Williams Pipeline Partners L.P. (WMZ), our master limited partnership formed in 2007. | |
| • | Midstream Gas & Liquids — includes our natural gas gathering, treating and processing business and is comprised of several wholly owned and partially owned subsidiaries including Williams Field Services Group, LLC and Williams Natural Gas Liquids, Inc. Midstream Gas & Liquids (Midstream) also includes Williams Partners L.P. (WPZ), our master limited partnership formed in 2005. |
2
Table of Contents
| • | Gas Marketing Services — manages our natural gas commodity risk through purchases, sales and other related transactions, under our wholly owned subsidiary Williams Gas Marketing, Inc. | |
| • | Other — primarily consists of corporate operations. |
This report is organized to reflect this structure.
Detailed discussion of each of our business segments follows.
Exploration &
Production
Our Exploration & Production segment produces,
develops, and manages natural gas reserves primarily located in
the Rocky Mountain (primarily Colorado, New Mexico, and
Wyoming), Mid-Continent (Oklahoma and Texas), and Appalachian
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, Fort Worth, and Appalachian basins.
Over 99 percent of our domestic reserves are natural gas.
We also have international oil and gas interests, which include
a 69 percent equity interest in Apco Oil and Gas
International Inc. (formerly Apco Argentina Inc., NASDAQ listed:
APAGF), an oil and gas exploration and production company with
operations in South America. If combined with our domestic
proved reserves, our international interests would make up
approximately 4 percent of our total proved reserves.
Considering this, the reserves information included in this
section relates only to our domestic activity.
Our goal is to continue to drill our existing proved undeveloped
reserves, which comprise approximately 44 percent of proved
reserves, and to drill in areas of probable and possible
reserves in order to add to our proved reserves. Our current
proved, probable, and possible reserves inventory provides us
with strong capital investment opportunities for many years into
the future.
On January 14, 2009, the SEC issued the
Final Rule for
Modernization of Oil and Gas Reporting
which modifies how
oil and gas companies report reserves estimates. We have adopted
the revised SEC oil and gas reporting requirements, effective as
of December 31, 2009, with the following effects:
| • | Applying the expanded definition of oil and gas reserves used for reserves estimation supported by reliable technologies and reasonable certainty. | |
| • | Choosing to disclose two alternative reserves sensitivity scenarios. | |
| • | Revising proved undeveloped reserves estimates based on new guidance. | |
| • | Estimating reserves for SEC disclosure using the 12-month average, first-of-the-month price instead of a single-day, period-end price. | |
| • | Incorporating certain additional disclosures around proved undeveloped reserves, internal controls used to ensure objectivity of the estimation process, and qualifications of those preparing and/or auditing the reserves. |
Oil
and Gas Reserves
Reserves information is reported as gas equivalents, since oil
volumes are insignificant. Reserves are more than 99 percent
natural gas for all periods indicated.
Summary of oil and gas reserves:
| December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Bcfe) | ||||||||||||
|
Proved developed reserves
|
2,387 | 2,456 | 2,252 | |||||||||
|
Proved undeveloped reserves
|
1,868 | 1,883 | 1,891 | |||||||||
|
Total proved reserves
|
4,255 | 4,339 | 4,143 | |||||||||
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 with the Department of Energy
(DOE) and the SEC. The estimates furnished to the DOE have been
consistent with those furnished to the SEC.
3
Table of Contents
Proved
reserves sensitivities price scenario
The new SEC rules allow for reserves sensitivity analysis using
alternate price and cost criteria as shown below. The SEC case
was derived using the
12-month
average,
first-of-the-month
Henry Hub spot price of $3.87 per MMbtu, adjusted for locational
price differentials. Neither of the sensitivity scenarios was
audited by a third party. All three cases assume that proved
undeveloped reserves are drilled within five years. No changes
were made to capital expenditures or operating costs in the
sensitivity scenarios.
| SEC Case | Sensitivity 1 | Sensitivity 2 | ||||||||||
|
Basin
|
(Bcfe) | |||||||||||
|
Piceance
|
3,207 | 3,430 | 3,455 | |||||||||
|
San Juan
|
467 | 491 | 505 | |||||||||
|
Powder River
|
304 | 349 | 356 | |||||||||
|
Mid-Continent
|
210 | 228 | 231 | |||||||||
|
Other
|
67 | 83 | 85 | |||||||||
|
Total
|
4,255 | 4,581 | 4,632 | |||||||||
Sensitivity 1: Reflects proved reserves estimated by adding
$1.00 to each of the basin prices from the SEC case.
Sensitivity 2: Reflects proved reserves estimated using prices
from the prior year-end, which were calculated using the
December 31, 2008, NYMEX Henry Hub posted price of $5.71
per MMbtu, adjusted for locational price differentials.
The chart below shows the year-end 2009 SEC case compared to the
two alternate price scenarios. Also shown is the impact the new
SEC reserves rules had on 2009 proved reserves.
Proved
U.S. Reserves Reconciliation
4
Table of Contents
The new SEC reporting rules require that year-end proved reserve
volumes are calculated using an average price for the full-year
2009, rather than the year-end price. This resulted in
utilization of a basin price approximately 33 percent lower
than the previous year which resulted in a downward price
revision of 336 Bcfe.
Under the new rules, reserves generally cannot be classified as
proved if they have not or will not be developed within five
years according to planned drilling activity and taking into
account anticipated proved undeveloped conversion rates for
wells drilled. This rule change resulted in reclassification of
496 Bcfe of reserves from proved undeveloped to probable.
Additionally, the new rules now allow adding undeveloped proved
reserves locations that are more than one offset away from
currently producing wells where there is reasonable certainty of
production. This rule change resulted in the addition of
454 Bcfe of proved reserves.
Also shown on the chart is 570 Bcfe of net
additions/revisions to our proved reserves through drilling
882 gross wells in 2009 at a capital cost of approximately
$878 million.
Reserves
estimation process
The engineering staff of each basin asset team provides the
reserves modeling and forecasts for their respective areas.
Various departments also participate in the preparation of the
year-end reserves estimate. These departments provide supporting
information such as pricing, ownership, gas gathering and gas
quality. The departments and their roles in the year-end
reserves process are coordinated by our reserves analysis
department. The reserves analysis department’s
responsibilities also include: working with the third-party
consultants and the asset teams to successfully complete the
third-party reserves audit, performing an internal review of
reserves data for reasonableness and accuracy, finalizing the
year-end reserves report, and reporting reserves data to
accounting.
The preparation of our year-end reserves report is a formal
process. We begin with a review of the existing process to
identify where improvements can be made. Our internal processes
and controls, as they relate to the year-end reserves, are
reviewed and updated. Each asset teams’ reserves
engineering and geological technical staffs, the reserves
analysis team, and the third-party engineering consultants meet
to begin the year-end process and audit. The asset teams’
reserves staff, the reserves analysis team and the third-party
engineering consultants exchange data and interpretations in
furtherance of the completion of the year-end reserves
estimates. The reserves analysis team met twice with the Audit
Committee of our Board of Directors to report on the progress of
its analysis of our 2009 reserves, allowing the Audit Committee
the opportunity to review and comment on management’s
processes and conclusions.
Approximately 99 percent of our total year-end 2009
domestic proved reserves estimates were audited 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
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 Reserves Information
promulgated by the Society of Petroleum Engineers. NSAI is
satisfied with our methods and procedures in preparing the
December 31, 2009, reserves estimates and noted nothing of
an unusual nature that would cause NSAI to take exception with
the estimates, in the aggregate, as prepared by us. The report
of NSAI is included as Exhibit 99.1 to this
Form 10-K.
In addition, reserves estimates related to properties underlying
the Williams Coal Seam Gas Royalty Trust, of which our ownership
in the Trust represents approximately 1 percent of our
total domestic proved reserves estimates, were prepared by
Miller and Lents, LTD. The report of Miller and Lents is
included as Exhibit 99.2 to this
Form 10-K.
The reserves estimates resulting from the above process are
subjected to both internal and external checks and controls to
promote transparency and accuracy of the year-end reserves
estimates. Our internal control documentation provides further
confirmation on the checks and controls. Our internal reserves
analysis team is independent and does not work within an asset
team or report directly to anyone on the asset teams. The
compensation of our reserves analysis team is not linked to
reserves additions or revisions.
5
Table of Contents
The technical person primarily responsible for overseeing
preparation of the reserves estimates and the third- party
reserves audit is the Director of Reserves and Production
Services. The Director’s qualifications include
27 years of reserves evaluation experience, a B.S. in
geology from the University of Texas at Austin, an M.S. in
physical sciences from the University of Houston, and membership
in the American Association of Petroleum Geologists, and The
Society of Petroleum Engineers.
Proved
undeveloped reserves
Our proved undeveloped reserves as of December 31, 2009,
are 1,868 Bcfe and 1,883 Bcfe as of December 31,
2008, a net decrease of approximately 15 Bcfe. See
additional discussion of proved undeveloped reserves in our
sensitivity analysis.
The vast majority of our reserves is concentrated in
unconventional tight gas sands, shale gas and coal bed gas
reservoirs. We use available geoscience and engineering data to
establish drainage areas and continuity of reservoir beyond one
direct offset from a producing well, which provides additional
proved undeveloped bookings in fields where the evidence
supported the methodology. Inherent in the methodology was a
requirement for significant well density of economically
producing wells to establish those bookings with reasonable
certainty. In fields where producing wells were less dense, only
direct offsets from proved producing wells were assigned the
proved undeveloped reserves classification.
Oil
and Gas Properties and Production, Production Prices and
Production Costs
The following table summarizes our domestic sales and cost
information for the years indicated:
| 2009 | 2008 | 2007 | ||||||||||
| (Bcfe)(1) | ||||||||||||
|
Piceance
|
254.6 | 237.7 | 196.9 | |||||||||
|
San Juan
|
53.1 | 52.8 | 53.4 | |||||||||
|
Powder River
|
88.9 | 83.6 | 61.9 | |||||||||
|
Mid-Continent
|
29.6 | 21.7 | 16.9 | |||||||||
|
Other
|
5.3 | 4.6 | 4.0 | |||||||||
|
Total net production sold
|
431.5 | 400.4 | 333.1 | |||||||||
|
Average production costs excluding production taxes ($/Mcfe)(2)
|
$ | 0.60 | $ | 0.66 | $ | 0.62 | ||||||
|
Average sales price ($/Mcfe)
|
$ | 2.79 | $ | 6.39 | $ | 4.92 | ||||||
|
Realized gain on hedging contracts ($/Mcfe)
|
$ | 1.43 | $ | 0.09 | $ | 0.16 | ||||||
|
Net Realized Average Price ($/Mcfe)
|
$ | 4.22 | $ | 6.48 | $ | 5.08 | ||||||
| (1) | Sales and cost information are reported in gas equivalents instead of oil equivalents since oil volumes are insignificant. Production is over 99 percent natural gas for all three years indicated. | |
| (2) | Includes lease and other operating expense and facility operating expense. |
Drilling
and Exploratory Activities
We focus on lower-risk development drilling. Our development
drilling success rate was approximately 99 percent in each
of 2009, 2008, and 2007.
6
Table of Contents
The following table summarizes domestic drilling activity by
number and type of well for the periods indicated:*
| 2009 | 2008 | 2007 | ||||||||||||||||||||||
| Gross Wells | Net Wells | Gross Wells | Net Wells | Gross Wells | Net Wells | |||||||||||||||||||
|
Piceance
|
349 | 303 | 687 | 624 | 572 | 539 | ||||||||||||||||||
|
San Juan
|
77 | 39 | 95 | 37 | 146 | 50 | ||||||||||||||||||
|
Powder River
|
233 | 95 | 702 | 324 | 633 | 255 | ||||||||||||||||||
|
Mid-Continent
|
43 | 41 | 82 | 62 | 75 | 48 | ||||||||||||||||||
|
Other
|
173 | 8 | 216 | 3 | 151 | 3 | ||||||||||||||||||
|
Productive exploration
|
3 | 1 | 4 | 2 | 4 | 3 | ||||||||||||||||||
|
Nonproductive, including exploration
|
4 | 1 | 1 | 0 | 9 | 5 | ||||||||||||||||||
|
Total
|
882 | 488 | 1,787 | 1,052 | 1,590 | 903 | ||||||||||||||||||
| * | 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. All of the wells drilled were natural gas wells. |
In 2009, there were two gross nonproductive exploratory wells
and one net nonproductive exploratory well. Total gross operated
wells drilled were 472 in 2009, 1,125 in 2008, and 1,112 in 2007.
Present
Activities
At December 31, 2009, we had 42 gross (14 net) wells
in the process of being drilled.
Delivery
Commitments
We hold a long-term obligation, through our Gas Marketing
segment, to deliver on a firm basis 200,000 MMBtu/d of gas
to a buyer at the White River Hub (Greasewood-Meeker, Colorado),
which is the major market hub exiting the Piceance basin. The
Piceance, being our largest producing basin, holds ample
reserves to fulfill this obligation without risk of
nonperformance during periods of normal infrastructure and
market operations. While the daily volume of gas is large and
represents a significant percentage of our daily production,
this transaction does not represent a material exposure.
Oil
and Gas Properties, Wells, Operations, and Acreage
The table below summarizes 2009 producing wells and production
by area:*
|
Wells
|
Wells
|
Net
|
||||||||||
|
Producing
|
Producing
|
Production
|
||||||||||
| (Gross) | (Net) | (Bcfe) | ||||||||||
|
Piceance
|
3,496 | 3,202 | 257 | |||||||||
|
San Juan
|
3,220 | 871 | 55 | |||||||||
|
Powder River
|
6,025 | 2,722 | 88 | |||||||||
|
Mid-Continent
|
671 | 451 | 29 | |||||||||
|
Other
|
737 | 27 | 6 | |||||||||
|
Total
|
14,149 | 7,273 | 435 | |||||||||
| * | 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. All of the wells drilled were natural gas wells. Volumes are reported in gas equivalents since any liquids produced are a by-product of the natural gas wells. |
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At December 31, 2009, there were 181 gross and
106 net producing wells with multiple completions.
The following table summarizes our leased acreage as of
December 31, 2009:
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross Acres | Net Acres | Gross Acres | Net Acres | Gross Acres | Net Acres | |||||||||||||||||||
|
Piceance
|
129,063 | 99,965 | 180,744 | 119,798 | 309,808 | 219,763 | ||||||||||||||||||
|
San Juan
|
237,587 | 119,345 | 2,100 | 1,576 | 239,688 | 120,921 | ||||||||||||||||||
|
Powder River
|
502,455 | 228,582 | 421,378 | 195,422 | 923,833 | 424,004 | ||||||||||||||||||
|
Mid-Continent
|
117,314 | 75,940 | 147,403 | 75,481 | 264,716 | 151,421 | ||||||||||||||||||
|
Other
|
30,029 | 5,111 | 549,591 | 309,242 | 579,619 | 314,353 | ||||||||||||||||||
|
Total
|
1,016,448 | 528,943 | 1,301,216 | 701,519 | 2,317,664 | 1,230,462 | ||||||||||||||||||
Piceance
basin
The Piceance basin is located in northwestern Colorado and is
our largest area of concentrated development. During 2009 we
operated an average of 10.3 drilling rigs in the basin. This
area has approximately 1972 undrilled proved locations in
inventory. Within this basin we own and operate natural gas
gathering facilities including some 300 miles of gathering
lines and associated field compression. Approximately
85 percent of the gas gathered is our own equity
production. The gathering system also includes 5 processing
plants and associated treating facilities for a total capacity
of 1.15 Bcf/d. During 2009, these plants recovered
approximately 6.3 million gallons of natural gas liquids
(NGLs) each month, which were marketed separately from the
residue natural gas.
In addition to our own operated facilities, Midstream owns and
operates a new cryogenic processing plant, Willow Creek, which
currently has a capacity of
450 MMcf/d
and reprocesses that amount of gas, recovering an average of
12.6 million additional gallons of NGLs per month, 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. We provide a significant amount of equity
production that is gathered
and/or
processed by Midstream’s facilities in the San Juan
basin.
Powder
River basin
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.
Mid-Continent
properties
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
Other properties are primarily comprised of interests in the
Green River basin in southwestern Wyoming and the Appalachian
basin (Marcellus Shale) in Pennsylvania. Also included is
exploration activity and other miscellaneous activity.
Hedging
Activity
To manage the commodity price risk and volatility of owning
producing gas properties, we enter into derivative contracts for
a portion of our expected future production. See further
discussion in
Management’s Discussion and Analysis of
Financial Condition and Results of Operations —
Exploration & Production
, included in Item 7
of this
Form 10-K.
8
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Acquisitions &
Divestitures
In June 2009, we entered into an agreement that allows us to
acquire, through a “drill to earn” structure, a
50 percent interest in approximately 44,000 net acres
in Pennsylvania’s Marcellus Shale in the Appalachian basin.
This agreement requires us to fund $33 million of drilling
and completion costs on behalf of our partner and
$41 million of our own costs and expenses prior to the end
of 2011 to earn our 50 percent interest. This growth
opportunity leverages our experience in developing
nonconventional natural gas reserves. Through December 2009, we
have funded $14 million of the $33 million.
In September 2009, we completed the purchase of additional
unproved leasehold acreage and proved properties in the Piceance
basin for $253 million. In December 2009, we increased our
working interest in these properties through a $22 million
acquisition.
Through other transactions totaling approximately
$36 million, Exploration & Production expanded
its acreage position and producing properties in the
Fort Worth basin (Barnett Shale), the Appalachian basin
(Marcellus Shale), the Arkoma basin (Woodford Shale), as well as
exploration leaseholds in the Paradox basin.
Other
Information
In 1993, Exploration & Production conveyed a net
profits interest in certain of its properties to the Williams
Coal Seam Gas Royalty Trust (“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 March 1, 2010, we
expect to own 789,291 trust units. Based on certain provisions
of the Trust agreement, the Trust is expected to terminate on
March 1, 2010. Upon termination, the net profits interest
will be placed for sale and we will receive proceeds from the
sale less applicable expenses in direct proportion to the Trust
units owned. This transaction is expected to have a minimal
impact to our financial statements.
Gas
Pipeline
We own and operate a combined total of approximately
13,900 miles of pipelines with a total annual throughput of
approximately 2,700 TBtu of natural gas and
peak-day
delivery capacity of approximately 12 MMdt of gas. Gas
Pipeline consists of Transcontinental Gas Pipe Line Company, LLC
(Transco) and Northwest Pipeline GP (Northwest Pipeline). Gas
Pipeline also holds interests in joint venture interstate and
intrastate natural gas pipeline systems including a
50 percent interest in Gulfstream. Gas Pipeline also
includes WMZ.
Transco
Transco is an interstate natural gas transportation company that
owns and operates a 10,000-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,
Washington, D.C., New York, New Jersey, and Pennsylvania.
Pipeline
system and customers
At December 31, 2009, 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 3.9 MMdt of
natural gas per day for a system-wide delivery capacity total of
approximately 8.6 MMdt of natural gas per day.
Transco’s system includes 45 compressor stations, four
underground storage fields, and a liquefied natural gas (LNG)
storage facility. Compression facilities at 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
9
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marketers and producers. One customer accounted for
approximately 11 percent and another customer accounted for
approximately 10 percent of Transco’s total revenues
in 2009. 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 four underground
storage fields located on or near its pipeline system or market
areas and operates two of these storage fields. Transco also has
storage capacity in an LNG storage facility that they own and
operate. 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 204 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, a LNG storage facility with 4 billion cubic feet of
storage 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.
Transco
expansion projects
The pipeline projects listed below were completed during 2009 or
are significant future pipeline projects for which we have
customer commitments.
Sentinel
Expansion Project
The Sentinel Expansion Project is a recently completed 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 $229 million. Phase I was placed into
service in December 2008. Phase II was placed into service
in November 2009.
Mobile
Bay South Expansion Project
The Mobile Bay South Expansion Project involves the addition of
compression at Transco’s Station 85 in Choctaw County,
Alabama, to allow Transco to provide firm transportation service
southbound on the Mobile Bay line from Station 85 to various
delivery points. In May 2009, Transco received approval from the
Federal Energy Regulatory Commission (FERC). The capital cost of
the project is estimated to be approximately $37 million.
Transco plans to place the project into service by May 2010.
Mobile
Bay South II Expansion Project
The Mobile Bay South II Expansion Project involves the
addition of compression at Transco’s Station 85 in Choctaw
County, Alabama, and modifications to existing facilities at
Transco’s Station 83 in Mobile County, Alabama, to allow
Transco to provide additional firm transportation service
southbound on the Mobile Bay line from Station 85 to various
delivery points. In November 2009, Transco filed an application
with the FERC. The capital cost of the project is estimated to
be approximately $36 million. Transco plans to place the
project into service by May 2011.
85
North Expansion Project
The 85 North Expansion Project involves an expansion of our
existing natural gas transmission system from Station 85 in
Choctaw County, Alabama, to various delivery points as far north
as North Carolina. In September 2009, Transco received approval
from the FERC. The capital cost of the project is estimated to
be $241 million. Transco plans to place the project into
service in phases, in July 2010 and May 2011.
Mid-South
Expansion Project
The Mid-South Expansion Project involves an expansion of
Transco’s mainline from Station 85 in Choctaw County,
Alabama, to markets as far downstream as North Carolina. Transco
anticipates filing an
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application with the FERC in the fourth quarter of 2010. The
capital cost of the project is estimated to be approximately
$200 million. Transco plans to place the project into
service in September 2012.
Mid-Atlantic
Connector Project
The Mid-Atlantic Connector Project involves an expansion of
Transco’s mainline from an existing interconnection with
East Tennessee Natural Gas in North Carolina to markets as far
downstream as Maryland. Transco anticipates filing an
application with the FERC in the first quarter of 2011. The
capital cost of the project is estimated to be approximately
$55 million. Transco plans to place the project into
service in November 2012.
Rockaway
Delivery Lateral Project
The Rockaway Delivery Lateral Project involves the construction
of a
three-mile
offshore lateral to National Grid’s distribution system in
New York. Transco anticipates filing an application with the
FERC in the third quarter of 2010. The capital cost of the
project is estimated to be approximately $120 million.
Transco plans to place the project into service in November 2013.
Operating
statistics
The following table summarizes transportation data for the
Transco system for the periods indicated:
| 2009 | 2008 | 2007 | ||||||||||
| (In TBtu) | ||||||||||||
|
Market-area deliveries:
|
||||||||||||
|
Long-haul transportation
|
624 | 753 | 839 | |||||||||
|
Market-area transportation
|
1,093 | 969 | 875 | |||||||||
|
Total market-area deliveries
|
1,717 | 1,722 | 1,714 | |||||||||
|
Production-area transportation
|
184 | 188 | 190 | |||||||||
|
Total system deliveries
|
1,901 | 1,910 | 1,904 | |||||||||
|
Average Daily Transportation Volumes
|
5.2 | 5.2 | 5.2 | |||||||||
|
Average Daily Firm Reserved Capacity
|
6.8 | 6.8 | 6.6 | |||||||||
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 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
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.
Pipeline
system and customers
At December 31, 2009, Northwest Pipeline’s system,
having long-term firm transportation agreements including
peaking service of approximately 3.7 Bcf 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.
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In 2009, Northwest Pipeline served a total of 127 transportation
and storage customers. Northwest Pipeline transports and stores
natural gas for a broad mix of customers, including local
natural gas distribution companies, municipal utilities, direct
industrial users, electric power generators and natural gas
marketers and producers. The two largest customers of Northwest
Pipeline in 2009 accounted for approximately 22 percent and
12 percent, respectively, of its total operating revenues.
No other customer accounted for more than 10 percent of
Northwest Pipeline’s total operating revenues in 2009.
Northwest Pipeline’s firm transportation and storage
contracts are generally long-term contracts 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 700 MMcf of gas per
day.
Northwest
Pipeline expansion projects
The pipeline projects listed below were completed during 2009 or
are significant future pipeline projects for which we have
customer commitments.
Colorado
Hub Connection Project
In November 2009, Northwest Pipeline placed into service the new
27-mile,
24-inch
diameter lateral referred to as the Colorado Hub Project (CHC
Project). The new lateral connects the Meeker/White River Hub
near Meeker, Colorado to its mainline south of Rangely,
Colorado, and is estimated to cost up to $60 million. The
CHC Project combined the new lateral capacity with existing
mainline capacity to provide approximately 363 Mdth per day of
firm transportation from various receipt points to delivery
points on the mainline as far south as Ignacio, Colorado. In
April 2009, the FERC issued a certificate approving the CHC
Project, including the presumption of rolling in the costs of
the project in any future rate case filed with the FERC.
Sundance
Trail Expansion
In November 2009, Northwest Pipeline received approval from the
FERC to construct approximately 16 miles of
30-inch
loop
between Northwest Pipeline’s existing Green River and Muddy
Creek compressor stations in Wyoming as well as an upgrade to
Northwest Pipeline’s existing Vernal compressor station,
with service targeted to commence in November 2010. The total
project is estimated to cost up to $65 million, including
the cost of replacing the existing compression at Vernal, which
will enhance the efficiency of Northwest Pipeline’s system.
Northwest Pipeline executed a precedent agreement to provide 150
Mdth per day of firm transportation service from the Greasewood
and Meeker Hubs in Colorado for delivery to the Opal Hub in
Wyoming. Northwest Pipeline has proposed to collect its maximum
system rates, and has received approval from the FERC to roll-in
the Sundance Trail Expansion costs in any future rate cases.
Operating
statistics
The following table summarizes volume and capacity data for the
Northwest Pipeline system for the periods indicated:
| 2009 | 2008 | 2007 | ||||||||||
| (In TBtu) | ||||||||||||
|
Total Transportation Volume
|
769 | 781 | 757 | |||||||||
|
Average Daily Transportation Volumes
|
2.1 | 2.1 | 2.1 | |||||||||
|
Average Daily Reserved Capacity Under Base Firm Contracts,
excluding peak capacity
|
2.7 | 2.5 | 2.5 | |||||||||
|
Average Daily Reserved Capacity Under Short-Term Firm
Contracts(1)
|
0.5 | 0.7 | 0.8 | |||||||||
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| (1) | Consists primarily of additional capacity created from time to time through the installation of new receipt or delivery points or the segmentation of existing mainline capacity. Such capacity is generally marketed on a short-term firm basis. |
Gulfstream
Gulfstream is a natural gas pipeline system extending from the
Mobile Bay area in Alabama to markets in Florida. Gas Pipeline
and Spectra Energy, through their respective subsidiaries, each
holds a 50 percent ownership interest in Gulfstream and
provides operating services for Gulfstream. At December 31,
2009, our equity investment in Gulfstream was $383 million.
Gulfstream
expansion projects
Gulfstream placed the Phase III expansion project in
service on September 1, 2008. The project extended the
pipeline system into South Florida and fully subscribed the
remaining 345 Mdt/d of firm capacity on the existing pipeline
system on a long-term basis. The capital cost of this project
was $118 million, with Gas Pipeline’s share being
50 percent of such costs. Service under the Gulfstream
Phase IV expansion project began during the fourth quarter
of 2008. The project is fully subscribed on a long-term basis
and is the first incremental expansion of Gulfstream’s
mainline capacity. The capital cost of this expansion was
$190 million, with Gas Pipeline’s share being
50 percent of such costs. The Phase V expansion involves
the addition of compression to provide 35 Mdt/d of firm capacity
by July 2011. The estimated capital cost of this expansion is
approximately $54 million with Gas Pipeline’s share
being 50 percent of such cost.
WMZ
WMZ was formed to own and operate natural gas transportation and
storage assets. As of December 31, 2009, we own an
approximate 45.7 percent limited partnership interest and a
2 percent general partner interest in WMZ. A subsidiary of
ours, Williams Pipeline GP LLC, serves as the general partner of
WMZ. WMZ owns a 35 percent interest in Northwest Pipeline.
As previously discussed, our overall ownership in WMZ was
affected by our restructuring transactions in 2010. WPZ intends
to make an exchange offer for the publicly held units of WMZ at
a future date. See “Strategic Restructuring” in
Part I, Item 1 of this Form
10-K
for
further discussion of this potential exchange offer.
Midstream
Gas & Liquids
Our Midstream segment, one of the nation’s largest natural
gas gatherers and processors, has primary service areas
concentrated in major producing basins in Colorado, New Mexico,
Wyoming, the Gulf of Mexico, Pennsylvania, 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 raw natural gas and
crude oil from the producing fields 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
petrochemicals, home heating fuels and refinery feedstock.
Key variables for the Midstream business will continue to be:
| • | Retaining and attracting customers by continuing to provide reliable services; | |
| • | Revenue growth associated with additional infrastructure either completed or currently under construction; | |
| • | Disciplined growth in our core service areas and new step-out areas; | |
| • | Prices impacting our commodity-based processing and olefin activities. |
13
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Domestic
Gathering, Processing and Treating
Our domestic gathering systems receive natural gas from
producers’ oil and natural gas wells and gather these
volumes to gas processing, treating or redelivery facilities.
Typically, natural gas, in its raw form, is not acceptable for
transportation in major interstate natural gas pipelines or for
commercial use as a fuel. In addition, natural gas contains
various amounts of NGLs, which generally have a higher value
when separated from the natural gas stream. Our processing and
treating plants remove water vapor, carbon dioxide and other
contaminants and our processing plants extract the NGLs and
olefins. NGL products include:
| • | Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics; | |
| • | Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials and molded plastic parts; | |
| • | Normal butane, iso-butane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock. |
Although a significant portion of our gas processing services
are performed for a volumetric-based fee, a portion of our gas
processing agreements are commodity-based and include two
distinct types of commodity exposure. The first type includes
“keep-whole” processing agreements 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 agreements, we are exposed to the spread
between NGL prices and natural gas prices. The second type
consists of
“percent-of-liquids”
agreements whereby we receive a portion of the extracted liquids
with no direct exposure to the price of natural gas. Under these
agreements, we are only exposed to NGL price movements. NGLs we
retain in connection with both of these types of processing
agreements are referred to as our equity NGL production. Our
gathering and processing agreements have terms ranging from
month-to-month
to the life of the producing lease. Generally, our gathering and
processing agreements are long-term agreements.
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 2009, these operations gathered and
processed gas for approximately 230 gas gathering and processing
customers. Our top 7 gathering and processing customers
accounted for approximately 50 percent of our domestic
gathering and processing revenue.
In addition to our natural gas assets, we own and operate three
deepwater crude oil pipelines and own two production platforms
serving the deepwater Gulf of Mexico. Our crude oil
transportation revenues are typically volumetric-based fee
arrangements. However, a portion of our marketing revenues are
recognized from purchase and sale arrangements whereby we
purchase oil from producers at the receipt points of our crude
oil pipelines for an index-based price and resell the oil at
delivery points at the same index-based price. Our offshore
floating production platform provides centralized services to
deepwater producers such as compression, separation, production
handling, water removal and pipeline landings. Revenue sources
have historically included a combination of fixed-fee,
volumetric-based fee and cost reimbursement arrangements. Fixed
fees associated with the resident production at our Devils Tower
facility are recognized on a
units-of-production
basis.
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
approximately 87 percent of our Exploration &
Production segment’s equity production in this basin. Our
Willow Creek plant, completed in 2009, is currently processing
Exploration & Production segment’s wellhead
production in the Piceance basin. Our San Juan basin,
southwest Wyoming, and Willow Creek systems deliver residue gas
volumes into Northwest Pipeline’s interstate system in
addition to third-party interstate systems.
West
region domestic gathering, processing and treating
We own
and/or
operate domestic gas gathering, processing and treating assets
within the western states of Wyoming, Colorado and New Mexico.
14
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In the Rocky Mountain area, our assets include:
| • | Approximately 3,500 miles of gathering pipelines with a capacity of nearly one Bcf/d and over 4,000 receipt points serving the Wamsutter and southwest Wyoming areas in Wyoming; | |
| • | Opal and Echo Springs processing plants with a combined daily inlet capacity of over 1,800 MMcf/d and NGL processing capacity of nearly 100 Mbbls/d. |
In the Four Corners area, our assets include:
| • | Approximately 3,800 miles of gathering pipelines with a capacity of nearly two Bcf/d and approximately 6,500 receipt points serving the San Juan basin in New Mexico and Colorado; | |
| • | Ignacio, Kutz and Lybrook processing plants with a combined daily inlet capacity of 765 MMcf/d and NGL processing capacity of approximately 40 Mbbls/d. The Ignacio plant also has the capacity to produce slightly more than one Mbbls/d of liquefied natural gas; | |
| • | Milagro and Esperanza natural gas treating plants, which remove carbon dioxide but do not extract NGLs, with a combined daily inlet capacity of 750 MMcf/d. At our Milagro facility, we also use gas-driven turbines to produce approximately 60 mega-watts per day of electricity which we primarily sell into the local electrical grid. |
In the Piceance basin in Colorado, our infrastructure includes:
| • | The Willow Creek processing plant, a 450 MMcf/d cryogenic natural gas processing plant in western Colorado’s Piceance basin, designed to recover 30 Mbbls/d of NGLs. In the third quarter of 2009, construction was finished and the plant began operations. The plant is currently operating at its designed inlet capacity. In the current processing arrangement with Exploration & Production, Midstream receives a volumetric-based processing fee and a percent of the NGLs extracted. | |
| • | Parachute Lateral, a 38-mile, 30-inch diameter line transporting gas from the Parachute area to the Greasewood hub and White River hub in northwest Colorado. Our Willow Creek plant processes gas flowing through the Parachute Lateral. | |
| • | PGX pipeline delivering NGLs previously transported by truck from Exploration & Production’s existing Parachute area processing plants to a major NGL transportation pipeline system. |
West
region expansion projects
Our major capital and expansion projects include additional
capacity at our Echo Springs facility and related gathering
system expansions in the Wamsutter basin. We expect to
significantly increase the processing and NGL production
capacities at our Echo Springs cryogenic natural gas processing
plant in Wyoming. The addition of a fourth cryogenic processing
train will add approximately
350 MMcf/d
of processing capacity and 30 Mbbls/d of NGL production
capacity, nearly doubling Echo Spring’s capacities in both
cases. We began construction on the fourth train at Echo Springs
during the second half of 2009 and expect to bring the
additional capacity online during late 2010.
Gulf
region domestic gathering, processing and treating
We own
and/or
operate domestic gas gathering and processing assets and crude
oil pipelines primarily within the onshore and offshore shelf
and deepwater areas in and around the Gulf Coast states of
Texas, Louisiana, Mississippi, and Alabama. We own:
| • | Over 700 miles of onshore and offshore natural gas gathering pipelines with a combined capacity of approximately 3.5 Bcf/d, including: |
| • | The 115-mile deepwater Seahawk gas pipeline in the western Gulf of Mexico, flowing into our Markham processing plant and serving the Boomvang and Nansen field areas; |
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| • | The 139-mile Canyon Chief gas pipeline, now including the 37-mile Blind Faith extension added in the fourth quarter of 2008, in the eastern Gulf of Mexico, flowing into our Mobile Bay processing plant and serving the Devils Tower, Triton, Goldfinger, Bass Lite and Blind Faith fields; |
| • | Mobile Bay and Markham processing plants with a combined daily inlet capacity of 1,000 MMcf/d and NGL handling capacity of 50 Mbbls/d; | |
| • | Canyon Station production platform, which brings natural gas to specifications allowable by major interstate pipelines but does not extract NGLs, with a daily inlet capacity of 500 MMcf/d; | |
| • | Three deepwater crude oil pipelines with a combined length of 300 miles and capacity of 325 Mbbls/d including: |
| • | BANJO pipeline running parallel to the Seahawk gas pipeline delivering production from two producer-owned spar-type floating production systems; and delivering production to our shallow-water platform at Galveston Area Block A244 (GA-A244) and then onshore through ExxonMobil’s Hoover Offshore Oil Pipeline System (HOOPS); | |
| • | Alpine pipeline in the central Gulf of Mexico, serving the Gunnison field, and delivering production to GA-A244 and then onshore through HOOPS under a joint tariff agreement; | |
| • | Mountaineer oil pipeline which connects to similar production sources as our Canyon Chief pipeline and, now including the new Blind Faith extension, ultimately delivering production to ChevronTexaco’s Empire Terminal in Plaquemines Parish, Louisiana; |
| • | Devils Tower production platform located in Mississippi Canyon Block 773, approximately 150 miles south-southwest of Mobile, Alabama and serving production from the Devils Tower, Triton, Goldfinger and Bass Lite fields. Located in 5,610 feet of water, it is one of the world’s deepest dry tree spars. The platform, which is operated by ENI Petroleum on our behalf, is capable of handling 210 MMcf/d of natural gas and 60 Mbbls/d of oil. |
Gulf
region expansion projects
Our current major expansion project in the Gulf region is our
Perdido Norte project located in the western deepwater of the
Gulf of Mexico. The investment expands our existing
infrastructure and includes a total of 184 miles of deepwater
oil and gas pipeline and a
200 MMcf/d
expansion of our onshore Markham gas processing facility. We
expect the project to begin
start-up
operations in the first quarter of 2010.
Olefins
Gulf
Coast region olefins
In the Gulf of Mexico region, we own a 10/12 interest in and are
the operator of an ethane cracker at Geismar, Louisiana, with a
total production capacity of 1.3 billion pounds of ethylene
and 90 million pounds of propylene per year. 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, respectively. We also own ethane and
propane pipeline systems and a refinery grade propylene splitter
with a production capacity of approximately 500 million
pounds per year of propylene and its related pipeline system in
Louisiana. At our propylene splitter, we 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.
Canadian
region olefins
Our Canadian operations include an oil sands off-gas processing
plant located near Ft. McMurray, Alberta and an NGL/olefin
fractionation facility near Edmonton, Alberta. Our facilities
extract liquids from the off-gas produced by a third-party oil
sands bitumen upgrading process. Our arrangement with the
third-party upgrader is a “keep-whole” type where we
remove a mix of NGLs and olefins from the off-gas and return the
equivalent heating value back to the third party in the form of
natural gas. We then fractionate, treat, store, terminal and
sell the
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propane, propylene, butane, butylenes and condensate recovered
from this process. Our commodity price exposure is the spread
between the price for natural gas and the NGL and olefin
products we produce. We continue to be the only NGL/olefins
fractionator in western Canada and the only treater/processor of
oil sands upgrader off-gas. Our extraction of liquids from
upgrader off-gas streams allows the upgraders to burn cleaner
natural gas streams and reduce their overall air emissions. The
Ft. McMurray 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.
Canadian
olefin expansion projects
In Canada, we expect to begin construction in 2010 on a
261-mile,
12-inch
pipeline which will transport recovered NGLs and olefins from
our processing plant in Ft. McMurray to our fractionation
facility near Edmonton, Alberta. The pipeline will have
sufficient capacity to transport additional NGLs and olefins
from the current arrangement with the third-party oil sands
producer, as well as from other oil-sands producers’
off-gas in the Ft. McMurray area. The project will be
constructed using cash previously generated from Canadian and
other international projects. We anticipate an in-service date
in 2012.
In addition, a project to upgrade the value of one of the
products produced at the fractionators near Edmonton, Alberta,
is expected to be completed in the latter part of 2010. The new
splitter and hydrotreating facilities will take the
butane/butlyene mix product currently produced and further
fractionate the mix product into two higher value products that
are in greater demand in the market place. These new facilities
are also being constructed using cash generated from Canadian
and other international projects.
NGL
and Olefin Marketing Services
In addition to our gathering, processing and olefin production
operations, we market NGLs and olefin products to a wide range
of users in the energy and petrochemical industries. The NGL
marketing business transports and markets equity NGLs from the
production at our domestic processing plants, and also markets
NGLs on behalf of third-party NGL producers, including some of
our fee-based processing customers, and the NGL volumes owned by
Discovery Producer Services LLC. The NGL marketing business
bears the risk of price changes in these NGL volumes while they
are being transported to final sales delivery points. In order
to meet sales contract obligations, we may purchase products in
the spot market for resale. The majority of domestic sales are
based on supply contracts of one year or less in duration. The
production from our Canadian facilities is marketed in Canada
and in the United States.
Other
We own interests in
and/or
operate NGL fractionation and storage assets. These assets
include two partially owned NGL fractionation facilities: one
near Conway, Kansas and the other in Baton Rouge, Louisiana that
have a combined capacity in excess of 167 Mbbls/d. We also
own approximately 20 million barrels of NGL storage
capacity in central Kansas near Conway.
We own an equity interest in and operate the facilities of
Discovery Producer Services LLC and its subsidiary Discovery Gas
Transmission LLC (collectively, Discovery) through our interest
in WPZ. Discovery’s assets include a
600 MMcf/d
cryogenic natural gas processing plant near Larose, Louisiana, a
32 Mbbls/d NGL fractionator plant near Paradis, Louisiana
and an offshore natural gas gathering and transportation system
in the Gulf of Mexico.
We also own a 14.6 percent equity interest in Aux Sable
Liquid Products LP 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 Mbbls/d of extracted liquids into NGL products.
In June 2009, we completed the formation of a new joint venture,
Laurel Mountain Midstream, LLC (Laurel Mountain), in the
Marcellus Shale located in southwest Pennsylvania. Our partner
in the venture contributed its existing Appalachian basin
gathering system, which currently has an average throughput of
approximately
100 MMcf/d.
In exchange for a 51 percent interest in the venture, we
contributed $100 million and issued a
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$26 million note payable. In 2010, we expect to
significantly increase our investment in our Laurel Mountain
joint venture through new gathering system infrastructure
construction.
In conjunction with a long-term agreement with a major producer,
we will construct a
28-mile
natural gas gathering pipeline in the Marcellus Shale region
that will deliver to the Transco pipeline. Construction is
expected to begin on the
20-inch
pipeline in the latter part of 2010, and it is expected to be
placed into service during 2011. We will operate the pipeline,
which represents our second significant midstream expansion in
the Marcellus Shale.
We own a 49.25 percent interest in Accroven SRL which
includes two
400 MMcf/d
NGL extraction plants, a 50 Mbbls/d NGL fractionation plant
and associated storage and refrigeration facilities. Accroven
owns and operates gas processing facilities and an NGL
fractionation plant for the exclusive benefit of the state-owned
oil company, Petróleos de Venezuela S.A. (PDVSA). As a
result of deteriorating circumstances for our Venezuelan
operations (see Note 2 of Notes to Consolidated Financial
Statements), we fully impaired and recognized a $75 million
charge related to an
other-than-temporary
loss in value of our Accroven investment. (See Note 3 of
Notes to Consolidated Financial Statements.) Accroven was not
part of the operations that were expropriated by the Venezuelan
government in May 2009. We are currently engaged in discussions
regarding the eventual disposition of Accroven.
Operating
Statistics
The following table summarizes our significant operating
statistics for Midstream:
| 2009 | 2008 | 2007 | ||||||||||
|
Volumes:(1)
|
||||||||||||
|
Domestic gathering (TBtu)
|
1,068 | 1,013 | 1,045 | |||||||||
|
Plant inlet natural gas (TBtu)
|
1,342 | 1,311 | 1,275 | |||||||||
|
Domestic NGL production (Mbbls/d)(2)
|
164 | 154 | 163 | |||||||||
|
Domestic NGL equity sales (Mbbls/d)(2)
|
80 | 80 | 92 | |||||||||
|
Crude oil gathering (Mbbls/d)(2)
|
109 | 70 | 80 | |||||||||
|
Canadian NGL equity sales (Mbbls/d)(2)
|
8 | 7 | 9 | |||||||||
|
Olefin (ethylene and propylene) sales (millions of pounds)
|
1,728 | 1,605 | 1,401 | |||||||||
| (1) | Excludes volumes associated with partially owned assets, such as our Discovery and Marcellus joint venture investments, that are not consolidated for financial reporting purposes. | |
| (2) | Annual average Mbbls/d. |
WPZ
WPZ was formed in 2005 to engage in gathering, transporting,
processing and treating natural gas and fractionating and
storing NGLs. As of December 31, 2009, we own approximately
a 23.6 percent limited partnership interest, including the
interests of the general partner, Williams Partners GP LLC,
which is wholly owned by us, and incentive distribution rights.
WPZ provides us with an alternative source of equity capital.
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 and operation of the assets. As of
December 31, 2009, WPZ’s asset portfolio includes
Williams Four Corners LLC, certain ownership interests in
Wamsutter LLC, a 60 percent interest in Discovery, three
integrated NGL storage facilities near Conway, Kansas, a
50 percent interest in an NGL fractionator near Conway,
Kansas, and the Carbonate Trend sour gas gathering pipeline off
the coast of Alabama.
As previously discussed, our ownership in WPZ, WPZ’s asset
portfolio, and our future segment reporting structure were
affected by our 2010 restructuring transactions.
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 the
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majority of fuel and shrink gas and hedging natural gas liquids
sales for Midstream. Gas Marketing also provides similar
services to third parties, such as producers and natural gas
processors. In addition, Gas Marketing manages various natural
gas-related contracts such as transportation and storage along
with the related hedges, including certain legacy natural gas
contracts and positions.
Gas Marketing’s 2009 natural gas purchase volumes include
1.4 Bcf/d of gas produced by Exploration &
Production and another 1.0 Bcf/d from other sources. This
natural gas was in turn marketed and sold to third parties
(2.1 Bcf/d) and to Midstream (0.3 Bcf/d).
Our Exploration & Production and Midstream segments
may execute commodity hedges with Gas Marketing. In turn, Gas
Marketing may execute offsetting derivative contracts with
unrelated third parties.
Additional
Business Segment Information
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.
We perform certain management, legal, financial, tax,
consultation, information technology, administrative and other
services for our subsidiaries.
Our principal sources of cash are from dividends and advances
from our subsidiaries, investments, payments by subsidiaries for
services rendered, interest payments from subsidiaries on cash
advances and, if needed, external financings, sales of master
limited partnership units to the public, 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 us.
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.
REGULATORY
MATTERS
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 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, and the
Pipeline Safety Improvement Act of 2002, which regulates safety
requirements in the design, construction, operation and
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maintenance of interstate natural gas transmission facilities.
FERC Standards of Conduct govern how our interstate pipelines
communicate and do business with gas marketing employees. Among
other things, the Standards of Conduct require that interstate
pipelines not operate their systems to preferentially benefit
gas marketing functions.
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:
| • | Costs of providing service, including depreciation expense; | |
| • | Allowed rate of return, including the equity component of the capital structure and related income taxes; | |
| • | Volume throughput assumptions. |
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.
Pipeline
Integrity Regulations
Transco and Northwest Pipeline have developed Integrity
Management Plans that meet the United States Department of
Transportation Pipeline and Hazardous Materials Safety
Administration (“PHMSA”) final rule pursuant to the
requirements of the Pipeline Safety Improvement Act of 2002. In
meeting the integrity regulations, Transco and Northwest
Pipeline have identified high-consequence areas, completed
baseline assessment plans, and are on schedule to complete the
required assessments within specified timeframes. Currently,
Transco and Northwest Pipeline estimate that the cost to perform
required assessments and remediation will be primarily capital
and range between $150 million and $220 million and
between $65 million and $85 million, respectively,
over the remaining assessment period of 2010 through 2012.
Management considers the costs associated with compliance with
the rule to be prudent costs incurred in the ordinary course of
business and, therefore, recoverable through rates.
Midstream Gas & Liquids.
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 offshore gathering facilities
are not subject to the NGA, offshore transmission pipelines are
subject to the NGA, and in recent years the FERC has taken a
broad view of offshore transmission, finding many shallow-water
pipelines to be jurisdictional transmission. 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 nonowner
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.
Our Midstream Canadian assets are regulated by the Energy
Resources Conservation Board (ERCB) 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 noncompliance
with the applicable regulations is at issue, the ERCB and
Alberta Environment have implemented an enforcement process with
escalating consequences.
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
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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 16 of our Notes to Consolidated Financial
Statements for further details on our regulatory matters.
ENVIRONMENTAL
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 cleanup costs. Materials could be released into
the environment in several ways including, but not limited to:
| • | From a well or drilling equipment at a drill site; | |
| • | Leakage from gathering systems, pipelines, processing or treating facilities, transportation facilities and storage tanks; | |
| • | Damage to oil and gas wells resulting from accidents during normal operations; | |
| • | Blowouts, cratering and explosions. |
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 16 of our Notes
to Consolidated Financial Statements.
COMPETITION
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.
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 Gas & Liquids.
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. By virtue of the master limited partnership
structure, WPZ provides us with an alternative source of
capital, which helps us compete against other master limited
partnerships for midstream projects.
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.
EMPLOYEES
At February 1, 2010, we had approximately
4,801 full-time employees. None of our employees are
represented by unions or covered by collective bargaining
agreements.
FINANCIAL
INFORMATION ABOUT GEOGRAPHIC AREAS
See Note 18 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 18 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.
| Item 1A. | Risk Factors |
FORWARD-LOOKING
STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
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 forward-looking statements relate to anticipated
financial performance, management’s plans and objectives
for future operations, business prospects, outcome of regulatory
proceedings, market conditions and other matters. We make these
forward-looking statements in reliance on the safe harbor
protections provided under the Private Securities Litigation
Reform Act of 1995.
All statements, other than statements of historical facts,
included in this report that 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,”
“seeks,” “could,” “may,”
“should,” “continues,”
“estimates,” “expects,”
“forecasts,” “intends,” “might,”
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“goals,” “objectives,” “targets,”
“planned,” “potential,”
“projects,” “scheduled,” “will” or
other similar expressions. These forward-looking statements are
based on management’s beliefs and assumptions and on
information currently available to management and include, among
others, statements regarding:
| • | Amounts and nature of future capital expenditures; | |
| • | Expansion and growth of our business and operations; | |
| • | Financial condition and liquidity; | |
| • | Business strategy; | |
| • | Estimates of proved gas and oil reserves; | |
| • | Reserve potential; | |
| • | Development drilling potential; | |
| • | Cash flow from operations or results of operations; | |
| • | Seasonality of certain business segments; | |
| • | Natural gas and natural gas liquids prices and demand. |
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 report. Many of the factors that will determine these
results are beyond our ability to control or predict. Specific
factors that could cause actual results to differ from results
contemplated by the forward-looking statements include, among
others, the following:
| • | Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital; | |
| • | Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers); | |
| • | The strength and financial resources of our competitors; | |
| • | Development of alternative energy sources; | |
| • | The impact of operational and development hazards; | |
| • | Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation, and rate proceedings; | |
| • | Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans; | |
| • | Changes in maintenance and construction costs; | |
| • | Changes in the current geopolitical situation; | |
| • | Our exposure to the credit risk of our customers; | |
| • | Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit; | |
| • | Risks associated with future weather conditions; | |
| • | Acts of terrorism; | |
| • | Additional risks described in our filings with the Securities and Exchange Commission. |
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
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statements. We disclaim any obligations to and do not intend to
update the above list or 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.
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 are described in the following section.
RISK
FACTORS
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
Related to the Restructuring
We did
not seek a vote of our shareholders in connection with the
restructuring. If there is a determination that such a vote was
required, the resulting consequences could impact
us.
Section 271 of the Delaware General Corporation Law (the
“DGCL”) generally requires a corporation to obtain
authorization from the holders of a majority of its outstanding
shares if the corporation intends to sell all or substantially
all of its assets. We do not believe the restructuring
constituted a sale of “all or substantially all” of
our assets because of, among other things, the portion of our
assets involved, the significance of our assets and businesses
that were not transferred and the facts that we retain control
of all of the assets involved and over an 80% interest in the
cash flows therefrom. As such, we did not seek a vote of our
shareholders in connection with the restructuring. There is a
limited body of Delaware case law interpreting the phrase
“all or substantially all,” and there is no precise
established definition. We cannot assure you that the
restructuring did not constitute a sale of “all or
substantially all” of our assets and, therefore, that a
shareholder vote was not required. If such a shareholder vote
were determined to be required, the resulting consequences could
impact us and could include (among other consequences) our
shareholders asserting claims against us, some or all of which
could ultimately be successful.
We may
not realize the anticipated benefits from the
restructuring.
We may not realize the benefits that we anticipate from the
Dropdown for a number of reasons, including, but not limited to,
if any of the matters identified as risks in this Risk Factors
section were to occur. If we do not realize the anticipated
benefits from the restructuring for any reason, our business may
be materially adversely affected.
Risks
Inherent to our Industry and Business
The
long-term financial condition of our Gas Pipeline 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 the prices of and
market demand for natural gas.
The development of the additional natural gas reserves that are
essential for our Gas Pipeline 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, including environmental regulations, 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.
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Production from existing wells and natural gas supply basins
with access to our pipeline and gathering systems will also
naturally decline over time. The amount of natural gas reserves
underlying these wells may also be less than anticipated, and
the rate at which production from these reserves declines may be
greater than anticipated. Additionally, the competition for
natural gas supplies to serve other markets could reduce the
amount of natural gas supply for our customers. Accordingly, to
maintain or increase the contracted capacity or the volume of
natural gas transported on or gathered through our pipelines and
cash flows associated with the gathering and transportation of
natural gas, our customers must compete with others to obtain
adequate supplies of natural gas. In addition, if natural gas
prices in the supply basins connected to our pipeline systems
are higher than prices in other natural gas producing regions,
our ability to compete with other transporters may be negatively
impacted on a short-term basis, as well as with respect to our
long-term recontracting activities. If new supplies of natural
gas are not obtained to replace the natural decline in volumes
from existing supply areas, if natural gas supplies are diverted
to serve other markets, or if environmental regulators restrict
new natural gas drilling, the overall volume of natural gas
transported, gathered, and stored on our system would decline,
which could have a material adverse effect on our business,
financial condition and results of operations. In addition, new
LNG import facilities built near our markets could result in
less demand for our gathering and transportation facilities.
Significant
prolonged changes in natural gas prices could affect supply and
demand and cause a termination of our transportation and storage
contracts or a reduction in throughput on our
system.
Higher natural gas prices over the long term could result in a
decline in the demand for natural gas and, therefore, in our
long-term transportation and storage contracts or throughput on
our Gas Pipelines’ systems. Also, lower natural gas prices
over the long term could result in a decline in the production
of natural gas resulting in reduced contracts or throughput on
our Gas Pipelines’ systems. As a result, significant
prolonged changes in natural gas prices could have a material
adverse effect on our business, financial condition, results of
operations and cash flows.
Prices
for NGLs, natural gas and other commodities are volatile and
this volatility could adversely affect our financial results,
cash flows, access to capital and ability to maintain existing
businesses.
Our revenues, operating results, future rate of growth and the
value of certain segments of our businesses depend primarily
upon the prices of NGLs, natural gas, or other commodities, and
the differences between prices of these commodities. Price
volatility and relative price levels may impact both the amount
we receive for our products and services and the volume of
products and services we sell. Prices affect the amount of cash
flow available for capital expenditures and our ability to
borrow money or raise additional capital.
The markets for NGLs, 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:
| • | Worldwide and domestic supplies of and demand for natural gas, NGLs, petroleum, and related commodities; | |
| • | Turmoil in the Middle East and other producing regions; | |
| • | The activities of the Organization of Petroleum Exporting Countries; | |
| • | Terrorist attacks on production or transportation assets; | |
| • | Weather conditions; | |
| • | The level of consumer demand; | |
| • | The price and availability of other types of fuels; | |
| • | The availability of pipeline capacity; | |
| • | Supply disruptions, including plant outages and transportation disruptions; | |
| • | The price and level of foreign imports; |
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| • | Domestic and foreign governmental regulations and taxes; | |
| • | Volatility in the natural gas markets; | |
| • | The overall economic environment; | |
| • | The credit of participants in the markets where products are bought and sold; | |
| • | The adoption of regulations or legislation relating to climate change. |
We
might not be able to successfully manage the risks associated
with selling and marketing products in the wholesale energy
markets.
Our portfolio of derivative and other energy contracts may
consist of wholesale contracts to buy and sell commodities,
including contracts for natural gas, NGLs 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 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. A general downturn in the economy and
tightening of global credit markets could cause more of our
counterparties to fail to perform than we have expected.
Significant
capital expenditures are required to replace our
reserves.
Our exploration, development and acquisition activities require
substantial capital expenditures. Historically, we have funded
our capital expenditures through a combination of cash flows
from operations and debt and equity issuances. Future cash flows
are subject to a number of variables, including the level of
production from existing wells, prices of natural gas, and our
success in developing and producing new reserves. If our cash
flow from operations is not sufficient to fund our capital
expenditure budget, we may not be able to access additional bank
debt, issue debt or equity securities or access other methods of
financing on an economic basis to meet our capital expenditure
budget. As a result, our capital expenditure plans may have to
be adjusted.
Failure
to replace reserves may negatively affect our
business.
The growth of our Exploration & Production business
depends upon our ability to find, develop or acquire additional
natural gas reserves that are economically recoverable. Our
proved reserves generally decline when reserves are produced,
unless we conduct successful exploration or development
activities or acquire properties containing proved reserves, or
both. We may not be able to find, develop or acquire additional
reserves on an economic basis. If natural gas prices increase,
our costs for additional reserves would also increase;
conversely if natural gas prices decrease, it could make it more
difficult to fund the replacement of our reserves.
Exploration
and development drilling may not result in commercially
productive reserves.
Our past success rate for drilling projects should not be
considered a predictor of future commercial success. We do not
always encounter commercially productive reservoirs through our
drilling operations. The new wells we drill or participate in
may not be productive and we may not recover all or any portion
of our investment in wells we drill or participate in. The cost
of drilling, completing and operating a well is often uncertain,
and cost factors can adversely affect the economics of a
project. Our efforts will be unprofitable if we drill dry wells
or wells that are
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productive but do not produce enough reserves to return a profit
after drilling, operating and other costs. Further, our drilling
operations may be curtailed, delayed or canceled as a result of
a variety of factors, including:
| • | Increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, skilled labor, capital or transportation; | |
| • | Unexpected drilling conditions or problems; | |
| • | Regulations and regulatory approvals; | |
| • | Changes or anticipated changes in energy prices; | |
| • | Compliance with environmental and other governmental requirements. |
Estimating
reserves and future net revenues involves uncertainties.
Negative revisions to reserve estimates, oil and gas prices or
assumptions as to future natural gas prices may lead to
decreased earnings, losses, or impairment of oil and gas assets,
including related goodwill.
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.
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. These revisions, as well as revisions in the
assumptions of future cash flows of these reserves, may also be
sufficient to trigger impairment losses on certain properties
which would result in a noncash charge to earnings. The
revisions could also possibly affect the evaluation of
Exploration & Production’s goodwill for
impairment purposes. At December 31, 2009, we had
approximately $1 billion of goodwill on our balance sheet.
Certain
of our services are subject to long-term, fixed-price contracts
that are not subject to adjustment, even if our cost to perform
such services exceeds the revenues received from such
contracts.
Our Gas Pipeline and Midstream businesses provide some services
pursuant to long-term, fixed price contracts. It is possible
that costs to perform services under such contracts will exceed
the revenues we collect for our services. Although most of the
services provided by our interstate gas pipelines are priced at
cost-based rates that are subject to adjustment in rate cases,
under FERC policy, a regulated service provider and a customer
may mutually agree to sign a contract for service at a
“negotiated rate” that may be above or below the FERC
regulated cost-based rate for that service. These
“negotiated rate” contracts are not generally subject
to adjustment for increased costs that could be produced by
inflation or other factors relating to the specific facilities
being used to perform the services.
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We may
not be able to maintain or replace expiring natural gas
transportation and storage contracts at favorable rates or on a
long-term basis.
Our primary exposure to market risk for our Gas Pipelines occurs
at the time the terms of their existing transportation and
storage contracts expire and are subject to termination.
Although none of our Gas Pipelines’ material contracts are
terminable in 2010, upon expiration of the terms we may not be
able to extend contracts with existing customers to obtain
replacement contracts at favorable rates or on a long-term
basis. The extension or replacement of existing contracts
depends on a number of factors beyond our control, including:
| • | The level of existing and new competition to deliver natural gas to our markets; | |
| • | The growth in demand for natural gas in our markets; | |
| • | Whether the market will continue to support long-term firm contracts; | |
| • | Whether our business strategy continues to be successful; | |
| • | The level of competition for natural gas supplies in the production basins serving us; | |
| • | The effects of state regulation on customer contracting practices. |
Any failure to extend or replace a significant portion of our
existing contracts may have a material adverse effect on our
business, financial condition, results of operations and cash
flows.
Our
risk measurement and hedging activities might not be effective
and could increase the volatility of our results.
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 GAAP 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 GAAP, must be recorded in our income.
This creates the risk of volatility in earnings even if no
economic impact to us has occurred during the applicable period.
The impact of changes in market prices for NGLs and natural gas
on the average prices paid or received by us may be reduced
based on the level of our hedging activities. These hedging
arrangements may limit or enhance our margins if the market
prices for NGLs or natural gas were to change substantially from
the price established by the hedges. In addition, our hedging
arrangements expose us to the risk of financial loss in certain
circumstances, including instances in which:
| • | Volumes are less than expected; | |
| • | The hedging instrument is not perfectly effective in mitigating the risk being hedged; | |
| • | The counterparties to our hedging arrangements fail to honor their financial commitments. |
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We
depend on certain key customers for a significant portion of our
revenues. The loss of any of these key customers or the loss of
any contracted volumes could result in a decline in our
business.
Our Gas Pipeline and Midstream businesses rely on a limited
number of customers for a significant portion of their revenues.
Although some of these customers are subject to long-term
contracts, extensions or replacements of these contracts may not
be renegotiated favorable terms, if at all. The loss of even a
portion of the revenues from natural gas, NGLs or contracted
volumes, as applicable, supplied by these customers, as a result
of competition, creditworthiness, inability to negotiate
extensions or replacements of contracts or otherwise, could have
a material adverse effect on our business, financial condition,
results of operations and cash flows, unless we are able to
generate comparable revenues from other sources.
We are
exposed to the credit risk of our customers, and our credit risk
management may not be adequate to protect against such
risk.
We are exposed to risk of loss resulting from nonpayment
and/or
nonperformance by our customers in the ordinary course of our
business. Generally our customers are either rated investment
grade or otherwise considered credit worthy, or they are
required to make pre-payments or otherwise provide security to
satisfy credit concerns. However, our credit procedures and
policies may not be adequate to fully eliminate customer credit
risk. We cannot predict to what extent our business would be
impacted by deteriorating conditions in the economy, including
declines in our customers’ creditworthiness. If we fail to
adequately assess the creditworthiness of existing or future
customers, unanticipated deterioration in their creditworthiness
and any resulting increase in nonpayment
and/or
nonperformance by them could cause us to write-down or write-off
doubtful accounts. Such write-downs or write-offs could
negatively affect our operating results for the period in which
they occur, and, if significant, could have a material adverse
effect on our business, results of operations, cash flows and
financial condition.
Competition
in the markets in which we operate may adversely affect our
results of operations.
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.
The
failure of new sources of natural gas production or LNG import
terminals to be successfully developed in North America could
increase natural gas prices and reduce the demand for our
services.
New sources of natural gas production in the United States and
Canada, particularly in areas of shale development are expected
to become an increasingly significant component of future U.S.
natural gas supplies in North America. Additionally, increases
in LNG supplies are expected to be imported through new LNG
import terminals, particularly in the Gulf Coast region. If
these additional sources of supply are not developed, natural
gas prices could increase and cause consumers of natural gas to
turn to alternative energy sources, which could have a material
adverse effect on our business, financial condition, results of
operations and cash flows.
Our
drilling, production, gathering, processing, storage and
transporting activities involve numerous risks that might result
in accidents, and other operating risks and
hazards.
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:
| • | Fires, blowouts, cratering and explosions; | |
| • | Uncontrolled releases of oil, natural gas, NGLs or well fluids; | |
| • | Collapse of NGL storage caverns; |
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| • | Operator error; | |
| • | Pollution and other environmental risks; | |
| • | Hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural disasters; | |
| • | Aging infrastructure and mechanical problems; | |
| • | Damages to pipelines and pipeline blockages; | |
| • | Damage inadvertently caused by third party activity, such as operation of construction equipment; | |
| • | Risks related to truck and rail loading and unloading; | |
| • | Risks related to operating in a marine environment; | |
| • | Terrorist attacks or threatened attacks on our facilities or those of other energy companies. |
Any of these risks could result in loss of human life, personal
injuries, 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 such as those described above could cause
considerable harm to people or property, and could have a
material adverse effect on our financial condition and results
of operations, 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, including those arising from maintenance and
repair activities, could result in service interruptions on
segments of our pipeline infrastructure. Potential customer
impacts arising from service interruptions on segments of our
pipeline infrastructure could include limitations on the
pipeline’s ability to satisfy customer requirements,
obligations to provide reservations charge credits to customers
in times of constrained capacity, and solicitation of existing
customers by others for potential new pipeline projects that
would compete directly with existing services. Such
circumstances could materially impact our ability to meet
contractual obligations and retain customers, with a resulting
negative impact on our business, financial condition, results of
operations and cash flows.
We do
not insure against all potential losses and could be seriously
harmed by unexpected liabilities or by the ability of the
insurers we do use to satisfy our claims.
We are not fully insured against all risks inherent to our
business, including environmental accidents that might occur. In
addition, we do not maintain business interruption insurance in
the type and amount to cover all possible risks of loss. We
currently maintain excess liability insurance with limits of
$610 million per occurrence and in the aggregate annually
and a deductible of $2 million per occurrence. This
insurance covers us, our subsidiaries and certain of our
affiliates for legal and contractual liabilities arising out of
bodily injury, personal injury or property damage, including
resulting loss of use to third parties. This excess liability
insurance includes coverage for sudden and accidental pollution
liability for full limits, with the first $135 million of
insurance also providing gradual pollution liability coverage
for natural gas and NGL operations. Pollution liability coverage
excludes: release of pollutants subsequent to their disposal;
release of substances arising from the combustion of fuels that
result in acidic deposition, and testing, monitoring,
clean-up,
containment, treatment or removal of pollutants from property
owned, occupied by, rented to, used by or in the care, custody
or control of us, our subsidiaries and certain of our affiliates.
We do not insure onshore underground pipelines for physical
damage, except at river crossings and at certain locations such
as compressor stations. We maintain coverage of
$300 million per occurrence for physical damage to onshore
assets and resulting business interruption caused by terrorist
acts. We also maintain coverage of $100 million per
occurrence for physical damage to offshore assets caused by
terrorist acts, except for our Devils Tower spar where we
maintain limits of $300 million per occurrence for property
damage caused by terrorist acts and $105 million per
occurrence for resulting business interruption. Also, all of our
insurance is subject to deductibles. If a significant accident
or event occurs for which we are not fully insured, it could
adversely affect our
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operations and financial condition. We may not be able to
maintain or obtain insurance of the type and amount we desire at
reasonable rates. Changes in the insurance markets subsequent to
hurricane losses in recent years have impacted named windstorm
insurance coverage, rates and availability for Gulf of Mexico
area exposures, and we may elect to self insure a portion of our
asset portfolio. We cannot assure you that we will in the future
be able to obtain the levels or types of insurance we would
otherwise have obtained prior to these market changes or that
the insurance coverage we do obtain will not contain large
deductibles or fail to cover certain hazards or cover all
potential losses. The occurrence of any operating risks not
fully covered by insurance could have a material adverse effect
on our business, financial condition, results of operations and
cash flows.
In addition, certain insurance companies that provide coverage
to us, including American International Group, Inc., have
experienced negative developments that could impair their
ability to pay any of our potential claims. As a result, we
could be exposed to greater losses than anticipated and may have
to obtain replacement insurance, if available, at a greater cost.
Execution
of our capital projects subjects us to construction risks,
increases in labor and materials costs and other risks that may
adversely affect financial results.
A significant portion of any growth in our Gas Pipeline and
Midstream businesses is accomplished through the construction of
new pipelines, processing and storage facilities, as well as the
expansion of existing facilities. Construction of these
facilities is subject to various regulatory, development and
operational risks, including:
| • | The ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; | |
| • | The availability of skilled labor, equipment, and materials to complete expansion projects; | |
| • | Potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; | |
| • | Impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; | |
| • | The ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor, or other factors beyond our control, that may be material; | |
| • | The ability to access capital markets to fund construction projects. |
Any of these risks could prevent a project from proceeding,
delay its completion or increase its anticipated costs. As a
result, new facilities may not achieve expected investment
return, which could adversely affect results of operations,
financial position or cash flows.
Our
costs and funding obligations for our defined benefit pension
plans and costs for our other post-retirement benefit plans are
affected by factors beyond our control.
We have defined benefit pension plans covering substantially all
of our U.S. employees and other post-retirement benefit
plans covering certain eligible participants. The timing and
amount of our funding requirements under the defined benefit
pension plans depend upon a number of factors we control,
including changes to pension plan benefits, as well as factors
outside of our control, such as asset returns, interest rates
and changes in pension laws. Changes to these and other factors
that can significantly increase our funding requirements could
have a significant adverse effect on our financial condition and
results of operations.
Two of
our subsidiaries act as the respective general partners of two
different publicly-traded limited partnerships, Williams
Partners L.P. and Williams Pipeline Partners L.P. As such, those
subsidiaries’ operations may involve a greater risk of
liability than ordinary business operations.
One of our subsidiaries acts as the general partner of WPZ and
another subsidiary of ours acts as the general partner of WMZ.
Each of these subsidiaries that act as the general partner of a
publicly-traded limited partnership
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may be deemed to have undertaken fiduciary obligations with
respect to the limited partnership of which it serves as the
general partner and to the limited partners of such limited
partnership. Activities determined to involve fiduciary
obligations to other persons or entities typically involve a
higher standard of conduct than ordinary business operations and
therefore may involve a greater risk of liability, particularly
when a conflict of interests is found to exist. Our control of
the general partners of two different publicly traded
partnerships may increase the possibility of claims of breach of
fiduciary duties, including claims brought due to conflicts of
interest (including conflicts of interest that may arise
(i) between the two publicly-traded partnerships as well as
(ii) between a publicly-traded partnership, on the one
hand, and its general partner and that general partner’s
affiliates, including us, on the other hand). Any liability
resulting from such claims could be material.
Potential
changes in accounting standards might cause us to revise our
financial results and disclosures in the future, which might
change the way analysts measure our business or financial
performance.
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. Any significant change
in accounting standards or disclosure requirements could have a
material adverse effect on our business, results of operations,
and financial condition.
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 projects or make
investments could make it more difficult to obtain nonrecourse
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.
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.
Our
operating results for certain segments of our business might
fluctuate on a seasonal and quarterly basis.
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.
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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.
Risks
Related to Strategy and Financing
Our
debt agreements impose restrictions on us that may adversely
affect our ability to operate our business.
Certain of our debt agreements contain covenants that restrict
or limit, among other things, our ability to create liens
supporting indebtedness, merge, sell substantially all of our
assets, make certain distributions, 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. These covenants
could adversely affect our ability to finance our future
operations or capital needs or engage in, expand or pursue our
business activities and prevent us from engaging in certain
transactions that might otherwise be considered beneficial to
us. Our ability to comply with these covenants may be affected
by many events beyond our control, including prevailing
economic, financial and industry conditions. If market or other
economic conditions deteriorate, our current assumptions about
future economic conditions turn out to be incorrect or
unexpected events occur, our ability to comply with these
covenants may be significantly impaired. 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
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. Certain payment defaults 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.
Our ability to repay, extend or refinance our existing debt
obligations and to obtain future credit will depend primarily on
our operating performance, which will be affected by general
economic, financial, competitive, legislative, regulatory,
business and other factors, many of which are beyond our
control. Our ability to refinance existing debt obligations or
obtain future credit will also depend upon the current
conditions in the credit markets and the availability of credit
generally. If we are unable to meet our debt service obligations
or obtain future credit on favorable terms, if at all, we could
be forced to restructure or refinance our indebtedness, seek
additional equity capital or sell assets. We may be unable to
obtain financing or sell assets on satisfactory terms, or at all.
Future
disruptions in the global credit markets may make equity and
debt markets less accessible, create a shortage in the
availability of credit and lead to credit market
volatility.
In 2008, public equity markets experienced significant declines
and global credit markets experienced a shortage in overall
liquidity and a resulting disruption in the availability of
credit. Future disruptions in the global financial marketplace,
including the bankruptcy or restructuring of financial
institutions, may make equity and debt markets inaccessible and
adversely affect the availability of credit already arranged and
the availability and cost of credit in the future. We have
availability under our existing bank credit facilities, but our
ability to borrow under those facilities could be impaired if
one or more of our lenders fail to honor its contractual
obligation to lend to us.
Adverse
economic conditions could adversely affect our results of
operations.
A slowdown in the economy has the potential to negatively impact
our businesses in many ways. Included among these potential
negative impacts are reduced demand and lower prices for our
products and services, increased difficulty in collecting
amounts owed to us by our customers and a reduction in our
credit ratings (either due to tighter rating standards or the
negative impacts described above), which could result in
reducing our access to credit markets, raising the cost of such
access or requiring us to provide additional collateral to our
counterparties.
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A
downgrade of our credit ratings could impact our liquidity,
access to capital and our costs of doing business, and
maintaining current credit ratings is under the control of
independent third parties.
A downgrade of our credit rating might increase our cost of
borrowing and would require us to post additional collateral
with third parties, negatively impacting our available
liquidity. Our ability to access capital markets would also be
limited by a downgrade of our credit rating and other
disruptions. Such disruptions could include:
| • | Economic downturns; | |
| • | Deteriorating capital market conditions; | |
| • | Declining market prices for natural gas, natural gas liquids and other commodities; | |
| • | Terrorist attacks or threatened attacks on our facilities or those of other energy companies; | |
| • | The overall health of the energy industry, including the bankruptcy or insolvency of other companies. |
Credit rating agencies perform independent analysis when
assigning credit ratings. The analysis includes a number of
criteria including, but not limited to, business composition,
market and operational risks, as well as various financial
tests. Credit rating agencies continue to review the criteria
for industry sectors and various debt ratings and may make
changes to those criteria from time to time. Our corporate
family credit rating and the credit ratings of Transco and
Northwest Pipeline are rated investment grade by
Standard & Poor’s, Moody’s Corporation, and
Fitch Ratings, Ltd., and our senior unsecured debt ratings are
rated investment grade by Moody’s and Fitch. Credit ratings
are not recommendations to buy, sell or hold investments in the
rated entity. Ratings are subject to revision or withdrawal at
any time by the ratings agencies, and no assurance can be given
that the credit rating agencies will continue to 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.
Risks
Related to Regulations that Affect our Industry
Our
natural gas sales, transmission, and storage operations are
subject to government regulations and rate proceedings that
could have an adverse impact on our results of
operations.
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 NGA and the Natural Gas Policy Act of 1978. The
FERC’s regulatory authority extends to:
| • | Transportation and sale for resale of natural gas in interstate commerce; | |
| • | Rates, operating terms and conditions of service, including initiation and discontinuation of services; | |
| • | Certification and construction of new facilities; | |
| • | Acquisition, extension, disposition or abandonment of facilities; | |
| • | Accounts and records; | |
| • | Depreciation and amortization policies; | |
| • | Relationships with marketing functions within Williams involved in certain aspects of the natural gas business; | |
| • | Market manipulation in connection with interstate sales, purchases or transportation of natural gas. |
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
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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 are
subject to risks associated with climate change.
There is a growing belief that emissions of greenhouse gases
(GHGs) may be linked to climate change. Climate change and the
costs that may be associated with its impacts and the regulation
of GHGs have the potential to affect our business in many ways,
including negatively impacting the costs we incur in providing
our products and services, the demand for and consumption of our
products and services (due to change in both costs and weather
patterns), and the economic health of the regions in which we
operate, all of which can create financial risks.
Costs
of environmental liabilities and complying with existing and
future environmental regulations, including those related to
climate change and greenhouse gas emissions, could exceed our
current expectations.
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 various substances into the
environment, and in connection with the operation, maintenance,
abandonment and reclamation of our facilities. Various
governmental authorities, including the U.S. Environmental
Protection Agency (EPA) and analogous state agencies and the
United States Department of Homeland Security, have the power to
enforce compliance with these laws and regulations and the
permits issued under them, oftentimes requiring difficult and
costly actions. Failure to comply with these laws, regulations,
and permits may result in the assessment of administrative,
civil, and criminal penalties, the imposition of remedial
obligations, the imposition of stricter conditions on or
revocation of permits, and the issuance of injunctions limiting
or preventing some or all of our operations.
Compliance with environmental laws requires significant
expenditures, including clean up costs and damages arising out
of contaminated properties. Joint and several, strict liability
may be incurred without regard to fault under certain
environmental laws and regulations for the remediation of
contaminated areas and in connection with spills or releases of
natural gas and wastes on, under, or from our properties and
facilities. Private parties, including the owners of properties
through which our pipeline and gathering systems pass, may have
the right to pursue legal actions to enforce compliance as well
as to seek damages for non-compliance with environmental laws
and regulations or for personal injury or property damage
arising from our operations.
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.
Legislative and regulatory responses related to GHGs and climate
change creates the potential for financial risk. The United
States Congress and certain states have for some time been
considering various forms of legislation related to GHG
emissions. There have also been international efforts seeking
legally binding reductions in emissions of GHGs. In addition,
increased public awareness and concern may result in more state,
federal, and international proposals to reduce or mitigate GHG
emissions.
Several bills have been introduced in the United States Congress
that would compel GHG emission reductions. In June of 2009, the
U.S. House of Representatives passed the “American
Clean Energy and Security Act” which is intended to
decrease annual GHG emissions through a variety of measures,
including a “cap and trade” system
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which limits the amount of GHGs that may be emitted and
incentives to reduce the nation’s dependence on traditional
energy sources. The U.S. Senate is currently considering
similar legislation, and numerous states have also announced or
adopted programs to stabilize and reduce GHGs. In addition, on
December 7, 2009, the EPA issued a final determination that
six GHGs are a threat to public safety and welfare. This
determination is the latest in a series of EPA actions in 2009
which could ultimately lead to the direct regulation of GHG
emissions in our industry by the EPA under the Clean Air Act.
While it is not clear whether or when any federal or state
climate change laws or regulations will be passed, any of these
actions could result in increased costs to (i) operate and
maintain our facilities, (ii) install new emission controls
on our facilities, and (iii) administer and manage any GHG
emissions program. If we are unable to recover or pass through a
significant level of our costs related to complying with climate
change regulatory requirements imposed on us, it could have a
material adverse effect on our results of operations. To the
extent financial markets view climate change and emissions of
GHGs as a financial risk, this could negatively impact our cost
of and access to capital.
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.
If
third-party pipelines and other facilities interconnected to our
pipeline and facilities become unavailable to transport natural
gas and NGLs or to treat natural gas, our revenues could be
adversely affected.
We depend upon third-party pipelines and other facilities that
provide delivery options to and from our pipeline and facilities
for the benefit of our customers. Because we do not own these
third-party pipelines or facilities, their continuing operation
is not within our control. If these pipelines or other
facilities were to become unavailable for any reason, or if
throughput were reduced because of testing, line repair, damage
to the pipelines or facilities, reduced operating pressures,
lack of capacity, increased credit requirements or rates charged
by such pipelines or facilities or other causes, we and our
customers would have reduced capacity to transport, store or
deliver natural gas or NGL products to end use markets or to
receive deliveries of mixed NGLs, thereby reducing our revenues.
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. Any
temporary or permanent interruption at any key pipeline
interconnect or in operations on third-party pipelines or
facilities that would cause a material reduction in volumes
transported on our pipelines or our gathering systems or
processed, fractionated, treated or stored at our facilities
could have a material adverse effect on our business, financial
condition, results of operations and cash flows.
Our
businesses are subject to complex government regulations. The
operation of our businesses might be adversely affected by
changes in these regulations or in their interpretation or
implementation, or the introduction of new laws or regulations
applicable to our businesses or our customers.
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.
Specifically, the Colorado Oil & Gas Conservation
Commission has enacted new rules in 2009 which increased our
costs of permitting and environmental compliance and the time
required to obtain permits, which may have a material effect on
our results of operations.
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Legal
and regulatory proceedings and investigations relating to the
energy industry and capital markets have adversely affected our
business and may continue to do so.
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, suits, regulatory appeals and similar
matters might result in adverse decisions 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.
Risks
Related to Employees, Outsourcing of Noncore Support Activities,
and Technology
Institutional
knowledge residing with current employees nearing retirement
eligibility might not be adequately preserved.
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.
Failure
of or disruptions to our outsourcing relationships might
negatively impact our ability to conduct our
business.
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. The expiration of such agreements
or the transition of services between providers could lead to
similar losses of institutional knowledge or disruptions.
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.
Risks
Related to Weather, other Natural Phenomena and Business
Disruption
Our
assets and operations can be adversely affected by weather and
other natural phenomena.
Our assets and operations, including those located offshore, can
be adversely affected by hurricanes, floods, 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. Insurance may be inadequate, and in some
instances, we have been unable to obtain insurance on
commercially
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reasonable terms, or insurance may not be available. A
significant disruption in operations or a significant liability
for which we were not fully insured could have a material
adverse effect on our business, results of operations and
financial condition.
Our customers’ energy needs vary with weather conditions.
To the extent weather conditions are affected by climate change
or demand is impacted by regulations associated with climate
change, customers’ energy use could increase or decrease
depending on the duration and magnitude of the changes, leading
to either increased investment or decreased revenues.
Acts
of terrorism could have a material adverse effect on our
financial condition, results of operations and cash
flows.
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.
| Item 1B. | Unresolved Staff Comments |
None.
| Item 2. | Properties |
We own property in 32 states plus the District of Columbia
in the United States and in Argentina, Canada, Venezuela, and
Colombia.
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 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.
| Item 3. | Legal Proceedings |
The information called for by this item is provided in
Note 16 of the Notes to Consolidated Financial Statements
of this report, which information is incorporated by reference
into this item.
| Item 4. | Submission of Matters to a Vote of Security Holders |
None.
Executive
Officers of the Registrant
The name, age, period of service, and title of each of our
executive officers as of February 17, 2009, are listed
below.
| Alan S. Armstrong | Senior Vice President, Midstream | |
| Age: 47 | ||
| Position held since February 2002. | ||
| Mr. Armstrong acts as President of our Midstream business unit. From 1999 to February 2002, Mr. Armstrong was Vice President, Gathering and Processing for Midstream. From 1998 to 1999 he was Vice President, Commercial Development for Midstream. Mr. Armstrong serves as a director and Senior Vice President, Midstream, of Williams Partners GP LLC, the general partner of Williams Partners L.P. |
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| James J. Bender | Senior Vice President and General Counsel | |
| Age: 53 | ||
| Position held since December 2002. | ||
| Prior to joining us, Mr. Bender was Senior Vice President and General Counsel with NRG Energy, Inc., a position held since June 2000, prior to which he was Vice President, General Counsel and Secretary of NRG Energy Inc. NRG Energy, Inc. filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003. Mr. Bender has served as the General Counsel of Williams Partners GP LLC, the general partner of Williams Partners L.P. since February 2005 and of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P. since August 2007. | ||
| Donald R. Chappel | Senior Vice President and Chief Financial Officer | |
| Age: 58 | ||
| Position held since April 2003. | ||
| Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Mr. Chappel serves as Chief Financial Officer and a director of Williams Partners GP LLC, the general partner of Williams Partners L.P., and as Chief Financial Officer and a director of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P. | ||
| Robyn L. Ewing | Senior Vice President, Strategic Services and Administration and Chief Administrative Officer | |
| Age: 54 | ||
| Position held since March 2008. | ||
| From 2004 to 2008 Ms. Ewing was Vice President of Human Resources. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in April 1998. She began her career with Cities Service Company in 1976. | ||
| Ralph A. Hill | Senior Vice President, Exploration & Production | |
| Age: 50 | ||
| Position held since December 1998. | ||
| Mr. Hill acts as President of our Exploration & Production business unit. He was Vice President of the Exploration & Production business from 1993 to 1998 as well as Senior Vice President Petroleum Services from 1998 to 2003. Mr. Hill serves as a director of Apco Oil and Gas International Inc. | ||
| Steven J. Malcolm | Chairman of the Board, Chief Executive Officer and President | |
| Age: 61 | ||
| Position held since September 2001. | ||
| Mr. Malcolm became Chairman of the Board in May 2002, Chief Executive Officer in January 2002, and President in September 2001. He was Chief Operating Officer from September 2001 to January 2002 and an Executive Vice President from May 2001 to September 2001. Mr. Malcolm was President and Chief Executive Officer of Williams Energy Services, LLC, a subsidiary of Williams, from 1998 to 2001, and Senior Vice President and General Manager of Williams Field Services Company, a subsidiary of Williams, from 1994 to 1998. Mr. Malcolm is also a director of several entities: Williams Partners GP LLC, the general partner of Williams Partners L.P.; Williams Pipeline GP LLC, the general |
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| partner of Williams Pipeline Partners L.P.; BOK Financial Corporation; and Bank of Oklahoma N.A. | ||
| Phillip D. Wright | Senior Vice President, Gas Pipeline | |
| Age: 54 | ||
| Position held since January 2005. | ||
| Mr. Wright acts as President of our Gas Pipeline business unit. From October 2002 to January 2005, he served as Chief Restructuring Officer. From September 2001 to October 2002, Mr. Wright served as President and Chief Executive Officer of our subsidiary Williams Energy Services. From 1996 until September 2001, he was Senior Vice President, Enterprise Development and Planning for our energy services group. Mr. Wright serves as a director of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P., and a director and Senior Vice President, Gas Pipeline, of Williams Partners GP LLC, the general partner of Williams Partners L.P. |
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| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is listed on the New York Stock Exchange under
the symbol “WMB.” At the close of business on
February 19, 2010, we had approximately 10,445 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:
| 2009 | 2008 | |||||||||||||||||||||||
|
Quarter
|
High | Low | Dividend | High | Low | Dividend | ||||||||||||||||||
|
1st
|
$ | 16.31 | $ | 9.83 | $ | .11 | $ | 36.99 | $ | 30.96 | $ | .10 | ||||||||||||
|
2nd
|
$ | 17.82 | $ | 11.53 | $ | .11 | $ | 40.31 | $ | 33.65 | $ | .11 | ||||||||||||
|
3rd
|
$ | 18.98 | $ | 13.83 | $ | .11 | $ | 39.90 | $ | 21.85 | $ | .11 | ||||||||||||
|
4th
|
$ | 21.37 | $ | 16.89 | $ | .11 | $ | 22.50 | $ | 12.13 | $ | .11 | ||||||||||||
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.
Performance
Graph
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, 2005. The
Bloomberg U.S. Pipeline Index is composed of Enbridge Inc.,
Spectra Energy Corp, TransCanada Corporation, and The Williams
Companies, Inc. The graph below assumes an investment of $100 at
the beginning of the period.
Cumulative
Total Shareholder Return
| 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | |||||||||||||||||||||||||
|
The Williams Companies, Inc.
|
100.0 | 143.9 | 164.6 | 228.3 | 94.0 | 140.7 | ||||||||||||||||||||||||
|
S&P 500 Index
|
100.0 | 104.9 | 121.5 | 128.1 | 80.7 | 102.1 | ||||||||||||||||||||||||
|
Bloomberg U.S. Pipelines Index
|
100.0 | 132.5 | 153.5 | 182.0 | 111.2 | 157.6 | ||||||||||||||||||||||||
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| Item 6. | Selected Financial Data |
The following financial data at December 31, 2009 and 2008,
and for each of the three years in the period ended
December 31, 2009, 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
of this
Form 10-K.
The following financial data at December 31, 2007, 2006,
and 2005, and for the years ended December 31, 2006 and
2005, has been prepared from our accounting records.
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
| (Millions, except per-share amounts) | ||||||||||||||||||||
|
Revenues(1)
|
$ | 8,255 | $ | 11,890 | $ | 10,239 | $ | 9,144 | $ | 9,537 | ||||||||||
|
Income from continuing operations(2)
|
584 | 1,467 | 910 | 366 | 458 | |||||||||||||||
|
Income (loss) from discontinued operations(3)
|
(223 | ) | 125 | 170 | (17 | ) | (116 | ) | ||||||||||||
|
Cumulative effect of change in accounting principle(4)
|
— | — | — | — | (2 | ) | ||||||||||||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||||||||||
|
Income from continuing operations
|
438 | 1,306 | 829 | 332 | 446 | |||||||||||||||
|
Income (loss) from discontinued operations
|
(153 | ) | 112 | 161 | (23 | ) | (130 | ) | ||||||||||||
|
Cumulative effect of change in accounting principle
|
— | — | — | — | (2 | ) | ||||||||||||||
|
Diluted earnings (loss) per common share:
|
||||||||||||||||||||
|
Income from continuing operations
|
.75 | 2.21 | 1.37 | .55 | .75 | |||||||||||||||
|
Income (loss) from discontinued operations
|
(.26 | ) | .19 | .26 | (.04 | ) | (.22 | ) | ||||||||||||
|
Total assets at December 31
|
25,280 | 26,006 | 25,061 | 25,402 | 29,443 | |||||||||||||||
|
Short-term notes payable and long-term debt due within one year
at December 31
|
17 | 18 | 108 | 358 | 88 | |||||||||||||||
|
Long-term debt at December 31
|
8,259 | 7,683 | 7,580 | 7,410 | 7,344 | |||||||||||||||
|
Stockholders’ equity at December 31
|
8,447 | 8,440 | 6,375 | 6,073 | 5,427 | |||||||||||||||
|
Cash dividends declared per common share
|
.44 | .43 | .39 | .345 | .25 | |||||||||||||||
| (1) | Amounts for 2008 and 2007 have been adjusted to reflect the presentation of certain revenues and costs for Midstream on a net basis. These adjustments reduced previously reported revenues and costs and operating expenses by the same amounts, with no impact to segment profit. The reductions were $295 million in 2008 and $99 million in 2007. | |
| (2) | See Note 4 of Notes to Consolidated Financial Statements for discussion of asset sales, impairments, and other accruals in 2009, 2008, and 2007. Income from continuing operations for 2006 includes a $73 million charge for a litigation contingency. Income from continuing operations for 2005 includes an $82 million charge for litigation contingencies and a $110 million charge for impairments of certain equity investments. | |
| (3) | See Note 2 of Notes to Consolidated Financial Statements for the analysis of the 2009, 2008, and 2007 income (loss) from discontinued operations. The discontinued operations results for 2006 includes our former power business, discontinued Venezuela operations, as well as amounts associated with our former chemical fertilizer business, a former exploration business, our former Alaska refinery, and our former distributive power business. The discontinued operations results for 2005 includes our former power business and discontinued Venezuela operations. | |
| (4) | The 2005 cumulative effect of change in accounting principle is due to the implementation of Financial Accounting Standards Board (FASB) Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations — an Interpretation of FASB statement No. 143 (SFAS No. 143).” |
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| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Strategic
Restructuring
On February 17, 2010, we completed a strategic
restructuring, which involved contributing a substantial
majority of our domestic midstream and gas pipeline businesses,
including our limited- and general-partner interests in Williams
Pipeline Partners L.P. (WMZ), into Williams Partners L.P. (WPZ).
As consideration for the asset contributions, we received
proceeds from WPZ’s debt issuance of approximately
$3.5 billion, less WPZ’s transaction fees and
expenses, as well as 203 million WPZ Class C units,
which are identical to common units, except for a prorated
initial distribution. We also maintained our 2 percent
general-partner interest. WPZ assumed approximately
$2 billion of existing debt associated with the gas
pipeline assets. In connection with the restructuring, we
retired $3 billion of our debt and paid $574 million
in related premiums. These amounts, as well as other transaction
costs, were primarily funded with the cash consideration
received from WPZ. The premiums paid and certain other
transaction costs will be recorded as expense in the first
quarter of 2010. As a result of our restructuring, we are better
positioned to drive additional growth and pursue value-adding
growth strategies. Our new structure is designed to lower
capital costs, enhance reliable access to capital markets, and
create a greater ability to pursue development projects and
acquisitions. (See Note 19 of Notes to Consolidated
Financial Statements.)
In conjunction with the restructuring, WPZ intends to make an
exchange offer for the publicly held units of WMZ at a future
date. See “Strategic Restructuring” in Part I,
Item 1 of this Form
10-K
for
further discussion of this potential exchange offer.
Beginning with reporting of first-quarter 2010 results, we will
change our segment reporting structure to align with the new
parent-level focus, resource allocation management and related
governance provisions resulting from the restructuring. Our
reporting segments will be Williams Partners,
Exploration & Production, and Other.
Exploration & Production will include our current Gas
Marketing segment and Other will include certain midstream and
gas pipeline businesses that were not contributed to WPZ, such
as our Canadian and olefins midstream businesses and the
remaining 25.5 percent interest in Gulfstream, as well as
corporate operations.
Information in this report has generally been prepared to be
consistent with the reportable segment presentation in our
consolidated financial statements in Part II, Item 8
of this document, which reflects our segment reporting structure
prior to the restructuring.
General
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 as of
December 31, 2009: Exploration & Production, Gas
Pipeline, Midstream Gas & Liquids, and Gas Marketing
Services. (See Note 1 of Notes to Consolidated Financial
Statements and Part I Item 1 for further discussion of
these segments.)
Unless indicated otherwise, the following discussion and
analysis of critical accounting estimates, 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.
Overview
of 2009
The overall economic recession, related lower energy commodity
price environment, and challenging financial markets during the
past year had a significant impact on our business. While we
began to see improvement in the second half of the year, these
conditions have resulted in sharply lower results of operations,
cash flow from operations and capital expenditures in 2009
compared to 2008. Anticipating these circumstances, our plan for
2009 was built around the transition from significant growth to
a focus on sustaining our current operations and reducing costs
where appropriate. Although capital expenditures were reduced
compared to the prior year, we continued to invest in our
businesses with a focus on completing major projects, meeting
legal, regulatory,
and/or
contractual
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commitments, and maintaining a reduced level of natural gas
production development. Objectives and highlights of this plan
included:
| Objectives | Highlights | ||
| Continuing to invest in our gathering and processing and interstate natural gas pipeline systems | We invested $513 million in capital expenditures in Midstream, primarily Deepwater Gulf expansion projects and gas-processing capacity in the western United States. We also invested $485 million in capital expenditures in Gas Pipeline during 2009. | ||
| Continuing to invest in our natural gas production development, although at a lower level than in recent years | We invested $1.3 billion in drilling activity and the acquisition of additional producing properties in Exploration & Production. | ||
| Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions, as well as seizing attractive opportunities | During 2009, capital and investment purchases were funded primarily through cash flow from operations while maintaining liquidity of at least $1 billion from cash and cash equivalents and unused revolving credit facilities. In addition, our Exploration & Production and Midstream segments seized growth opportunities to enter the Marcellus Shale, while Exploration & Production also expanded its footprint in the Piceance basin. (See further discussion in Other Significant 2009 Events.) | ||
Our 2009
income from continuing operations
attributable
to The Williams Companies, Inc., decreased by $868 million
compared to 2008. This decrease is primarily reflective of the
overall unfavorable commodity price environment for the full
year of 2009 as compared to 2008. Commodity prices declined
sharply in the fourth quarter of 2008, but have improved in the
latter half of 2009. See additional discussion in Results of
Operations.
Our
net cash provided by operating activities
for 2009
decreased $783 million compared to 2008, primarily due to
the decrease in our operating results. See additional discussion
in Management’s Discussion and Analysis of Financial
Condition and Liquidity.
Other
Significant 2009 Events
In March 2009, we issued $600 million aggregate principal
amount of 8.75 percent senior unsecured notes due 2020 to
certain institutional investors in a private debt placement. In
August 2009, we completed an exchange of these notes for
substantially identical new notes that are registered under the
Securities Act of 1933, as amended.
In April 2009, Midstream announced its plan to build a
261-mile
natural gas liquids pipeline in Canada at an estimated cost of
$283 million. Construction is expected to begin in 2010
with completion expected in 2012.
In May 2009, certain of Midstream’s Venezuela operations
were expropriated by the Venezuelan government. As a result,
these operations are now reflected as discontinued operations
and have been deconsolidated. (See Note 2 of Notes to
Consolidated Financial Statements.)
In June 2009, Midstream finalized the formation of a new joint
venture in the Marcellus Shale located in southwest
Pennsylvania. (See Results of Operations — Segments,
Midstream Gas & Liquids.)
In June 2009, Exploration & Production entered into an
agreement to develop properties in the Marcellus Shale. (See
Results of Operations — Segments,
Exploration & Production.)
In September 2009, Exploration & Production completed
the purchase of additional properties in the Piceance basin of
Colorado for $253 million. (See Results of
Operations — Segments, Exploration &
Production.)
In September 2009, Gas Pipeline received approval from the FERC
to begin construction of the 85 North expansion project at an
estimated cost of $241 million. (See Results of
Operations — Segments, Gas Pipeline.)
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Outlook
for 2010
We believe we are well positioned to execute on our 2010
business plan and to capture attractive growth opportunities.
The economic environment in the latter half of 2009 has improved
compared to conditions earlier in the year. In addition,
economic and commodity price indicators for 2010 and beyond
reflect continued improvement in the economic environment.
However, given the potential volatility of these measures, it is
reasonably possible that the economy could worsen
and/or
commodity prices could decline, negatively impacting future
operating results and increasing the risk of nonperformance of
counterparties or impairments of goodwill and long-lived assets.
As a result of our 2010 restructuring, as previously discussed,
we are better positioned to drive additional growth and pursue
value-adding growth strategies. Our new structure is designed to
lower capital costs, enhance reliable access to capital markets,
and create a greater ability to pursue development projects and
acquisitions.
We continue to operate with a focus on
EVA
®
and invest in our businesses in a way that meets customer needs
and enhances our competitive position by:
| • | Continuing to invest in and grow our gathering and processing and interstate natural gas pipeline systems; | |
| • | Continuing to invest in our natural gas drilling at a level generally consistent with the prior year and maintaining capacity to consider additional investment in attractive opportunities to diversify our reserves; | |
| • | Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions. |
Potential risks
and/or
obstacles that could impact the execution of our plan include:
| • | Lower than anticipated commodity prices; | |
| • | Lower than expected levels of cash flow from operations; | |
| • | Availability of capital; | |
| • | Counterparty credit and performance risk; | |
| • | Decreased drilling success at Exploration & Production; | |
| • | Decreased volumes from third parties served by Midstream; | |
| • | General economic, financial markets, or industry downturn; | |
| • | Changes in the political and regulatory environments; | |
| • | Physical damages to facilities, especially damage to offshore facilities by named windstorms for which our aggregate insurance policy limit is $37.5 million in the event of a material loss. |
We continue to address these risks through utilization of
commodity hedging strategies, disciplined investment strategies,
and maintaining at least $1 billion in liquidity from cash
and cash equivalents and unused revolving credit facilities. In
addition, we utilize master netting agreements and collateral
requirements with our counterparties to reduce credit risk and
liquidity requirements.
Accounting
Pronouncements Issued But Not Yet Adopted
Accounting pronouncements that have been issued but not yet
adopted may have an effect on our Consolidated Financial
Statements in the future.
See
Accounting Standards Issued But Not Yet Adopted
in
Note 1 of Notes to Consolidated Financial Statements for
further information on 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. We have discussed the following
accounting estimates and
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Table of Contents
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.
Impairments
of Long-Lived Assets and Goodwill
We evaluate our long-lived assets for impairment when we believe
events or changes in circumstances indicate that we may not be
able to recover the carrying value. Our computations utilize
judgments and assumptions that may include the estimated fair
value of the asset, undiscounted future cash flows, discounted
future cash flows, and the current and future economic
environment in which the asset is operated.
We assess our natural gas-producing properties and associated
unproved leasehold costs for impairment using estimates of
future cash flows. Significant judgments and assumptions in
these assessments include estimates of natural gas reserves
quantities, estimates of future natural gas prices using a
forward NYMEX curve adjusted for locational basis differentials,
drilling plans, expected capital costs, and an applicable
discount rate commensurate with risk of the underlying cash flow
estimates. Considering market-based pricing at December 31,
2009, we are not currently aware of any significant properties
that are approaching impairment thresholds.
In addition to those long-lived assets for which impairment
charges were recorded (see Note 4 of Notes to Consolidated
Financial Statements), certain others were reviewed for which no
impairment was required. These reviews included
Exploration & Production’s properties and
utilized inputs consistent with those described above. Certain
assets within our Midstream segment were also evaluated for
impairment utilizing judgments and assumptions including future
fees, margins, and volumes. These underlying variables are
subjective and susceptible to change. The use of alternate
judgments and assumptions could result in the recognition of
different levels of impairment charges in the consolidated
financial statements.
We have goodwill of approximately $1 billion at
Exploration & Production related to its domestic
operations (the reporting unit) primarily resulting from a 2001
acquisition. We assess goodwill for impairment annually as of
the end of the year. Because quoted market prices are not
available for the reporting unit, management applies a range of
reasonable judgments (including market supported assumptions
when available) in estimating a range of fair values for the
reporting unit.
We estimate the fair value of the reporting unit on a
stand-alone basis and also consider our market capitalization in
corroborating our estimate of the fair value of the reporting
unit. As of December 31, 2009, the estimated fair value of
the reporting unit exceeds its carrying value, including
goodwill, indicating no impairment of Exploration &
Production’s goodwill.
We estimated the fair value of the reporting unit on a
stand-alone basis primarily by valuing proved and unproved
reserves. We used an income approach (discounted cash flows) for
valuing reserves. The significant inputs into the valuation of
proved reserves included reserve quantities, forward natural gas
prices, anticipated drilling and operating costs, anticipated
production curves, and appropriate discount rates. Unproved
reserves were valued using similar assumptions adjusted further
for the uncertainty associated with these reserves. We
corroborated our fair value estimates with recent market
transactions where possible.
In estimating the inputs, management must make assumptions that
require judgments and are subject to change in response to
changing market conditions and other future events. Significant
assumptions in valuing proved reserves included reserves
quantities of more than 4.7 Tcfe, forward natural gas
prices, adjusted for locational differences, averaging
approximately $5.97 per Mcfe, and an after-tax discount rate of
11 percent.
At December 31, 2009, we believe that an overall
20 percent or greater reduction to our estimates of future
revenues, which are a component of our estimates of future cash
flows, could result in an impairment of goodwill. Future revenue
estimates are largely impacted by estimated prices and reserves.
This sensitivity does not include any related changes in
operating taxes or production costs. We currently do not
consider such a decrease in future revenues across all future
periods to be likely.
We further reviewed the fair value of the reporting unit
estimated on a stand-alone basis, by considering our market
capitalization in a reconciliation of the fair values of all our
businesses, including the reporting unit. In this
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reconciliation, we determined our market capitalization,
including a control premium, and estimated the fair values of
all our businesses considering certain financial performance
metrics. The range of control premiums that we considered were
consistent with historical market sales transactions and also
considered the current market environment. Market capitalization
was based on our traded stock price for a reasonably short
period of time before and after December 31, 2009. In
evaluating the items in our reconciliation analysis, management
considered a range of reasonable judgments. This analysis
allowed management to consider market expectations in
corroborating the reasonableness of the estimated fair value of
the reporting unit.
We also perform interim assessments of goodwill if impairment
triggering events or circumstances are present. Examples of
impairment triggering events or circumstances include:
| • | The testing for recoverability of a significant long-lived asset group within the reporting unit; | |
| • | Sustained operating losses or negative cash flows at the reporting unit level; | |
| • | A significant decline in forward natural gas prices or reserve quantities; | |
| • | Not meeting internal forecasts, or significant downward adjustments to future forecasts; | |
| • | A decline in enterprise market capitalization below our total consolidated stockholders’ equity; | |
| • | Industry trends. |
We cannot predict future market conditions and events that might
adversely affect the estimated fair value of the
Exploration & Production reporting unit and possibly
the reported value of goodwill. The estimated fair value of the
reporting unit is significantly affected by natural gas prices,
reserve quantities, and market expectations for required rates
of return. There are numerous uncertainties inherent in
estimating quantities of reserves that could affect our reserve
quantities. Low prices for natural gas, regulatory limitations,
or the lack of available capital for projects could adversely
affect the development and production of additional reserves.
Given the challenges affecting our businesses and the energy
industry in 2010, these factors could impact us and require us
to perform interim assessments of goodwill for possible
impairment during 2010, which could result in a material
impairment of our goodwill.
Accounting
for Derivative Instruments and Hedging Activities
We review our energy contracts to determine whether they are, or
contain derivatives. We further assess the appropriate
accounting method for any derivatives identified, which could
include:
| • | Qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings; | |
| • | Qualifying for and electing accrual accounting under the normal purchases and normal sales exception; or | |
| • | Applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings. |
If cash flow hedge accounting or accrual accounting is not
applied, a derivative is subject to
mark-to-market
accounting. Determination of the accounting method involves
significant judgments and assumptions, which are further
described below.
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 offsetting the 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
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occurring, or if the derivative contract is not expected to be
highly effective, the derivative does not qualify for hedge
accounting.
For derivatives designated as cash flow hedges, we must
periodically assess whether they continue to qualify for hedge
accounting. 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 reclassify 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 the 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.
Since our energy derivative contracts could be accounted for in
three different ways, two of which are elective, our accounting
method could be different from that used by another party for a
similar transaction. Furthermore, the accounting method may
influence the level of volatility in the financial statements
associated with changes in the fair value of derivatives, as
generally depicted below:
|
|
|
|||||||
|
Accounting Method
|
Drivers | Impact | Drivers | Impact | ||||
|
Accrual Accounting
|
Realizations | Less Volatility | None | No Impact | ||||
|
Cash Flow Hedge Accounting
|
Realizations & Ineffectiveness | Less Volatility | Fair Value Changes | More Volatility | ||||
|
Mark-to-Market
Accounting
|
Fair Value Changes | More Volatility | Fair Value Changes | More Volatility | ||||
Our determination of the accounting method does not impact our
cash flows related to derivatives.
Additional discussion of the accounting for energy contracts at
fair value is included in Notes 1 and 15 of Notes to
Consolidated Financial Statements.
Oil-
and Gas-Producing Activities
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:
| • | An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates. | |
| • | Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses, including that for goodwill. |
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, approximately
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 cost and 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. Such
changes could trigger an impairment of our oil and
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Table of Contents
gas properties
and/or
goodwill and have an impact on our
depreciation, depletion
and amortization
expense prospectively. For example, a
change of approximately 10 percent in our total oil and gas
reserves could change our annual
depreciation, depletion and
amortization
expense between approximately $72 million
and $87 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. Significant unfavorable changes in the
forward price curve could result in an impairment of our oil and
gas properties
and/or
goodwill.
Contingent
Liabilities
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 when 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 16 of Notes to Consolidated
Financial Statements.
Valuation
of Deferred Tax Assets and Tax Contingencies
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, 2009,
we have $681 million of deferred tax assets for which a
$4 million valuation allowance has been established. When
assessing the need for a valuation allowance, we consider
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. 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. We
evaluate the liability associated with our various filing
positions by applying the two step process of recognition and
measurement. The ultimate disposition of these contingencies
could have a significant impact on operating results and 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.
Pension
and Postretirement Obligations
We have employee benefit plans that include pension and other
postretirement benefits. Net periodic benefit expense and
obligations for these plans 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.
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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.
| Benefit Expense | Benefit Obligation | |||||||||||||||
|
One-Percentage-
|
One-Percentage-
|
One-Percentage-
|
One-Percentage-
|
|||||||||||||
| Point Increase | Point Decrease | Point Increase | Point Decrease | |||||||||||||
| (Millions) | ||||||||||||||||
|
Pension benefits:
|
||||||||||||||||
|
Discount rate
|
$ | (9 | ) | $ | 10 | $ | (114 | ) | $ | 135 | ||||||
|
Expected long-term rate of return on plan assets
|
(9 | ) | 9 | — | — | |||||||||||
|
Rate of compensation increase
|
3 | (2 | ) | 12 | (10 | ) | ||||||||||
|
Other postretirement benefits:
|
||||||||||||||||
|
Discount rate
|
(2 | ) | 3 | (30 | ) | 36 | ||||||||||
|
Expected long-term rate of return on plan assets
|
(1 | ) | 1 | — | — | |||||||||||
|
Assumed health care cost trend rate
|
2 | (2 | ) | 33 | (27 | ) | ||||||||||
Our expected long-term rates of return on plan assets, as
determined at the beginning of each fiscal year, are based on
the average rate of return expected on the funds invested in the
plans. We determine our long-term expected rate of return on
plan assets using our expectations of capital market results,
which includes an analysis of historical results as well as
forward-looking projections. These capital market expectations
are based on a long-term period of at least ten years and
consider our investment strategy and mix of assets, which is
weighted toward domestic and international equity securities. We
develop our expectations using input from several external
sources, including consultation with our third-party independent
investment consultant. The forward-looking capital market
projections are developed using a consensus of economists’
expectations for inflation, GDP growth, and dividend yield along
with expected changes in risk premiums. The capital market
return projections for specific asset classes in the investment
portfolio are then applied to the relative weightings of the
asset classes in the investment portfolio. The resulting rate is
an estimate of future results and, thus, likely to be different
than actual results.
The capital markets improved in 2009 and the benefit plans’
assets reflect this improvement. While the 2009 investment
performance was greater than our expected rates of return, the
expected rates of return on plan assets are long-term in nature
and are not significantly impacted by short-term market
performance. Changes to our asset allocation would also impact
these expected rates of return. Our expected long-term rate of
return on plan assets used for our pension plans has been
7.75 percent since 2006. The 2009 actual return on plan
assets for our pension plans was a gain of approximately
21.8 percent. The ten-year average rate of return on
pension plan assets through December 2009 was approximately
2.2 percent and is largely affected by the approximately
34.1 percent loss experienced in 2008.
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 are 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 by the duration of our
plans’ liabilities.
The expected rate of compensation increase represents average
long-term salary increases. An increase in this rate causes the
pension obligation and expense to increase.
The assumed health care cost trend rates are based on national
trend rates adjusted for our actual historical cost rates and
plan design. An increase in this rate causes the other
postretirement benefit obligation and expense to increase.
50
Table of Contents
Fair
Value Measurements
Certain of our energy derivative assets and liabilities and
other assets trade in markets with lower availability of pricing
information requiring us to use unobservable inputs and are
considered Level 3 in the fair value hierarchy. At
December 31, 2009, less than 1 percent of the total
assets and total liabilities measured at fair value on a
recurring basis are included in Level 3. For Level 2
transactions, we do not make significant adjustments to
observable prices in measuring fair value as we do not generally
trade in inactive markets.
The determination of fair value for our assets and liabilities
also incorporates the time value of money and various credit
risk factors which can include the credit standing of the
counterparties involved, master netting arrangements, the impact
of credit enhancements (such as cash collateral posted and
letters of credit) and our nonperformance risk on our
liabilities. The determination of the fair value of our
liabilities does not consider noncash collateral credit
enhancements. For net derivative assets, we apply a credit
spread, based on the credit rating of the counterparty, against
the net derivative asset with that counterparty. For net
derivative liabilities we apply our own credit rating. We derive
the credit spreads by using the corporate industrial credit
curves for each rating category and building a curve based on
certain points in time for each rating category. The spread
comes from the discount factor of the individual corporate
curves versus the discount factor of the LIBOR curve. At
December 31, 2009, the credit reserve is less than
$1 million on our net derivative assets and $3 million
on our net derivative liabilities. Considering these factors and
that we do not have significant risk from our net credit
exposure to derivative counterparties, the impact of credit risk
is not significant to the overall fair value of our derivatives
portfolio.
At December 31, 2009, 82 percent of our derivatives
portfolio expires in the next 12 months and more than
99 percent of our derivatives portfolio expires in the next
36 months. Our derivatives portfolio is largely comprised
of exchange-traded products or like products where price
transparency has not historically been a concern. Due to the
nature of the markets in which we transact and the relatively
short tenure of our derivatives portfolio, we do not believe it
is necessary to make an adjustment for illiquidity. We regularly
analyze the liquidity of the markets based on the prevalence of
broker pricing and exchange pricing for products in our
derivatives portfolio.
At December 31, 2009, Level 2 includes option
contracts that hedge future sales of production from our
Exploration & Production segment; these options are
structured as costless collars and are financially settled. They
are valued using an industry standard Black-Scholes option
pricing model. Prior to the third quarter of 2009, these options
were included in Level 3 because a significant input to the
model, implied volatility by location, was considered
unobservable. However, due to the increased transparency, we now
consider this input to be observable and have included these
options in Level 2.
The instruments included in Level 3 at December 31,
2009, consist of natural gas liquids swaps for our Midstream
segment as well as natural gas index transactions that are used
to manage the physical requirements of our
Exploration & Production and Midstream segments. The
change in the overall fair value of instruments included in
Level 3 primarily results from changes in commodity prices.
Exploration & Production has an unsecured credit
agreement through December 2013 with certain banks that, so long
as certain conditions are met, serves to reduce our usage of
cash and other credit facilities for margin requirements related
to instruments included in the facility.
For the year ended December 31, 2009, we have recognized
impairments of certain assets that have been measured at fair
value on a nonrecurring basis. These impairment measurements are
included in Level 3 as they include significant
unobservable inputs, such as our estimate of future cash flows
and the probabilities of alternative scenarios. (See
Note 14 of notes to Consolidated Financial Statements.)
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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, 2009. The results of operations by segment are
discussed in further detail following this consolidated overview
discussion.
| Years Ended December 31, | ||||||||||||||||||||||||||||
|
$ Change
|
% Change
|
$ Change
|
% Change
|
|||||||||||||||||||||||||
|
from
|
from
|
from
|
from
|
|||||||||||||||||||||||||
| 2009 | 2008* | 2008* | 2008 | 2007* | 2007* | 2007 | ||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
|
Revenues
|
$ | 8,255 | −3,635 | −31 | % | $ | 11,890 | +1,651 | +16 | % | $ | 10,239 | ||||||||||||||||
|
Costs and expenses:
|
||||||||||||||||||||||||||||
|
Costs and operating expenses
|
6,081 | +2,695 | +31 | % | 8,776 | −944 | −12 | % | 7,832 | |||||||||||||||||||
|
Selling, general and administrative expenses
|
512 | −8 | −2 | % | 504 | −43 | −9 | % | 461 | |||||||||||||||||||
|
Other (income) expense — net
|
17 | −89 | NM | (72 | ) | +70 | NM | (2 | ) | |||||||||||||||||||
|
General corporate expenses
|
164 | −15 | −10 | % | 149 | +12 | +7 | % | 161 | |||||||||||||||||||
|
Total costs and expenses
|
6,774 | 9,357 | 8,452 | |||||||||||||||||||||||||
|
Operating income
|
1,481 | 2,533 | 1,787 | |||||||||||||||||||||||||
|
Interest accrued — net
|
(585 | ) | −8 | −1 | % | (577 | ) | +55 | +9 | % | (632 | ) | ||||||||||||||||
|
Investing income
|
46 | −143 | −76 | % | 189 | −63 | −25 | % | 252 | |||||||||||||||||||
|
Early debt retirement costs
|
(1 | ) | — | — | (1 | ) | +18 | +95 | % | (19 | ) | |||||||||||||||||
|
Other income — net
|
2 | +2 | NM | — | −12 | −100 | % | 12 | ||||||||||||||||||||
|
Income from continuing operations before income taxes
|
943 | 2,144 | 1,400 | |||||||||||||||||||||||||
|
Provision for income taxes
|
359 | +318 | +47 | % | 677 | −187 | −38 | % | 490 | |||||||||||||||||||
|
Income from continuing operations
|
584 | 1,467 | 910 | |||||||||||||||||||||||||
|
Income (loss) from discontinued operations
|
(223 | ) | −348 | NM | 125 | −45 | −26 | % | 170 | |||||||||||||||||||
|
Net income
|
361 | 1,592 | 1,080 | |||||||||||||||||||||||||
|
Less: Net income attributable to noncontrolling interests
|
76 | +98 | +56 | % | 174 | −84 | −93 | % | 90 | |||||||||||||||||||
|
Net income attributable to The Williams Companies, Inc.
|
$ | 285 | $ | 1,418 | $ | 990 | ||||||||||||||||||||||
| * | + = Favorable change; − = Unfavorable change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator, or a percentage change greater than 200. |
2009 vs.
2008
Our consolidated results in 2009 declined significantly compared
to 2008. These results reflect a rapid decline in energy
commodity prices that began in the fourth quarter of 2008 as a
result of the weakened economy. Energy commodity prices have
generally improved during 2009, but not to levels experienced
early in 2008.
The decrease in
revenues
is primarily due to decreased
realized revenue at Gas Marketing primarily reflecting a
decrease in average natural gas prices as well as lower natural
gas liquid (NGL) and olefin production revenues and lower
marketing revenues at Midstream. In addition,
Exploration & Production revenues decreased primarily
due to lower net realized average prices, partially offset by
higher production volumes sold.
The decrease in
costs and operating expenses
is primarily
due to decreased costs at Gas Marketing primarily reflecting a
decrease in average natural gas prices as well as decreased
marketing purchases and decreased costs associated with our
olefin and NGL production businesses at Midstream.
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Table of Contents
Other (income) expense — net
within
operating income
in 2009 includes:
| • | Gain of $40 million on the sale of our Cameron Meadows NGL processing plant at Midstream; | |
| • | Expense of $32 million related to penalties from the early termination of certain drilling rig contracts at Exploration & Production; | |
| • | Impairment charges totaling $20 million at Exploration & Production. |
Other (income) expense — net
within
operating income
in 2008 includes:
| • | Gain of $148 million on the sale of our Peru interests at Exploration & Production; | |
| • | Net gains of $39 million on foreign currency exchanges at Midstream; | |
| • | Income of $32 million related to the partial settlement of our Gulf Liquids litigation at Midstream; | |
| • | Gain of $10 million on the sale of certain south Texas assets at Gas Pipeline; | |
| • | Income of $17 million resulting from involuntary conversion gains at Midstream; | |
| • | Impairment charges totaling $143 million related to certain natural gas producing properties at Exploration & Production; | |
| • | Expense of $23 million related to project development costs at Gas Pipeline. |
General corporate expenses
increased primarily due to an
increase in employee-related expenses, partially offset by a
decrease in outside services.
The decrease in
operating income
generally reflects an
overall unfavorable energy commodity price environment in 2009
compared to 2008 and other changes as previously discussed.
The decrease in
investing income
is primarily due to a
$75 million impairment of Midstream’s Accroven
investment and an $11 million impairment of a cost-based
investment at Exploration & Production. (See
Note 3 of Notes to Consolidated Financial Statements.) A
decrease in interest income, primarily due to lower average
interest rates in 2009 compared to 2008, also contributed to the
decrease in
investing income.
Provision for income taxes
decreased primarily due to
lower pre-tax income. See Note 5 of Notes to Consolidated
Financial Statements for a reconciliation of the effective tax
rates compared to the federal statutory rate for both years.
See Note 2 of Notes to Consolidated Financial Statements
for a discussion of the items in
income (loss) from
discontinued operations
.
Net income attributable to noncontrolling interests
decreased reflecting the first-quarter 2009 impairments and
related charges associated with Midstream’s discontinued
Venezuela operations (see Note 2 of Notes to Consolidated
Financial Statements) and the decline in Williams Partners
L.P.’s operating results primarily driven by lower NGL
margins.
2008 vs.
2007
Our consolidated results in 2008 improved significantly compared
to 2007. However, these results were considerably influenced by
favorable results in the first three quarters of the year,
followed by a sharp decline in the fourth quarter due to a rapid
decline in energy commodity prices.
The increase in
revenues
is primarily due to higher
production revenues at Exploration & Production
resulting from both higher net realized average prices and
increased production volumes sold. Midstream also experienced
higher olefin production revenues primarily due to higher
average prices and volumes as well as increased NGL production
revenues resulting from higher average prices, partially offset
by lower volumes. Additionally, Gas Marketing revenues increased
primarily due to favorable price movements on derivative
positions economically hedging the anticipated withdrawals of
natural gas from storage and the absence of a loss recognized on
a legacy derivative sales contract in 2007.
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Table of Contents
The increase in
costs and operating expenses
is primarily
due to increased costs associated with our olefin and NGL
production businesses at Midstream. Higher depreciation,
depletion, and amortization and higher operating taxes at
Exploration & Production also contributed to the
increase in expenses.
The increase in
selling, general and administrative expenses
(
SG&A)
primarily includes the impact of higher
staffing and compensation at our Exploration &
Production and Midstream segments in support of increased
operational activities.
Other (income) expense — net
within
operating income
in 2007 includes:
| • | Income of $18 million associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral; | |
| • | Income of $17 million associated with a change in estimate related to a regulatory liability at Northwest Pipeline; | |
| • | Income of $12 million related to a favorable litigation outcome at Midstream; | |
| • | Income of $8 million due to the reversal of a planned major maintenance accrual at Midstream; | |
| • | Expense of $20 million related to an accrual for litigation contingencies at Gas Marketing; | |
| • | Net losses of $11 million on foreign currency exchanges at Midstream; | |
| • | Expense of $10 million related to an impairment of the Carbonate Trend pipeline at Midstream. |
The increase in
operating income
reflects improved
operating results at Exploration & Production due to
higher net realized average prices, natural gas production
growth and a gain of $148 million on the sale of our Peru
interests, partially offset by increased operating costs and
$143 million of property impairments in 2008. The increase
also reflects improved results at Gas Marketing primarily due to
favorable price movements on derivative positions economically
hedging the anticipated withdrawals of natural gas from storage
and the absence of a loss recognized on a legacy derivative
sales contract in 2007. Partially offsetting these increases is
a decrease in
operating income
at Midstream primarily due
to a sharp decline in energy commodity prices in the latter part
of 2008.
Interest accrued — net
decreased primarily due
to increased capitalized interest resulting from an increased
level of capital expenditures. The decrease was also a result of
lower interest rates on debt issuances that occurred late in the
fourth quarter of 2007 and in the first half of 2008 for which
the proceeds were primarily used to retire existing debt bearing
higher interest rates. While our overall debt balances have been
relatively comparable, the net effect of these retirements and
issuances has resulted in lower rates.
The decrease in
investing income
is primarily due to a
decrease in interest income largely resulting from lower average
interest rates in 2008 compared to 2007.
Early debt retirement costs
in 2007 includes
$19 million of premiums and fees related to the December
2007 repurchase of senior unsecured notes.
Provision for income taxes
increased primarily due to
higher pre-tax income partially offset by a reduction in our
estimate of the effective deferred state tax rate in 2008. See
Note 5 of Notes to Consolidated Financial Statements for a
reconciliation of the effective tax rate compared to the federal
statutory rate for both years.
See Note 2 of Notes to Consolidated Financial Statements
for a discussion of the items in
income (loss) from
discontinued operations.
Net income attributable to noncontrolling interests
increased primarily reflecting the growth in the
noncontrolling interest holdings of Williams Partners L.P. and
Williams Pipeline Partners L.P. in late 2007 and early 2008,
respectively.
54
Table of Contents
Results
of Operations — Segments
As of December 31, 2009, we are organized into the
following segments: Exploration & Production, Gas
Pipeline, Midstream, Gas Marketing Services, and Other. Other
primarily consists of corporate operations. Our management
evaluates performance based on segment profit (loss) from
operations. (See Note 18 of Notes to Consolidated Financial
Statements.)
As previously discussed, our reportable segments will change in
the first quarter of 2010 as a result of our restructuring
transactions.
Exploration &
Production
Overview
of 2009
Segment revenues and segment profit for 2009 were significantly
lower than 2008 primarily due to a sharp decline in net realized
average prices partially offset by higher production volumes.
Additionally, 2009 results include expense of $32 million
associated with contractual penalties from the early termination
of drilling rig contracts and $20 million of impairment
charges. Highlights of the comparative periods include:
| For The Years Ended December 31, | ||||||||||||
| 2009 | 2008 | % Change | ||||||||||
|
Average daily domestic production sold (MMcfe)(1)
|
1,182 | 1,094 | +8 | % | ||||||||
|
Average daily total production sold (MMcfe)
|
1,236 | 1,144 | +8 | % | ||||||||
|
Domestic net realized average price ($/Mcfe)(2)
|
$ | 4.22 | $ | 6.48 | −35 | % | ||||||
|
Capital expenditures incurred ($ millions)
|
$ | 1,291 | $ | 2,519 | −49 | % | ||||||
|
Segment revenues ($ millions)
|
$ | 2,219 | $ | 3,121 | −29 | % | ||||||
|
Segment profit ($ millions)
|
$ | 418 | $ | 1,260 | −67 | % | ||||||
| (1) | MMcfe is equal to one million cubic feet of gas equivalent. | |
| (2) | Mcfe is equal to one thousand cubic feet of gas equivalent. |
| • | The increased production is primarily within the Piceance, Powder River, and Fort Worth basins. We reduced development activities and related capital expenditures in 2009, which resulted in production peaking during the first quarter of 2009, then decreasing slightly thereafter. | |
| • | Net realized average prices include market prices, net of fuel and shrink and hedge gains and losses, less gathering and transportation expenses. The realized hedge gain per Mcfe was $1.43 and $.09 for 2009 and 2008, respectively. |
We drilled 875 gross domestic productive development wells
in 2009 with a success rate of 99 percent. On
January 14, 2009, the SEC issued the
Final Rule for
Modernization of Oil and Gas Reporting
which affects how oil
and gas companies report their reserves. These changes included:
(1) applying the expanded definition of oil and gas
reserves used for reserves estimation supported by reliable
technologies and reasonable certainty; (2) revising proved
undeveloped reserve estimates based on new guidance; and
(3) estimating proved reserves for disclosure in SEC
filings using the
12-month
average,
first-of-the-month
price instead of a
single-day,
period-end price. The FASB substantially conformed its
requirements to the SEC rule with the issuance of its Accounting
Standards Update
2010-03,
Oil and Gas Reserve Estimation and Disclosures
. Our
estimated domestic proved reserves as of December 31, 2009
are 4,255 Bcfe.
Significant
Events
In June 2009, we entered into an agreement that allows us to
acquire, through a “drill to earn” structure, a
50 percent interest in approximately 44,000 net acres
in Pennsylvania’s Marcellus Shale in the Appalachian basin.
This agreement requires us to fund $33 million of drilling
and completion costs on behalf of our partner and
$41 million of our own costs and expenses prior to the end
of 2011 to earn our 50 percent interest. This growth
55
Table of Contents
opportunity leverages our experience in developing
nonconventional natural gas reserves. Through December 2009, we
have funded $14 million of the $33 million.
In September 2009, we completed the purchase of additional
unproved leasehold acreage and proved properties in the Piceance
basin for $253 million. In December 2009, we increased our
working interest in these properties through a $22 million
acquisition.
Outlook
for 2010
We expect natural gas prices to increase in 2010, resulting in
higher segment revenues and segment profit. We plan to maintain
capital expenditures at a level similar to 2009 with a
consistent level of drilling rigs operating in 2010 compared to
2009. We have the following expectations and objectives for 2010:
| • | Continuation of our development drilling program in the Piceance, Fort Worth, Powder River, San Juan and Appalachian basins. Our capital expenditures for 2010 are projected to be between $1 billion and $1.4 billion. This includes our drilling program in the Marcellus Shale that will enable us to meet the terms of our agreement as previously discussed. | |
| • | Annual average daily domestic production level consistent with 2009, with fourth quarter 2010 volumes likely to be higher than the prior year comparable period. | |
| • | Stability in the costs of services and materials associated with development activities. |
Risks to achieving our expectations and objectives include
unfavorable natural gas market price movements which are
impacted by numerous factors, including weather conditions,
domestic natural gas production levels and demand, and a slower
recovery in the global economy than expected. A significant
decline in natural gas prices could impact these expectations
for 2010, although the impact would be somewhat mitigated by our
hedging program, which hedges a significant portion of our
expected production.
In addition, changes in laws and regulations may impact our
development drilling program. For example, the Colorado
Oil & Gas Conservation Commission enacted new rules
effective in April 2009 which increased our costs of permitting
and environmental compliance and could potentially delay
drilling permits. The new rules included additional
environmental and operational requirements as part of permit
approvals, tracking of certain chemicals brought on location,
increased wildlife stipulations, new pit and waste management
procedures and increased notifications and approvals from
surface landowners. Our current outlook incorporates these
changes; however, the extent and magnitude of other changes in
laws and regulations could be greater than our current
assumptions.
Commodity
Price Risk Strategy
To manage the commodity price risk and volatility of owning
producing gas properties, we enter into derivative contracts for
a portion of our future production. For 2010, we have the
following contracts for our daily domestic production, shown at
weighted average volumes and basin-level weighted average prices:
| 2010 | ||||||||
|
Price ($/Mcf)
|
||||||||
|
Volume
|
Floor-Ceiling for
|
|||||||
| (MMcf/d) | Collars | |||||||
|
Collars — Rockies
|
100 | $ | 6.53 - $8.94 | |||||
|
Collars — San Juan
|
233 | $ | 5.75 - $7.82 | |||||
|
Collars — Mid-Continent
|
105 | $ | 5.37 - $7.41 | |||||
|
Collars — Southern California
|
45 | $ | 4.80 - $6.43 | |||||
|
Collars — Other
|
28 | $ | 5.63 - $6.87 | |||||
|
NYMEX and basis fixed-price
|
120 | $4.40 | ||||||
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The following is a summary of our contracts for daily production
for the years ended December 31, 2009, 2008 and 2007:
| 2009 | 2008 | 2007 | ||||||||||
|
Price ($/Mcf)
|
Price ($/Mcf)
|
Price ($/Mcf)
|
||||||||||
|
Volume
|
Floor-Ceiling
|
Volume
|
Floor-Ceiling
|
Volume
|
Floor-Ceiling
|
|||||||
| (MMcf/d) | for Collars | (MMcf/d) | for Collars | (MMcf/d) | for Collars | |||||||
|
Collars — NYMEX
|
— | — | — | — | 15 | $6.50 - $8.25 | ||||||
|
Collars — Rockies
|
150 | $6.11 - $9.04 | 170 | $6.16 -$9.14 | 50 | $5.65 - $7.45 | ||||||
|
Collars — San Juan
|
245 | $6.58 - $9.62 | 202 | $6.35 - $8.96 | 130 | $5.98 - $9.63 | ||||||
|
Collars — Mid-Continent
|
95 | $7.08 - $9.73 | 63 | $7.02 -$9.72 | 76 | $6.82 - $10.77 | ||||||
|
NYMEX and basis fixed-price
|
106 | $3.67 | 70 | $3.97 | 172 | $3.90 | ||||||
Additionally, we utilize contracted pipeline capacity through
Gas Marketing Services to move our production from the Rockies
to other locations when pricing differentials are favorable to
Rockies pricing. We hold a long-term obligation through Gas
Marketing Services to deliver on a firm basis 200,000 MMbtu
per day of gas to a buyer at the White River Hub
(Greasewood-Meeker, Colorado), which is the major market hub
exiting the Piceance basin. Our interest in the Piceance basin
holds ample reserves to meet this obligation.
Year-Over-Year
Operating Results
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Segment revenues
|
$ | 2,219 | $ | 3,121 | $ | 2,021 | ||||||
|
Segment profit
|
$ | 418 | $ | 1,260 | $ | 756 | ||||||
2009 vs.
2008
The decrease in total
segment revenues
is primarily due
to the following:
| • | $725 million, or 27 percent, decrease in domestic production revenues reflecting $935 million associated with a 35 percent decrease in net realized average prices, partially offset by an increase of $210 million associated with a 8 percent increase in production volumes sold. Production revenues in 2009 and 2008 include approximately $93 million and $85 million, respectively, related to natural gas liquids (NGL) and approximately $36 million and $62 million, respectively, related to condensate. While NGL volumes were significantly higher than the prior year, NGL prices were significantly lower. | |
| • | $169 million decrease primarily reflecting lower average sales prices for gas management activities related to gas purchased from certain outside parties, which is offset by a similar decrease in segment costs and expenses. |
Total
segment costs and expenses
decreased
$62 million, primarily due to the following:
| • | $163 million lower operating taxes due primarily to 56 percent lower average market prices (excluding the impact of hedges), partially offset by higher production volumes sold. The lower operating taxes include a net decrease of $39 million reflecting a $34 million charge in 2008 and $5 million of favorable revisions in 2009 relating to Wyoming severance and ad valorem tax issues; | |
| • | $165 million decrease primarily reflecting lower average sales prices for gas management activities related to gas purchased from certain outside parties, which is offset by a similar decrease in segment revenues ; | |
| • | $143 million due to the absence of property impairments recorded in 2008 in the Arkoma basin; | |
| • | $8 million lower lease and other operating expenses due to lower industry costs and activity partially offset by the effect of an increase in production volumes; |
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| • | $5 million lower SG&A expenses, which includes lower bad debt expense related to the partial recovery of certain receivables previously reserved for in 2008 resulting from a bankrupt counterparty. |
Partially offsetting the decreased costs are increases due to
the following:
| • | The absence of a $148 million gain recorded in 2008 associated with the sale of our Peru interests; | |
| • | $152 million higher depreciation, depletion and amortization expense primarily due to the impact of higher capitalized drilling costs from prior years and higher production volumes compared to the prior year. Also, we recorded an additional $17 million of depreciation, depletion, and amortization in the fourth quarter of 2009 primarily due to new SEC reserves reporting rules. Our proved reserves decreased primarily due to the new SEC reserves reporting rules and the related price impact; | |
| • | $48 million higher gathering fees primarily due to higher production volumes and the processing fees for natural gas liquids at Midstream’s Willow Creek plant, which began processing in August 2009; | |
| • | $32 million of expense related to penalties from the early release of drilling rigs as previously discussed; | |
| • | $20 million of impairment costs in the Fort Worth and Arkoma basins. We recorded a $15 million impairment in 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth basin. This impairment was based on our assessment of estimated future discounted cash flows and additional information obtained from drilling and other activities in 2009. We also recorded a $5 million impairment in the Arkoma basin in 2009 related to facilities; | |
| • | $31 million higher exploratory expense in 2009, primarily related to $20 million of increased seismic costs and $12 million related to higher amortization and the write-off of lease acquisition costs. Dry hole costs for 2009 and 2008 were $11 million and $12 million, respectively. As of December 31, 2009 we have approximately $14 million of capitalized drilling costs and $24 million of undeveloped leasehold costs related to continuing exploratory activities in the Paradox basin. |
The $842 million decrease in s
egment profit
is
primarily due to the 35 percent decrease in net realized
average domestic prices and the other previously discussed
changes in
segment revenues
and
segment costs and
expenses.
2008 vs.
2007
The increase in total
segment revenues
is primarily due
to the following:
| • | $919 million, or 53 percent, increase in domestic production revenues reflecting $571 million associated with a 28 percent increase in net realized average prices and $348 million associated with a 20 percent increase in production volumes sold. The impact of hedge positions on increased net realized average prices includes the effect of fewer volumes hedged by fixed-price contracts. The increase in production volumes reflects an increase in the number of producing wells primarily from the Piceance, Powder River, and Fort Worth basins. Production revenues in 2008 and 2007 include approximately $85 million and $53 million, respectively, related to natural gas liquids and approximately $62 million and $40 million, respectively, related to condensate. | |
| • | $151 million increase in revenues for gas management activities related to gas purchased from certain outside parties, which is substantially offset by a similar increase in segment costs and expenses . This increase is primarily due to increases in natural gas prices and volumes sold. | |
| • | $17 million favorable change related to hedge ineffectiveness due to $1 million in net unrealized gains from hedge ineffectiveness in 2008 compared to $16 million in net unrealized losses in 2007. |
Total
segment costs and expenses
increased
$591 million, primarily due to the following:
| • | $202 million higher depreciation, depletion and amortization expense, primarily due to higher production volumes and increased capitalized drilling costs. | |
| • | $149 million increase in expenses for gas management activities related to gas purchased from certain outside parties, which is offset by a similar increase in segment revenues . |
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| • | $143 million of property impairments in 2008 in the Arkoma basin. | |
| • | $118 million higher operating taxes primarily due to both higher average market prices and higher domestic production volumes sold and the $34 million charge related to the Wyoming severance and ad valorem tax issue. | |
| • | $61 million higher lease operating expenses from the increased number of producing wells primarily within the Piceance, Powder River, and Fort Worth basins combined with increased prices for well and lease service expenses and higher facility expenses. | |
| • | $28 million higher SG&A expenses primarily due to increased staffing in support of increased drilling and operational activity, including higher compensation. The higher SG&A expenses also include an increase of $11 million in bad debt expense. | |
| • | $17 million higher gathering expenses due to higher domestic production volumes. | |
| • | $17 million of expense in 2008 related to the write-off of certain exploratory drilling costs for our domestic and international operations. |
These increases are partially offset by the $148 million
gain associated with the sale of our Peru interests in 2008.
The $504 million increase in s
egment profit
is
primarily due to the 28 percent increase in domestic net
realized average prices and the 20 percent increase in
domestic production volumes sold, partially offset by the
increase in total
segment costs and expenses
.
Gas
Pipeline
Overview
Gas Pipeline’s strategy to create value 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 near-term impact on revenues
because the majority of cost of service is recovered through
firm capacity reservation charges in transportation rates.
Gas
Pipeline master limited partnership
At December 31, 2009, we own approximately
47.7 percent of WMZ, including 100 percent of the
general partner, and incentive distribution rights. Considering
the presumption of control of the general partner, we
consolidate WMZ within our Gas Pipeline segment. Gas
Pipeline’s segment profit includes 100 percent of
WMZ’s segment profit. As previously discussed, our
ownership in WMZ was affected by our 2010 restructuring
transactions.
Significant events of 2009 include:
Completed
Expansion Projects
Gulfstream
Phase IV
In September 2007, our 50 percent-owned equity investee,
Gulfstream, received FERC approval to construct 17.8 miles
of
20-inch
pipeline and to install a new compressor facility. The pipeline
expansion was placed into service in the fourth quarter of 2008,
and the compressor facility was placed into service in January
2009. The expansion increased capacity by 155 Mdt/d.
Gulfstream’s cost of this project is $190 million.
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Sentinel
In August 2008, we received FERC approval to construct an
expansion in the northeast United States. The cost of the
project is estimated to be $229 million. We placed Phase I
into service in December 2008 increasing capacity by 40 Mdt/d.
Phase II provided an additional 102 Mdt/d and was placed
into service in November 2009.
Colorado
Hub Connection
In April 2009, we received approval from the FERC to construct a
27-mile
pipeline to provide increased access to the Rockies natural gas
supplies. Construction began in June 2009 and the project was
placed into service in November 2009. We combined lateral
capacity with existing mainline capacity to provide
approximately 363 Mdt/d of firm transportation from various
receipt points for delivery to Ignacio, Colorado. The estimated
cost of the project is $60 million.
In-progress
Expansion Projects
Mobile
Bay South
In May 2009, we received approval from the FERC to construct a
compression facility in Alabama allowing transportation service
to various southbound delivery points. The cost of the project
is estimated to be $37 million. The estimated project
in-service date is May 2010 and will increase capacity by 253
Mdt/d.
85
North
In September 2009, we received approval from the FERC to
construct an expansion of our existing natural gas transmission
system from Alabama to various delivery points as far north as
North Carolina. The cost of the project is estimated to be
$241 million. Phase I service is anticipated to begin in
July 2010 and will increase capacity by 90 Mdt/d. Phase II
service is anticipated to begin in May 2011 and will increase
capacity by 218 Mdt/d.
Mobile
Bay South II
In November 2009, we filed an application with the FERC to
construct additional compression facilities and modifications to
existing facilities in Alabama allowing transportation service
to various southbound delivery points. The cost of the project
is estimated to be $36 million. The estimated project
in-service date is May 2011 and will increase capacity by 380
Mdt/d.
Sundance
Trail
In November 2009, we received approval from the FERC to
construct approximately 16 miles of
30-inch
pipeline between our existing compressor stations in Wyoming.
The project also includes an upgrade to our existing compressor
station and is estimated to cost $65 million. The estimated
in-service date is November 2010 and will increase capacity by
150 Mdt/d.
Outlook
for 2010
In addition to the various in-progress expansion projects
previously discussed, we have several other proposed projects to
meet customer demands. Subject to regulatory approvals,
construction of some of these projects could begin as early as
2010.
Year-Over-Year
Operating Results
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Segment revenues
|
$ | 1,591 | $ | 1,634 | $ | 1,610 | ||||||
|
Segment profit
|
$ | 667 | $ | 689 | $ | 673 | ||||||
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2009 vs.
2008
Segment revenues
decreased primarily due to a
$53 million decrease in revenues from lower transportation
imbalance settlements in 2009 compared to 2008 (offset in
costs and operating expenses
), partially offset by a
$17 million increase in other service revenues and
expansion projects placed into service by Transco.
Costs and operating expenses
decreased $27 million,
or 3 percent, primarily due to a $53 million decrease
in costs associated with lower transportation imbalance
settlements in 2009 compared to 2008 (offset in
segment
revenues
) and $11 million of income from an adjustment
of state franchise taxes. Partially offsetting these decreases
is a $13 million increase in depreciation expense due
primarily to projects placed into service, a $10 million
increase in transportation-related fuel expense resulting from
less favorable recovery from customers due to pricing
differences, and $7 million higher employee-related
expenses.
SG&A
increased $6 million, or 4 percent,
primarily due to an increase in pension expense.
Other (income) expense — net
reflects the
absence of a $10 million gain on the sale of certain south
Texas assets and a $9 million gain on the sale of excess
inventory gas, both of which were recorded by Transco in 2008.
Partially offsetting these unfavorable changes is
$16 million lower project development costs in 2009.
Segment profit
decreased primarily due to the previously
described changes, partially offset by higher equity earnings
from Gulfstream.
2008 vs.
2007
Segment revenues
increased primarily due to a
$52 million increase in transportation revenues resulting
primarily from Transco’s new rates, which were approved by
the FERC as part of a general rate case and became effective
March 2007, and expansion projects that Transco placed into
service in the fourth quarter of 2007. In addition,
segment
revenues
increased $28 million due to transportation
imbalance settlements (offset in
costs and operating
expenses
). Partially offsetting these increases is the
absence of $59 million associated with a 2007 sale of
excess inventory gas (offset in
costs and operating
expenses
).
Costs and operating expenses
decreased $11 million,
or 1 percent, primarily due to the absence of
$59 million associated with a 2007 sale of excess inventory
gas (offset in
segment revenues
). The decrease is
partially offset by an increase in costs of $28 million
associated with transportation imbalance settlements (offset in
segment revenues
) and higher rental expense related to
the Parachute lateral that was transferred to Midstream in
December 2007.
Other (income) expense — net
changed
unfavorably by $31 million primarily due to the absence of
$18 million of income recognized in 2007 associated with
payments received for a terminated firm transportation agreement
on Northwest Pipeline’s Grays Harbor lateral and the
absence of $17 million of income recorded in 2007 for a
change in estimate related to a regulatory liability at
Northwest Pipeline. In addition, project development costs were
$21 million higher in 2008. Partially offsetting these
unfavorable changes is a $10 million gain on the sale of
certain south Texas assets, and a $9 million gain on the
sale of excess inventory gas, both of which were recorded by
Transco in 2008.
The increase in
segment profit
is primarily due to the
previously described changes and higher equity earnings from
Gulfstream.
Midstream
Gas & Liquids
Overview
of 2009
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. We focus on consistently attracting new business by
providing highly reliable service to our customers.
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Significant events during 2009 include the following:
Cameron
Meadows Plant
In November 2009, we sold our Cameron Meadows plant and
recognized a pre-tax gain of $40 million. This plant
sustained hurricane damage twice in recent years and is,
therefore, considered incongruent with our strategy of providing
the most reliable service in the industry.
Willow
Creek
The Willow Creek facility in western Colorado began processing
natural gas production and extracting NGLs in early August and
achieved full processing operations in September. Currently, the
450-million-cubic-feet-per-day
(MMcf/d)
gas
processing plant primarily processes Exploration &
Production’s wellhead production, has a peak capacity of
30,000 barrels of NGLs per day, and is recovering
approximately 20,000 barrels per day. In the current
processing arrangement with Exploration & Production,
Midstream receives a volumetric-based processing fee and a
percent of the NGLs extracted.
Laurel
Mountain Midstream, LLC
In June 2009, we completed the formation of a new joint venture
in the Marcellus Shale located in southwest Pennsylvania. Our
partner in the venture contributed its existing Appalachian
basin gathering system, which currently has an average
throughput of approximately
100 MMcf/d.
In exchange for a 51 percent interest in the venture, we
contributed $100 million and issued a $26 million note
payable. We account for this investment under the equity method
due to the significant participatory rights of our partner such
that we do not control the investment. We have transitioned
operational control from our partner to us.
Venezuela
In May 2009, the Venezuelan government expropriated the El
Furrial and PIGAP II assets that we operated in Venezuela. As a
result, these operations are now reflected as discontinued
operations for all periods presented and are no longer included
in Midstream’s results. Our investment in Accroven, whose
assets have not been expropriated, is still included within
Midstream and reflects a first-quarter 2009 impairment charge of
$75 million. (See Notes 2 and 3 of Notes to
Consolidated Financial Statements for further discussion.)
Volatile
commodity prices
NGL prices, especially ethane prices, have generally improved
during 2009, following significant declines in the fourth
quarter of 2008 as a result of the weakened economy. Our NGL
margins also benefited from a period of declining natural gas
prices during 2009. While average annual
per-unit
NGL
margins in 2009 were still significantly lower than 2008, they
improved during 2009 to levels currently above the rolling
five-year average
per-unit
margin. We continued to benefit from favorable natural gas price
differentials in the Rocky Mountain area, although the
differentials narrowed during 2009. These differentials
contributed to realized
per-unit
margins that were generally greater than that of the industry
benchmarks for natural gas processed in the Henry Hub area and
for liquids fractionated and sold at Mont Belvieu, Texas.
NGL margins are defined as NGL revenues less any applicable BTU
replacement cost, plant fuel, and third-party transportation and
fractionation.
Per-unit
NGL
margins are calculated based on sales of our own equity volumes
at the processing plants.
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Domestic
Gathering and Processing Per Unit NGL Margin
with Production and Sales Volumes by Quarter
(excludes partially owned plants)
with Production and Sales Volumes by Quarter
(excludes partially owned plants)
Hurricane
Impact to Insurance Coverage
While our insurance expense has increased modestly in 2009
compared to 2008, the overall level of coverage on our offshore
assets in the Gulf Coast region against named windstorm events
has substantially decreased, including the absence of coverage
on certain of our assets. (See Note 9 of Notes to
Consolidated Financial Statements.)
Williams
Partners L.P.
As of December 31, 2009, we own approximately
23.6 percent of Williams Partners L.P., including
100 percent of the general partner and incentive
distribution rights. Considering the presumption of control of
the general partner, we consolidate Williams Partners L.P.
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. As previously discussed, our
ownership in Williams Partners L.P. and our future segment
reporting structure were affected by our 2010 restructuring
transactions.
Outlook
for 2010
The following factors could impact our business in 2010.
Commodity
price changes
| • | NGL, crude and natural gas prices are highly volatile and difficult to predict. However, we expect per-unit NGL margins in 2010 to be higher than our average per-unit margins in 2009 and our rolling five-year average per-unit NGL margins. NGL, crude and natural gas prices are highly volatile. NGL price changes have historically tracked somewhat with changes in the price of crude oil. Margins in our NGL and olefins business are highly dependent upon continued demand within the global economy. Although forecasted domestic and global demand for polyethylene, or plastics, has been impacted by the weakness in the global economy, NGL products are currently the preferred feedstock for ethylene and propylene production, which are the building blocks of polyethylene. Propylene and ethylene production processes have increasingly shifted from the more expensive crude-based feedstocks to NGL-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets. As |
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| natural gas pipeline transportation capacity increases in the Rocky Mountain area, we anticipate that historically favorable natural gas price differentials will decline. |
| • | In our olefin production business, we anticipate margins in 2010 to show an improvement over 2009, similarly benefiting from the dynamics discussed above. | |
| • | As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of a small portion of our anticipated NGL sales for 2010. In addition, we have entered into financial contracts to fix the price of a portion of our shrink gas requirements for 2010. |
Gathering,
processing, and NGL sales volumes
| • | The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities. Our customers are generally large producers and we have not experienced and do not anticipate an overall significant decline in volumes due to reduced drilling activity. | |
| • | In the West, we expect higher fee revenues, NGL volumes, depreciation expense and operating expenses in 2010 compared to 2009 as our Willow Creek facility moves into a full year of operation, and our expansion at Echo Springs is completed late in 2010. | |
| • | We expect fee revenues, NGL volumes, depreciation expense, and operating expenses in our offshore Gulf Coast region to increase from 2009 levels as our new Perdido Norte expansion begins start-up operations in the first quarter of 2010. Increases from our Perdido Norte expansion are expected to be partially offset by lower volumes in other Gulf Coast areas due to expected changes in gas processing contracts, as described below, and natural declines. | |
| • | Certain of our gas processing contracts contain provisions that allow customers to periodically elect processing services on either a fee basis, keep-whole, or percent-of-liquids basis. If customers switch from keep-whole to fee-based processing, this would reduce our NGL equity sales volumes. |
Allocation
of capital to expansion projects
We expect to spend $500 million to $750 million in
2010 on capital projects. The ongoing major expansion projects
include:
| • | The Perdido Norte project, in the western deepwater of the Gulf of Mexico, which includes an expansion of our Markham gas processing facility and oil and gas lines that will expand the scale of our existing infrastructure. Significant milestones have been reached and, considering the progress of our customer’s drilling and tie-in construction, we expect this project to begin start-up operations in the first quarter of 2010. | |
| • | Additional processing and NGL production capacities at our Echo Springs facility and related gathering system expansions in the Wamsutter area of Wyoming, which we expect to be in service at the end of 2010. | |
| • | We expect to begin construction in 2010 on a 12-inch pipeline in Canada, which will transport recovered natural gas liquids and olefins from our extraction plant in Ft. McMurray to our Redwater fractionation facility. The pipeline will have sufficient capacity to transport additional recovered liquids in excess of those from our current agreements. We anticipate an in-service date in 2012. | |
| • | In conjunction with a long-term agreement with a major producer, we will construct and operate a 28-mile natural gas gathering pipeline in the Marcellus Shale region that will deliver to the Transco pipeline. Construction is expected to begin on the 20-inch pipeline in the latter part of 2010, and it is expected to be placed into service during 2011. | |
| • | In addition to our initial investment, we intend to invest additional capital within our Laurel Mountain joint venture to grow the existing gathering infrastructure in 2010 and beyond. |
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Year-Over-Year
Operating Results
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Segment revenues
|
$ | 3,588 | $ | 5,180 | $ | 4,933 | ||||||
|
Segment profit (loss):
|
||||||||||||
|
Domestic gathering & processing
|
$ | 637 | $ | 841 | $ | 897 | ||||||
|
NGL marketing, olefins and other
|
162 | 113 | 174 | |||||||||
|
Venezuela
|
(68 | ) | 12 | 11 | ||||||||
|
Indirect general and administrative expense
|
(91 | ) | (95 | ) | (88 | ) | ||||||
|
Total
|
$ | 640 | $ | 871 | $ | 994 | ||||||
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.
2009 vs.
2008
The decrease in
segment revenues
is largely due to:
| • | A $716 million decrease in revenues associated with the production of NGLs primarily due to lower average NGL prices. | |
| • | A $457 million decrease in revenues in our olefins production business primarily due to lower average product prices, partially offset by higher volumes. | |
| • | A $438 million decrease in marketing revenues primarily due to lower average NGL and crude prices, partially offset by higher NGL volumes. |
These decreases are partially offset by a $52 million
increase in fee revenues primarily due to higher volumes
resulting from connecting new supplies in the deepwater Gulf of
Mexico in the latter part of 2008 and new fees for processing
Exploration & Production’s natural gas production
at Willow Creek.
Segment costs and expenses
decreased $1,443 million,
or 33 percent, primarily as a result of:
| • | A $586 million decrease in marketing purchases primarily due to lower average NGL and crude prices, including the absence of a $19 million charge in 2008 to write-down the value of NGL and olefin inventories, partially offset by higher NGL volumes. | |
| • | A $445 million decrease in costs in our olefins production business primarily due to lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin inventories, partially offset by higher volumes. | |
| • | A $435 million decrease in costs associated with the production of NGLs primarily due to lower average natural gas prices. | |
| • | A $40 million gain on the 2009 sale of our Cameron Meadows processing plant. | |
| • | The absence of $17 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations. |
These decreases are partially offset by:
| • | A $39 million unfavorable change due primarily to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations. |
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| • | The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation (see Note 16 of Notes to Consolidated Financial Statements). |
The decrease in Midstream’s
segment profit
reflects
the previously described changes in
segment revenues
and
segment costs and expenses
and a $75 million loss
from investment related to the impairment of our investment in
Accroven.
A more detailed analysis of the segment profit of certain
Midstream operations is presented as follows.
Domestic gathering & processing
The decrease in
domestic gathering & processing
segment profit
includes a $193 million decrease in the
West region and an $11 million decrease in the Gulf Coast
region.
The decrease in our West region’s
segment profit
includes:
| • | A $213 million decrease in NGL margins due to a significant decrease in average NGL prices, partially offset by a significant decrease in production costs reflecting lower natural gas prices. NGL equity volumes were slightly higher as both periods were impacted by significant volume changes. Current year volumes include the unfavorable impact of certain producers electing to convert, in accordance with those gas processing agreements, from keep-whole to fee-based processing at the beginning of 2009. Prior year NGL equity volumes sold were unusually low primarily due to an increase in inventory as we transitioned from product sales at the plant to shipping volumes through a pipeline for sale downstream, lower ethane recoveries to accommodate restrictions on the volume of NGLs we could deliver into the pipelines, and hurricane-related disruptions at a third-party fractionation facility at Mont Belvieu, Texas, which resulted in an NGL inventory build-up. Lower NGL transportation costs in the West region due to the transition from our previous shipping arrangement to transportation on the Overland Pass pipeline also favorably impacted NGL margins in 2009. | |
| • | An $8 million decrease in involuntary conversion gains related to our Ignacio plant. These insurance recoveries in both years were used to rebuild the plant. | |
| • | A $39 million increase in fee revenues primarily due to new fees for processing Exploration & Production’s natural gas production at Willow Creek, unusually low gathering and processing volumes in the first quarter of 2008 related to severe winter weather conditions, and producers converting from keep-whole to fee-based processing in the first quarter of 2009. |
The decrease in the Gulf Coast region’s
segment profit
includes:
| • | A $68 million decrease in NGL margins reflecting lower average NGL prices and lower volumes. Lower production costs reflecting lower natural gas prices partially offset these decreases. Both periods were impacted by unfavorable volume changes. Current year volumes include the unfavorable impact of periods of reduced NGL recoveries during the first quarter due to unfavorable NGL economics and natural declines in production sources. Prior year volumes were unusually low primarily due to periods of reduced NGL recoveries during the fourth quarter and as a result of hurricanes in the third quarter. | |
| • | A $40 million gain in 2009 on the sale of our Cameron Meadows processing plant, partially offset by the absence of a $5 million involuntary conversion gain in 2008 related to our Cameron Meadows plant. | |
| • | $26 million higher fee revenues primarily due to higher volumes resulting from connecting new supplies in the Blind Faith prospect in the deepwater in the latter part of 2008. | |
| • | The absence of $16 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations. | |
| • | An $11 million increase in depreciation primarily due to our Blind Faith pipeline extensions that came into service during the latter part of 2008. |
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NGL marketing, olefins and other
The significant components of the increase in
segment profit
of our other operations include:
| • | $138 million in higher margins related to the marketing of NGLs and olefins primarily due to favorable changes in pricing while product was in transit during 2009 as compared to significant unfavorable changes in pricing while product was in transit in 2008 and the absence of a $19 million charge in 2008 to write-down the value of NGL and olefin inventories. | |
| • | A $41 million unfavorable change primarily due to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations. | |
| • | The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation. | |
| • | $12 million in lower margins in our olefins production business primarily due to lower average prices, partially offset by lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin inventories, and higher volumes in 2009 related to the impact of third-party operational issues in 2008 that reduced off-gas supplies to our plant in Canada. | |
| • | The absence of an $8 million gain recognized in 2008 related to a final earn-out payment on a 2005 asset sale. |
Venezuela
The decrease in
segment profit
for our Venezuela
operations primarily reflects the previously discussed
$75 million loss from investment related to Accroven.
2008 vs.
2007
The increase in
segment revenues
is largely due to:
| • | A $210 million increase in revenues in our olefins production business primarily due to higher average product prices and also to higher volumes sold associated with the increase of our ownership interest in the Geismar olefins facility effective July 2007. | |
| • | A $163 million increase in revenues associated with the production of NGLs primarily due to higher average NGL prices, partially offset by lower volumes. Lower volumes resulted from reduced ethane recoveries at the plants during the third and fourth quarters of 2008 compared to higher volumes during 2007 as we transitioned from shipping volumes through a pipeline for sale downstream to product sales at the plant. | |
| • | A $50 million increase in fee-based revenues primarily due to the West region, the deepwater Gulf Coast region and at our Conway fractionation and storage facilities. |
These increases are partially offset by a $194 million
decrease in marketing revenues primarily due to lower volumes,
partially offset by higher prices.
Segment costs and expenses
increased $368 million,
or 9 percent, primarily as a result of:
| • | A $213 million increase in costs in our olefins production business due to higher feedstock prices and also to higher volumes produced associated with the increase of our ownership interest in the Geismar olefins facility effective July 2007. The increase also includes a $10 million higher charge to write-down the value of olefin inventories. | |
| • | A $191 million increase in costs associated with the production of NGLs primarily due to higher average natural gas prices. | |
| • | A $100 million increase in operating costs including higher depreciation, repair costs and property insurance deductibles related to the hurricanes, gas transportation expenses in the eastern Gulf of Mexico, |
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| employee costs, and higher costs associated with the increase of our ownership interest in the Geismar olefins facility. |
These increases are partially offset by:
| • | A $68 million decrease in marketing purchases primarily due to lower volumes, partially offset by higher average NGL and crude prices and a $19 million charge in 2008 to write-down the value of NGL and olefin inventories. | |
| • | A $49 million favorable change related to foreign currency exchange gains primarily due to the revaluation of current assets held in U.S. dollars within our Canadian operations. | |
| • | $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation. | |
| • | A $16 million favorable change due to higher involuntary conversion gains in 2008 related to insurance recoveries in excess of the carrying value of our Ignacio and Cameron Meadows plants. |
The decrease in Midstream’s
segment profit
reflects
the previously described changes in
segment revenues
and
segment costs and expenses
. A more detailed analysis of
the segment profit of certain Midstream operations is presented
as follows.
Domestic gathering & processing
The decrease in
domestic gathering & processing
segment profit
includes a $49 million decrease in the
West region and a $7 million decrease in the Gulf Coast
region.
The decrease in our West region’s
segment profit
includes:
| • | A $45 million decrease in NGL margins due to a significant increase in costs associated with the production of NGLs reflecting higher natural gas prices and lower volumes sold. The decrease in volumes sold is primarily due to restricted transportation capacity, unfavorable ethane economics, an increase in inventory during 2008, hurricane-related disruptions at a third-party fractionation facility, and lower equity volumes as processing agreements change from keep-whole to fee-based. These decreases were partially offset by a full year of production from the fifth train at our Opal processing plant, which began production in the first quarter of 2007. | |
| • | A $35 million increase in operating costs driven by higher turbine and engine overhaul expenses, depreciation expense and employee costs. | |
| • | The absence of a $12 million favorable litigation outcome in 2007. | |
| • | A $24 million increase in fee revenues including new lease revenues from Gas Pipeline for the Parachute lateral transferred to Midstream in December 2007. | |
| • | A $12 million involuntary conversion gain in 2008 related to our Ignacio plant. These insurance recoveries were used to rebuild the plant. |
The decrease in the Gulf Coast region’s
segment profit
is primarily due to $39 million higher operating costs
including higher depreciation, gas transportation expenses and
hurricane repair and property insurance deductibles. These
increased expenses are partially offset by $18 million
higher NGL margins and $8 million higher fee revenues
primarily due to connecting new supplies in the deepwater.
NGL marketing, olefins and other
The significant components of the decrease in
segment profit
of our other operations include:
| • | $123 million in lower margins related to the marketing of NGLs and olefins primarily due to the impact of a significant and rapid decline in NGL and olefin prices during the fourth quarter of 2008 on a higher volume of product inventory in transit. This also includes a $19 million charge in 2008 to write-down the value of NGL and olefin inventories. |
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| • | $33 million higher operating costs including higher costs associated with the increase of our ownership interest in the Geismar olefins facility effective July 2007 and hurricane damage repair expense at the Geismar plant. | |
| • | A $56 million favorable change in foreign currency exchange gains related to the revaluation of current assets held in U.S. dollars within our Canadian operations. | |
| • | $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation. |
Gas
Marketing Services
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 the
majority of fuel and shrink gas and hedging natural gas liquids
sales for Midstream. Gas Marketing also provides similar
services to third parties, such as producers and natural gas
processors. In addition, Gas Marketing manages various natural
gas-related contracts such as transportation and storage along
with the related hedges, including certain legacy natural gas
contracts and positions. We do not expect our future segment
profit will be significantly impacted by these legacy contracts
and positions.
Overview
of 2009
Gas Marketing’s operating results for 2009 are unfavorable
compared to 2008 primarily due to lower realized margins on our
storage contracts. This decline was partially offset by reduced
net losses on proprietary trading and legacy contracts and lower
adjustments to the carrying value of our natural gas storage
inventory.
Outlook
for 2010
For 2010, Gas Marketing will focus on providing services that
support our natural gas businesses. 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.
Year-Over-Year
Operating Results
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Realized revenues
|
$ | 3,031 | $ | 6,385 | $ | 4,948 | ||||||
|
Net forward unrealized
mark-to-market
gains (losses)
|
21 | 27 | (315 | ) | ||||||||
|
Segment revenues
|
$ | 3,052 | $ | 6,412 | $ | 4,633 | ||||||
|
Segment profit (loss)
|
$ | (18 | ) | $ | 3 | $ | (337 | ) | ||||
2009 vs.
2008
Realized revenues
represent (1) revenue from the
sale of natural gas and (2) gains and losses from the net
financial settlement of derivative contracts. The decrease in
realized revenues
is primarily due to a decrease in
physical natural gas revenue as a result of a 53 percent
decrease in average prices on physical natural gas sales,
slightly offset by a 3 percent increase in natural gas
sales volumes. This decline in
realized revenues
is
primarily related to both gas sales associated with our
transportation and storage contracts and gas sales associated
with marketing Exploration & Production’s natural
gas volumes. A corresponding decline in
segment costs and
expenses
occurred in 2009.
Net forward unrealized
mark-to-market
gains (losses)
primarily represent changes in the fair
values of certain 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. The
decrease in
net forward unrealized
mark-to-market
gains
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(losses)
is primarily related to the absence of a
$10 million favorable impact in 2008 for the initial
consideration of our own nonperformance risk in estimating the
fair value of our derivative liabilities.
Total segment costs and expenses
decreased
$3,339 million, primarily due to a 54 percent decrease
in average prices on physical natural gas purchases, slightly
offset by a 3 percent increase in natural gas purchase
volumes. This decrease is primarily related to the previously
discussed gas purchases associated with both our transportation
and storage contracts and gas purchases from Exploration and
Production. This decline also includes a lower adjustment to the
carrying value of natural gas inventory in storage. These
adjustments totaled $7 million in 2009 compared to
$35 million in 2008.
The unfavorable change in
segment profit (loss)
is
primarily due to a decline in realized margins on our storage
contracts partially offset by lower adjustments to the carrying
value of our natural gas storage inventory and reduced net
losses on proprietary trading and legacy contracts.
2008 vs.
2007
The increase in
realized revenues
is primarily due to an
increase in physical natural gas revenue as a result of a
26 percent increase in average prices on physical natural
gas sales. This is slightly offset by a decrease related to net
financial settlements of derivative contracts.
The favorable change in
net forward unrealized
mark-to-market
gains (losses)
includes the effect of a $156 million
loss realized in December 2007 related to a legacy derivative
natural gas sales contract. We had previously accounted for this
contract on an accrual basis under the normal purchases and
normal sales exception. We discontinued normal purchase and
normal sales treatment because it was no longer probable that
the contract would not be net settled. In addition, 2008
reflects favorable price movements on our derivative positions
executed to hedge the anticipated withdrawal of natural gas from
storage.
Total segment costs and expenses
increased
$1,439 million, primarily due to a 33 percent increase
in average prices on physical natural gas purchases. These
increases were partially offset by the absence of a
$20 million accrual for litigation contingencies in 2007.
The favorable change in
segment profit (loss)
is
primarily due to the favorable change in
net forward
unrealized
mark-to-market
gains (losses)
, which includes the absence of a 2007 loss
recognized on a legacy derivative natural gas sales contract.
The favorable change in
segment profit (loss)
also
reflects the absence of a $20 million accrual for
litigation contingencies in 2007, partially offset by a decline
in accrual earnings.
Other
Year-Over-Year
Operating Results
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Segment revenues
|
$ | 27 | $ | 24 | $ | 26 | ||||||
|
Segment loss
|
$ | (1 | ) | $ | (3 | ) | $ | (1 | ) | |||
The results of our Other segment are relatively comparable for
all periods presented.
Management’s
Discussion and Analysis of Financial Condition and
Liquidity
Overview
In 2009, we continued to focus upon growth through disciplined
investments in our natural gas businesses. Examples of this
growth included:
| • | Continued investment in Exploration & Production’s development drilling programs, as well as the acquisition of additional producing properties and our initial entry into the Marcellus Shale area. |
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| • | Expansion of Gas Pipeline’s interstate natural gas pipeline system to meet the demand of growth markets. | |
| • | Continued investment in Midstream’s Deepwater Gulf expansion projects and gas processing capacity in the western United States and our initial entry into the Marcellus Shale area. |
These investments were primarily funded through our cash flow
from operations, which totaled nearly $2.6 billion for 2009.
During 2009, global credit markets experienced significant
instability, markets witnessed significant reductions in value,
and energy commodity prices experienced significant and rapid
declines. In consideration of our liquidity under these
conditions, we note the following:
| • | We reduced our levels of capital expenditures. | |
| • | As of December 31, 2009, we have approximately $1.9 billion of cash and cash equivalents and approximately $2.1 billion of available credit capacity under our credit facilities. Our $1.5 billion credit facility does not expire until May 2012. Additionally, Exploration & Production has an unsecured credit agreement that serves to reduce our margin requirements related to our hedging activities. (See additional discussion in the following Available Liquidity section.) | |
| • | We have no significant debt maturities until 2011. | |
| • | Our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support. (See Note 15 of Notes to Consolidated Financial Statements.) |
Strategic
Restructuring
On February 17, 2010, we completed a strategic
restructuring, which involved contributing a substantial
majority of our domestic midstream and gas pipeline businesses,
including our limited- and general-partner interests in Williams
Pipeline Partners L.P. (WMZ), into Williams Partners L.P. (WPZ).
We initially own approximately 84 percent of Williams
Partners L.P., up from 24 percent of current partnership.
Our total ownership percentage will decline to approximately
80 percent assuming the successful completion of the
exchange offer for all of WMZ’s publicly-held units. See
“Strategic Restructuring” in Part I, Item 1
of this Form
10-K
for
further discussion of this potential exchange offer. We intend
to hold our limited-partner and general-partner units for the
long-term. As consideration for the asset contributions, we
received proceeds from WPZ’s debt issuance of approximately
$3.5 billion, less WPZ’s transaction fees and
expenses, as well as 203 million WPZ Class C units,
which are identical to common units, except for a prorated
initial distribution. We also maintained our 2 percent
general-partner interest. WPZ assumed approximately
$2 billion of existing debt associated with the gas
pipeline assets. In connection with the restructuring, we
retired $3 billion of our debt and paid $574 million
in related premiums. These amounts, as well as other transaction
costs, were primarily funded with the cash consideration we
received from WPZ. As a result of our restructuring, we are
better positioned to drive additional growth and pursue
value-adding growth strategies. Our new structure is designed to
lower capital costs, enhance reliable access to capital markets,
and create a greater ability to pursue development projects and
acquisitions. (See Note 19 of Notes to Consolidated
Financial Statements.)
Outlook
For 2010, we expect operating results and cash flows to improve
from 2009 levels due to the impact of expected higher energy
commodity prices.
Lower-than-expected
energy commodity prices would be somewhat mitigated by certain
of our cash flow streams that are substantially insulated from
changes in commodity prices as follows:
| • | Firm demand and capacity reservation transportation revenues under long-term contracts from Gas Pipeline; | |
| • | Hedged natural gas sales at Exploration & Production related to a significant portion of its production; | |
| • | Fee-based revenues from certain gathering and processing services at Midstream. |
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We believe we have, or have access to, the financial resources
and liquidity necessary to meet our requirements for working
capital, capital and investment expenditures, and debt payments
while maintaining a sufficient level of liquidity. In
particular, we note the following assumptions for the coming
year:
| • | We expect to maintain liquidity of at least $1 billion from cash and cash equivalents and unused revolving credit facilities. | |
| • | We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, utilization of our revolving credit facilities, and proceeds from debt issuances and sales of equity securities as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.2 billion and $2.975 billion in 2010. |
We expect capital and investment expenditures to total between
$2.05 billion and $2.775 billion in 2010. Of this
total, approximately 64 percent is considered
nondiscretionary to meet legal, regulatory,
and/or
contractual requirements, to fund committed growth projects or
to preserve the value of existing assets.
Potential risks associated with our planned levels of liquidity
and the planned capital and investment expenditures discussed
above include:
| • | Lower than expected levels of cash flow from operations; | |
| • | Sustained reductions in energy commodity prices from the range of current expectations. |
Liquidity
Based on our forecasted levels of cash flow from operations and
other sources of liquidity, we expect to have sufficient
liquidity to manage our businesses in 2010. Our internal and
external sources of liquidity include cash generated from our
operations, cash and cash equivalents on hand, and our credit
facilities. Additional sources of liquidity, if needed, include
bank financings, proceeds from the issuance of long-term debt
and equity securities, and proceeds from asset sales. These
sources are available to us at the parent level and may be
available to certain of our subsidiaries, including equity and
debt issuances from Williams Partners L.P. Our ability to raise
funds in the capital markets will be impacted by our financial
condition, interest rates, market conditions, and industry
conditions.
Available
Liquidity
|
Credit Facilities
|
Year Ended
|
|||||||
| Expiration | December 31,2009 | |||||||
| (Millions) | ||||||||
|
Cash and cash equivalents(1)
|
$ | 1,867 | ||||||
|
Available capacity under our unsecured revolving and letter of
credit facilities:
|
||||||||
|
$700 million facilities(2)
|
October 2010 | 480 | ||||||
|
$1.5 billion facility(3)
|
May 2012 | 1,430 | ||||||
|
Available capacity under Williams Partners L.P.’s
$200 million senior unsecured credit facility(3)
|
December 2012 | 188 | ||||||
| $ | 3,965 | |||||||
| (1) | Cash and cash equivalents includes $31 million of funds received from third parties as collateral. The obligation for these amounts is reported as accrued liabilities on the Consolidated Balance Sheet. Also included is $648 million of cash and cash equivalents that is being utilized by certain subsidiary and international operations. The remainder of our cash and cash equivalents is primarily held in government-backed instruments. | |
| (2) | These facilities were originated primarily in support of our former power business. |
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| (3) | At December 31, 2009, we are in compliance with the financial covenants associated with these credit agreements. These credit facilities were impacted by our previously discussed restructuring transactions. Williams Partners L.P. established a new $1.75 billion, three-year, senior unsecured revolving credit facility, which replaces its previous $450 million credit facility (which was comprised of a $250 million term loan and a $200 million revolving credit facility). The full amount of the new credit facility is available to Williams Partners L.P. to the extent not otherwise utilized by Transco and Northwest Pipeline, and may be increased by up to an additional $250 million. Transco and Northwest Pipeline are co-borrowers and are each able to borrow up to $400 million under this new facility to the extent not otherwise utilized. Williams Partners L.P. utilized $250 million of the new facility to repay a term loan that was outstanding under its existing facility. As Williams Partners L.P. will be funding Midstream and Gas Pipeline projects, we reduced our approximately $1.5 billion unsecured credit facility that expires May 2012 to approximately $900 million and removed Transco and Northwest Pipeline as borrowers. See the financial covenants of the new facility in Note 19 of Notes to Consolidated Financial Statements. |
Williams Pipeline Partners L.P. filed a shelf registration
statement for the issuance of up to $1.5 billion aggregate
principal amount of debt and limited partnership unit
securities. The registration statement was declared effective on
August 3, 2009.
Williams Partners L.P. filed a shelf registration statement as a
well-known, seasoned issuer in October 2009 that allows it to
issue an unlimited amount of registered debt and limited
partnership unit securities.
At the parent-company level, we filed a shelf registration
statement as a well-known, seasoned issuer in May 2009 that
allows us to issue an unlimited amount of registered debt and
equity securities.
Exploration & Production has an unsecured credit
agreement with certain banks that, so long as certain conditions
are met, serves to reduce our use of cash and other credit
facilities for margin requirements related to our hedging
activities as well as lower transaction fees. The agreement
extends through December 2013. (See Note 11 of Notes to
Consolidated Financial Statements.)
Credit
Ratings
Our ability to borrow money is impacted by our credit ratings
and the credit ratings of WPZ. Following the closing of our 2010
restructuring, our investment-grade ratings were affirmed and
the ratings for WPZ were upgraded to investment grade. The
current ratings are as follows:
| WMB | WPZ | |||
|
Standard and Poor’s(1)
|
||||
|
Corporate Credit Rating
|
BBB− | BBB− | ||
|
Senior Unsecured Debt Rating
|
BB+ | BBB− | ||
|
Outlook
|
Positive(4) | Positive(4) | ||
|
Moody’s Investors Service(2)
|
||||
|
Senior Unsecured Debt Rating
|
Baa3 | Baa3(5) | ||
|
Outlook
|
Stable | Stable(6) | ||
|
Fitch Ratings(3)
|
||||
|
Senior Unsecured Debt Rating
|
BBB− | BBB−(7) | ||
|
Outlook
|
Stable | Stable |
| (1) | 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. | |
| (2) | A rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1,” “2,” and “3” modifiers show the relative standing within a major category. A “1” |
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| indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates the lower end of the category. | ||
| (3) | A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category. | |
| (4) | On January 12, 2010, Standard & Poor’s revised to positive from stable. | |
| (5) | On February 17, 2010, Moody’s Investor Service revised to Baa3 from Ba2. | |
| (6) | On February 17, 2010, Moody’s Investor Service revised to stable from negative. | |
| (7) | On February 2, 2010, Fitch Ratings revised to BBB- from BB. |
Credit rating agencies perform independent analyses when
assigning credit ratings. No assurance can be given that the
credit rating agencies will continue to assign us investment
grade ratings even if we meet or exceed their current criteria
for investment grade ratios. A downgrade of our credit rating
might increase our future cost of borrowing and would require us
to post additional collateral with third parties, negatively
impacting our available liquidity. As of December 31, 2009,
we estimate that a downgrade to a rating below investment grade
would require us to post up to $585 million in additional
collateral with third parties.
Sources
(Uses) of Cash
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Net cash provided (used) by:
|
||||||||||||
|
Operating activities
|
$ | 2,572 | $ | 3,355 | $ | 2,237 | ||||||
|
Financing activities
|
166 | (432 | ) | (511 | ) | |||||||
|
Investing activities
|
(2,310 | ) | (3,183 | ) | (2,296 | ) | ||||||
|
Increase (decrease) in cash and cash equivalents
|
$ | 428 | $ | (260 | ) | $ | (570 | ) | ||||
Operating
activities
Our
net cash provided by operating activities
in 2009
decreased from 2008 primarily due to the decrease in our
operating results.
Significant transactions in 2008 include:
| • | We received $140 million of cash related to a favorable resolution of matters involving pipeline transportation rates associated with our former Alaska operations. (See Note 2 of Notes to Consolidated Financial Statements.) | |
| • | Transco paid $144 million of required refunds related to a general rate case with the FERC. (See Results of Operations — Segments, Gas Pipeline.) |
Our
net cash provided by operating activities
in 2008
increased from 2007 primarily due to the increase in our
earnings.
Financing
activities
Significant transactions include:
2009
| • | We received $595 million net cash from the issuance of $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to fund general corporate expenses and capital expenditures. (See Note 11 of Notes to Consolidated Financial Statements.) | |
| • | We paid $256 million of quarterly dividends on common stock for the year ended December 31, 2009. |
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2008
| • | We received $362 million from the completion of the Williams Pipeline Partners L.P. initial public offering. | |
| • | We paid $474 million for the repurchase of our common stock. (See Note 12 of Notes to Consolidated Financial Statements.) | |
| • | Gas Pipeline received $75 million net proceeds from debt transactions. | |
| • | We paid $250 million of quarterly dividends on common stock for the year ended December 31, 2008. |
2007
| • | We paid $526 million for the repurchase of our common stock. (See Note 12 of Notes to Consolidated Financial Statements.) | |
| • | We repurchased $22 million of our 8.125 percent senior unsecured notes due March 2012 and $213 million of our 7.125 percent senior unsecured notes due September 2011. Early retirement premiums paid were approximately $19 million. | |
| • | Northwest Pipeline issued $185 million of 5.95 percent senior unsecured notes due 2017 and retired $175 million of 8.125 percent senior unsecured notes due 2010. Early retirement premiums paid were approximately $7 million. | |
| • | 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 term loan borrowings under their $450 million five-year senior unsecured credit facility and issuing approximately $157 million of common units to us. | |
| • | We paid $233 million of quarterly dividends on common stock for the year ended December 31, 2007. |
Investing
activities
2009
| • | Capital expenditures totaled $2.4 billion, more than half of which related to Exploration & Production. Included was a $253 million payment by Exploration & Production for the purchase of additional properties in the Piceance basin. (See Results of Operations — Segments, Exploration & Production.) | |
| • | We received $148 million as a distribution from Gulfstream following its debt offering. | |
| • | We contributed $142 million to our investments, including $106 million related to our Laurel Mountain equity investment and $20 million related to our Gulfstream equity investment. |
2008
| • | Capital expenditures totaled $3.4 billion and was primarily related to Exploration & Production’s drilling activity. This total includes Exploration & Production’s acquisitions of certain interests in the Piceance and Fort Worth basins. | |
| • | We received $148 million of cash from Exploration & Production’s sale of a contractual right to a production payment. | |
| • | We contributed $111 million to our investments, including $90 million related to our Gulfstream equity investment. |
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2007
| • | Capital expenditures totaled $2.9 billion and was primarily related to Exploration & Production’s drilling activity, mostly in the Piceance basin. | |
| • | We received $496 million of gross proceeds from the sale of substantially all of our power business. | |
| • | We purchased $304 million and received $353 million from the sale of auction rate securities. These were utilized as a component of our overall cash management program. |
Off-Balance
Sheet Financing Arrangements and Guarantees of Debt or Other
Commitments
We have various other guarantees and commitments which are
disclosed in Notes 9, 10, 11, 15, and 16 of Notes to
Consolidated Financial Statements. We do not believe these
guarantees or the possible fulfillment of them will prevent us
from meeting our liquidity needs.
Contractual
Obligations
The table below summarizes the maturity dates of our contractual
obligations, including obligations related to discontinued
operations.
|
2011-
|
2013-
|
|||||||||||||||||||
| 2010 | 2012 | 2014 | Thereafter | Total | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
|
Long-term debt, including current portion:
|
||||||||||||||||||||
|
Principal(1)
|
$ | 15 | $ | 2,139 | $ | — | $ | 6,155 | $ | 8,309 | ||||||||||
|
Interest
|
619 | 1,113 | 938 | 4,273 | 6,943 | |||||||||||||||
|
Capital leases
|
2 | — | 1 | — | 3 | |||||||||||||||
|
Operating leases
|
70 | 64 | 45 | 138 | 317 | |||||||||||||||
|
Purchase obligations(2)
|
1,147 | 1,728 | 1,474 | 3,621 | 7,970 | |||||||||||||||
|
Other long-term liabilities, including current portion:
|
||||||||||||||||||||
|
Physical and financial derivatives(3)(4 )
|
418 | 287 | 125 | 62 | 892 | |||||||||||||||
|
Other(5)(6)
|
— | — | — | — | — | |||||||||||||||
|
Total
|
$ | 2,271 | $ | 5,331 | $ | 2,583 | $ | 14,249 | $ | 24,434 | ||||||||||
| (1) | In February 2010, we completed our strategic restructuring and retired $3 billion of aggregate principal corporate debt and issued $3.5 billion aggregate principal amount of senior unsecured notes of WPZ. Additionally, WPZ established a new $1.75 billion three-year unsecured revolving credit facility which replaces its previous $450 million credit facility. WPZ utilized $250 million of the new facility to repay a term loan that was outstanding under the previous facility. Williams has reduced its existing $1.5 billion unsecured |
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| revolving credit facility, which matures in May 2012, to $900 million. The below table shows the impact by period of this transaction: |
|
2011-
|
2013-
|
|||||||||||||||||||
| 2010 | 2012 | 2014 | Thereafter | Total | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
|
Long-term debt, including current portion:
|
||||||||||||||||||||
|
Retirement of $3 billion of aggregate principle corporate
debt
|
$ | — | $ | (1,030 | ) | $ | — | $ | (1,970 | ) | $ | (3,000 | ) | |||||||
|
Issuance of the $3.5 billion WPZ senior notes
|
— | — | — | 3,500 | 3,500 | |||||||||||||||
|
Retirement of the $250 million term loan under WPZ’s
$450 million credit facility
|
— | (250 | ) | — | — | (250 | ) | |||||||||||||
|
Issuance of $250 million term loan under WPZ’s new
$1.75 billion credit facility
|
— | — | 250 | — | 250 | |||||||||||||||
|
Total
|
$ | — | $ | (1,280 | ) | $ | 250 | $ | 1,530 | $ | 500 | |||||||||
| (2) | Includes $3.2 billion of natural gas purchase obligations at market prices at our Exploration & Production segment. The purchased natural gas can be sold at market prices. | |
| (3) | The obligations for physical and financial derivatives are based on market information as of December 31, 2009, and assumes contracts remain outstanding for their full contractual duration. Because market information changes daily and has the potential to be volatile, significant changes to the values in this category may occur. | |
| (4) | Expected offsetting cash inflows of $3.9 billion at December 31, 2009, resulting from product sales or net positive settlements, are not reflected in these amounts. In addition, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts. | |
| (5) | Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $77 million in 2009 and $75 million in 2008. In 2010, we expect to contribute approximately $77 million to these plans (see Note 7 of Notes to Consolidated Financial Statements). During 2009, we contributed $60 million to our tax-qualified pension plans which was greater than the minimum funding requirements. We expect to contribute approximately $60 million to these pension plans again in 2010, which is expected to be greater than the minimum funding requirements. Estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations. | |
| (6) | As of December 31, 2009, we have accrued approximately $72 million for unrecognized tax benefits. We cannot make reasonably reliable estimates of the timing of the future payments of these liabilities. Therefore, these liabilities have been excluded from the table above. See Note 5 of Notes to Consolidated Financial Statements for information regarding our contingent tax liability reserves. |
Effects
of Inflation
Our operations have benefited from relatively low inflation
rates. Approximately 37 percent of our gross property,
plant and equipment is at Gas Pipeline. Gas Pipeline is subject
to regulation, which limits recovery to historical cost. While
amounts in excess of historical cost are not recoverable under
current FERC practices, we anticipate being allowed to recover
and earn a return based on increased actual cost incurred to
replace existing assets. Cost-based regulation, along with
competition and other market factors, may limit our ability to
recover such increased costs. For the other operating units,
operating costs are influenced to a greater extent by both
competition for specialized services and specific price changes
in oil and natural gas and related commodities than by changes
in general inflation. Crude, natural gas, and natural gas
liquids prices are particularly sensitive to the Organization of
the Petroleum Exporting Countries (OPEC) production levels
and/or
the
market perceptions concerning the supply and demand balance in
the near future, as well as general economic conditions.
However, our exposure to these price changes is reduced through
the use of hedging instruments and the fee-based nature of
certain of our services.
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Environmental
We are a participant in certain environmental activities in
various stages including assessment studies, cleanup operations
and/or
remedial processes at certain sites, some of which we currently
do not own (see Note 16 of Notes to Consolidated Financial
Statements). We are monitoring these sites in a coordinated
effort with other potentially responsible parties, the
U.S. Environmental Protection Agency (EPA), or other
governmental authorities. We are jointly and severally liable
along with unrelated third parties in some of these activities
and solely responsible in others. Current estimates of the most
likely costs of such activities are approximately
$42 million, all of which are recorded as liabilities on
our balance sheet at December 31, 2009. We will seek
recovery of approximately $12 million of these accrued
costs through future natural gas transmission rates. The
remainder of these costs will be funded from operations. During
2009, we paid approximately $8 million for cleanup
and/or
remediation and monitoring activities. We expect to pay
approximately $10 million in 2010 for these activities.
Estimates of the most likely costs of cleanup are generally
based on completed assessment studies, preliminary results of
studies or our experience with other similar cleanup operations.
At December 31, 2009, certain assessment studies were still
in process for which the ultimate outcome may yield
significantly different estimates of most likely costs.
Therefore, the actual costs incurred will depend on the final
amount, type, and extent of contamination discovered at these
sites, the final cleanup standards mandated by the EPA or other
governmental authorities, and other factors.
We are subject to the federal Clean Air Act and to the federal
Clean Air Act Amendments of 1990, which require the EPA to issue
new regulations. We are also subject to regulation at the state
and local level. In September 1998, the EPA promulgated rules
designed to mitigate the migration of ground-level ozone in
certain states. Revisions to those rules were proposed in
January 2010 and may result in additional controls. In March
2004 and June 2004, the EPA promulgated additional regulation
regarding hazardous air pollutants, which may result in
additional controls. Capital expenditures necessary to install
emission control devices on our Transco gas pipeline system to
comply with rules were approximately $400 thousand in 2009 and
are estimated to be between $5 million and $10 million
through 2013. The actual costs incurred will depend on the final
implementation plans developed by each state to comply with
these regulations. We consider these costs on our Transco system
associated with compliance with these environmental laws and
regulations to be prudent costs incurred in the ordinary course
of business and, therefore, recoverable through its rates.
We have established systems and procedures to meet our reporting
obligations under the Mandatory Reporting Rule related to
greenhouse gas emissions issued by the EPA in late 2009. Also,
certain states in which we have operations have established
reporting obligations. We have not incurred significant capital
investment to meet the obligations imposed by these new rules.
The EPA is developing additional regulations that will expand
the scope of the Mandatory Reporting Rule, with particular
emphasis on natural gas operations. We are participating
directly and through trade associations in developmental aspects
of that prospective rulemaking. It is likely that additional
rules will be issued in 2010 which may expand our reporting
obligations as early as 2011. As those rules are still being
developed, at this time we are unable to estimate any capital
investment that may be required to comply.
78
Table of Contents
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Interest
Rate Risk
Our current interest rate risk exposure is related primarily to
our debt portfolio. The majority of our debt portfolio is
comprised of fixed rate debt in order to mitigate the impact of
fluctuations in interest rates. The maturity of our long-term
debt portfolio is partially influenced by the expected lives of
our operating assets. In February 2010, we completed a strategic
restructuring that involved retiring $3 billion of our debt
and issuing $3.5 billion aggregate principal amount of
senior unsecured notes of WPZ. (See Note 19 of Notes to
Consolidated Financial Statements.)
The tables below provide information by maturity date about our
interest rate risk-sensitive instruments included in continuing
operations as of December 31, 2009 and 2008. Long-term debt
in the tables represents principal cash flows, net of (discount)
premium, and weighted-average interest rates by expected
maturity dates. The fair value of our publicly traded long-term
debt is valued using indicative year-end traded bond market
prices. Private debt is valued based on market rates and the
prices of similar securities with similar terms and credit
ratings.
|
Fair Value
|
||||||||||||||||||||||||||||||||
|
December 31,
|
||||||||||||||||||||||||||||||||
| 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter(1) | Total | 2009 | |||||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||||||
|
Long-term debt, including current portion(2):
|
||||||||||||||||||||||||||||||||
|
Fixed rate
|
$ | 15 | $ | 936 | $ | 953 | $ | — | $ | — | $ | 6,119 | $ | 8,023 | $ | 8,905 | ||||||||||||||||
|
Interest rate
|
7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 8.0 | % | ||||||||||||||||||||
|
Variable rate
|
$ | — | $ | — | $ | 250 | $ | — | $ | — | $ | — | $ | 250 | $ | 237 | ||||||||||||||||
|
Interest rate(3)
|
||||||||||||||||||||||||||||||||
|
Fair Value
|
||||||||||||||||||||||||||||||||
|
December 31,
|
||||||||||||||||||||||||||||||||
| 2009 | 2010 | 2011 | 2012 | 2013 | Thereafter(1) | Total | 2008 | |||||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||||||
|
Long-term debt, including current portion(2):
|
||||||||||||||||||||||||||||||||
|
Fixed rate
|
$ | 15 | $ | — | $ | 927 | $ | 953 | $ | — | $ | 5,551 | $ | 7,446 | $ | 5,907 | ||||||||||||||||
|
Interest rate
|
7.6 | % | 7.6 | % | 7.6 | % | 7.6 | % | 7.5 | % | 7.9 | % | ||||||||||||||||||||
|
Variable rate
|
$ | — | $ | — | $ | — | $ | 250 | $ | — | $ | — | $ | 250 | $ | 233 | ||||||||||||||||
|
Interest rate(3)
|
||||||||||||||||||||||||||||||||
| (1) | Includes unamortized discount and premium. | |
| (2) | Excludes capital leases. | |
| (3) | The interest rate at December 31, 2009 and 2008 is LIBOR plus 1 percent and 0.75 percent, respectively. |
Commodity
Price Risk
We are exposed to the impact of fluctuations in the market price
of natural gas and NGLs, as well as other market factors, such
as market volatility and commodity price correlations. We are
exposed to these risks in connection with our owned
energy-related assets, our long-term energy-related contracts
and our proprietary trading activities. We manage the risks
associated with these market fluctuations using various
derivatives and nonderivative energy-related contracts. The fair
value of derivative contracts is subject to many factors,
including changes in energy-commodity market prices, the
liquidity and volatility of the markets in which the contracts
are transacted, and changes in interest rates. We measure the
risk in our portfolios using a
value-at-risk
methodology to estimate the potential
one-day
loss
from adverse changes in the fair value of the portfolios.
Value at risk requires a number of key assumptions and is not
necessarily representative of actual losses in fair value that
could be incurred from the portfolios. Our
value-at-risk
model uses a Monte Carlo method to simulate hypothetical
movements in future market prices and assumes that, as a result
of changes in commodity prices, there
79
Table of Contents
is a 95 percent probability that the
one-day
loss
in fair value of the portfolios will not exceed the value at
risk. The simulation method uses historical correlations and
market forward prices and volatilities. In applying the
value-at-risk
methodology, we do not consider that the simulated hypothetical
movements affect the positions or would cause any potential
liquidity issues, nor do we consider that changing the portfolio
in response to market conditions could affect market prices and
could take longer than a
one-day
holding period to execute. While a
one-day
holding period has historically been the industry standard, a
longer holding period could more accurately represent the true
market risk given market liquidity and our own credit and
liquidity constraints.
We segregate our derivative contracts into trading and
nontrading contracts, as defined in the following paragraphs. We
calculate value at risk separately for these two categories.
Contracts designated as normal purchases or sales and
nonderivative energy contracts have been excluded from our
estimation of value at risk.
Trading
Our trading portfolio consists of derivative contracts entered
into for purposes other than economically hedging our commodity
price-risk exposure. The fair value of our trading derivatives
is a net liability of $11 million at December 31,
2009. Our value at risk for contracts held for trading purposes
was less than $1 million at December 31, 2009 and 2008.
Nontrading
Our nontrading portfolio consists of derivative contracts that
hedge or could potentially hedge the price risk exposure from
the following activities:
|
Segment
|
Commodity Price Risk Exposure
|
|
|
Exploration & Production
|
• Natural gas sales
|
|
|
Midstream
|
• Natural gas purchases
|
|
|
• NGL purchases and sales
|
||
|
Gas Marketing Services
|
• Natural gas purchases and sales
|
The fair value of our nontrading derivatives is a net asset of
$99 million at December 31, 2009.
The value at risk for derivative contracts held for nontrading
purposes was $34 million at December 31, 2009, and
$33 million at December 31, 2008. During the year
ended December 31, 2009, our value at risk for these
contracts ranged from a high of $37 million to a low of
$27 million.
Certain of the derivative contracts held for nontrading purposes
are accounted for as cash flow hedges. Of the total fair value
of nontrading derivatives, cash flow hedges have a net asset
value of $178 million as of December 31, 2009. Though
these contracts are included in our
value-at-risk
calculation, any change in the fair value of the effective
portion of these hedge contracts would generally not be
reflected in earnings until the associated hedged item affects
earnings.
Trading
Policy
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.
Foreign
Currency Risk
We have international investments that could affect our
financial results if the investments incur a permanent decline
in value as a result of changes in foreign currency exchange
rates
and/or
the economic conditions in foreign countries.
International investments accounted for under the cost method
totaled $2 million at December 31, 2009, and
$17 million at December 31, 2008. These investments
are primarily in nonpublicly traded companies for which it is
80
Table of Contents
not practicable to estimate fair value. We believe that we can
realize the carrying value of these investments considering the
status of the operations of the companies underlying these
investments.
Net assets of consolidated foreign operations, whose functional
currency is the local currency, are located primarily in Canada
and approximate 6 percent and 5 percent of our net
assets at December 31, 2009 and 2008, respectively. These
foreign operations do not have significant transactions or
financial instruments denominated in currencies other than their
functional currency. However, these investments do have the
potential to impact our financial position, due to fluctuations
in these local currencies arising from the process of
translating the local functional currency into the
U.S. dollar. As an example, a 20 percent change in the
respective functional currencies against the U.S. dollar
would have changed
stockholders’ equity
by
approximately $98 million at December 31, 2009.
81
Table of Contents
| Item 8. | Financial Statements and Supplementary Data |
MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
FINANCIAL REPORTING
Management is responsible for establishing and maintaining
adequate internal control over financial reporting (as defined
in
Rules 13a-15(f)
and
15d-15(f)
under the Securities Exchange Act of 1934). Our internal
controls over financial reporting are designed to provide
reasonable assurance to our management and board of directors
regarding the preparation and fair presentation of financial
statements in accordance with accounting principles generally
accepted in the United States. Our internal control over
financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the
transactions and dispositions of our assets; (ii) provide
reasonable assurance that transactions are recorded as to permit
preparation of financial statements in accordance with generally
accepted accounting principles, and that our receipts and
expenditures are being made only in accordance with
authorization of our management and board of directors; and
(iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use or disposition
of our assets that could have a material effect on our financial
statements.
All internal control systems, no matter how well designed, have
inherent limitations including the possibility of human error
and the circumvention or overriding of controls. Therefore, even
those systems determined to be effective can provide only
reasonable assurance with respect to financial statement
preparation and presentation.
Under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief
Financial Officer, we assessed the effectiveness of our internal
control over financial reporting as of December 31, 2009,
based on the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in
Internal
Control — Integrated Framework.
Based on our
assessment, we concluded that, as of December 31, 2009, our
internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public
accounting firm, has audited our internal control over financial
reporting, as stated in their report which is included in this
Annual Report on
Form 10-K.
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Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited The Williams Companies, Inc.’s internal
control over financial reporting as of December 31, 2009,
based on criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria).
The Williams Companies, Inc.’s management is responsible
for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of
internal control over financial reporting included in the
accompanying Management’s Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion
on the Company’s internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, The Williams Companies, Inc. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2009, based on the COSO
criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheet of The Williams Companies, Inc. as of
December 31, 2009 and 2008, and the related consolidated
statements of income, changes in equity, and cash flows for each
of the three years in the period ended December 31, 2009 of
The Williams Companies, Inc. and our report dated
February 25, 2010 expressed an unqualified opinion thereon.
/s/ Ernst &
Young LLP
Tulsa, Oklahoma
February 25, 2010
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Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited the accompanying consolidated balance sheet of
The Williams Companies, Inc. as of December 31, 2009 and
2008, and the related consolidated statements of income, changes
in equity, and cash flows for each of the three years in the
period ended December 31, 2009. Our audits also included
the financial statement schedule listed in the index at
Item 15(a). These financial statements and schedule are the
responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial
statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of The Williams Companies, Inc. at
December 31, 2009 and 2008, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2009, in conformity with
U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken
as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Note 9 to the consolidated financial
statements, the Company has changed its reserve estimates and
related disclosures as a result of adopting new oil and gas
reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), The
Williams Companies, Inc.’s internal control over financial
reporting as of December 31, 2009, based on criteria
established in Internal Control — Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 25, 2010
expressed an unqualified opinion thereon.
/s/ Ernst &
Young LLP
Tulsa, Oklahoma
February 25, 2010
84
Table of Contents
THE
WILLIAMS COMPANIES, INC.
CONSOLIDATED
STATEMENT OF INCOME
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions, except per-share amounts) | ||||||||||||
|
Revenues:
|
||||||||||||
|
Exploration & Production
|
$ | 2,219 | $ | 3,121 | $ | 2,021 | ||||||
|
Gas Pipeline
|
1,591 | 1,634 | 1,610 | |||||||||
|
Midstream Gas & Liquids
|
3,588 | 5,180 | 4,933 | |||||||||
|
Gas Marketing Services
|
3,052 | 6,412 | 4,633 | |||||||||
|
Other
|
27 | 24 | 26 | |||||||||
|
Intercompany eliminations
|
(2,222 | ) | (4,481 | ) | (2,984 | ) | ||||||
|
Total revenues
|
8,255 | 11,890 | 10,239 | |||||||||
|
Segment costs and expenses:
|
||||||||||||
|
Costs and operating expenses
|
6,081 | 8,776 | 7,832 | |||||||||
|
Selling, general and administrative expenses
|
512 | 504 | 461 | |||||||||
|
Other (income) expense — net
|
17 | (72 | ) | (2 | ) | |||||||
|
Total segment costs and expenses
|
6,610 | 9,208 | 8,291 | |||||||||
|
General corporate expenses
|
164 | 149 | 161 | |||||||||
|
Operating income (loss):
|
||||||||||||
|
Exploration & Production
|
400 | 1,240 | 731 | |||||||||
|
Gas Pipeline
|
601 | 630 | 622 | |||||||||
|
Midstream Gas & Liquids
|
663 | 812 | 933 | |||||||||
|
Gas Marketing Services
|
(18 | ) | 3 | (337 | ) | |||||||
|
Other
|
(1 | ) | (3 | ) | (1 | ) | ||||||
|
General corporate expenses
|
(164 | ) | (149 | ) | (161 | ) | ||||||
|
Total operating income
|
1,481 | 2,533 | 1,787 | |||||||||
|
Interest accrued
|
(661 | ) | (636 | ) | (664 | ) | ||||||
|
Interest capitalized
|
76 | 59 | 32 | |||||||||
|
Investing income
|
46 | 189 | 252 | |||||||||
|
Early debt retirement costs
|
(1 | ) | (1 | ) | (19 | ) | ||||||
|
Other income — net
|
2 | — | 12 | |||||||||
|
Income from continuing operations before income taxes
|
943 | 2,144 | 1,400 | |||||||||
|
Provision for income taxes
|
359 | 677 | 490 | |||||||||
|
Income from continuing operations
|
584 | 1,467 | 910 | |||||||||
|
Income (loss) from discontinued operations
|
(223 | ) | 125 | 170 | ||||||||
|
Net income
|
361 | 1,592 | 1,080 | |||||||||
|
Less: Net income attributable to noncontrolling interests
|
76 | 174 | 90 | |||||||||
|
Net income attributable to The Williams Companies, Inc.
|
$ | 285 | $ | 1,418 | $ | 990 | ||||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||
|
Income from continuing operations
|
$ | 438 | $ | 1,306 | $ | 829 | ||||||
|
Income (loss) from discontinued operations
|
(153 | ) | 112 | 161 | ||||||||
|
Net income
|
$ | 285 | $ | 1,418 | $ | 990 | ||||||
|
Basic earnings (loss) per common share:
|
||||||||||||
|
Income from continuing operations
|
$ | .75 | $ | 2.25 | $ | 1.39 | ||||||
|
Income (loss) from discontinued operations
|
(.26 | ) | .19 | .27 | ||||||||
|
Net income
|
$ | .49 | $ | 2.44 | $ | 1.66 | ||||||
|
Weighted-average shares (thousands)
|
581,674 | 581,342 | 596,174 | |||||||||
|
Diluted earnings (loss) per common share:
|
||||||||||||
|
Income from continuing operations
|
$ | .75 | $ | 2.21 | $ | 1.37 | ||||||
|
Income (loss) from discontinued operations
|
(.26 | ) | .19 | .26 | ||||||||
|
Net income
|
$ | .49 | $ | 2.40 | $ | 1.63 | ||||||
|
Weighted-average shares (thousands)
|
589,385 | 592,719 | 609,866 | |||||||||
See accompanying notes.
85
Table of Contents
THE
WILLIAMS COMPANIES, INC.
CONSOLIDATED
BALANCE SHEET
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions, except per-share amounts) | ||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 1,867 | $ | 1,438 | ||||
|
Accounts and notes receivable (net of allowance of $22 at
December 31, 2009 and $29 at December 31, 2008)
|
829 | 884 | ||||||
|
Inventories
|
222 | 260 | ||||||
|
Derivative assets
|
650 | 1,464 | ||||||
|
Assets of discontinued operations
|
1 | 142 | ||||||
|
Other current assets and deferred charges
|
224 | 223 | ||||||
|
Total current assets
|
3,793 | 4,411 | ||||||
|
Investments
|
886 | 971 | ||||||
|
Property, plant and equipment — net
|
18,644 | 17,741 | ||||||
|
Derivative assets
|
444 | 986 | ||||||
|
Goodwill
|
1,011 | 1,011 | ||||||
|
Assets of discontinued operations
|
— | 387 | ||||||
|
Other assets and deferred charges
|
502 | 499 | ||||||
|
Total assets
|
$ | 25,280 | $ | 26,006 | ||||
| LIABILITIES AND EQUITY | ||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable
|
$ | 934 | $ | 1,052 | ||||
|
Accrued liabilities
|
948 | 1,139 | ||||||
|
Derivative liabilities
|
578 | 1,093 | ||||||
|
Liabilities of discontinued operations
|
— | 217 | ||||||
|
Long-term debt due within one year
|
17 | 18 | ||||||
|
Total current liabilities
|
2,477 | 3,519 | ||||||
|
Long-term debt
|
8,259 | 7,683 | ||||||
|
Deferred income taxes
|
3,656 | 3,315 | ||||||
|
Derivative liabilities
|
428 | 875 | ||||||
|
Liabilities of discontinued operations
|
— | 82 | ||||||
|
Other liabilities and deferred income
|
1,441 | 1,478 | ||||||
|
Contingent liabilities and commitments (Note 16)
|
||||||||
|
Equity:
|
||||||||
|
Stockholders’ equity:
|
||||||||
|
Common stock (960 million shares authorized at $1 par
value; 618 million shares issued at December 31, 2009,
and 613 million shares issued at December 31, 2008)
|
618 | 613 | ||||||
|
Capital in excess of par value
|
8,135 | 8,074 | ||||||
|
Retained earnings
|
903 | 874 | ||||||
|
Accumulated other comprehensive loss
|
(168 | ) | (80 | ) | ||||
|
Treasury stock, at cost (35 million shares of common stock)
|
(1,041 | ) | (1,041 | ) | ||||
|
Total stockholders’ equity
|
8,447 | 8,440 | ||||||
|
Noncontrolling interests in consolidated subsidiaries
|
572 | 614 | ||||||
|
Total equity
|
9,019 | 9,054 | ||||||
|
Total liabilities and equity
|
$ | 25,280 | $ | 26,006 | ||||
See accompanying notes.
86
Table of Contents
THE
WILLIAMS COMPANIES, INC.
CONSOLIDATED
STATEMENT OF CHANGES IN EQUITY
| The Williams Companies, Inc., Stockholders | ||||||||||||||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||||||||||||||
|
Capital in
|
Retained
|
Other
|
Total
|
|||||||||||||||||||||||||||||
|
Common
|
Excess of
|
Earnings
|
Comprehensive
|
Treasury
|
Stockholders’
|
Noncontrolling
|
||||||||||||||||||||||||||
| Stock | Par Value | (Deficit) | Loss | Stock | Equity | Interests | Total | |||||||||||||||||||||||||
| (Millions, except per-share amounts) | ||||||||||||||||||||||||||||||||
|
Balance, December 31, 2006
|
$ | 603 | $ | 6,605 | $ | (1,034 | ) | $ | (60 | ) | $ | (41 | ) | $ | 6,073 | $ | 1,081 | $ | 7,154 | |||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | 990 | — | — | 990 | 90 | 1,080 | ||||||||||||||||||||||||
|
Other comprehensive loss:
|
||||||||||||||||||||||||||||||||
|
Net change in cash flow hedges (Note 17)
|
— | — | — | (177 | ) | — | (177 | ) | (2 | ) | (179 | ) | ||||||||||||||||||||
|
Foreign currency translation adjustments
|
— | — | — | 53 | — | 53 | — | 53 | ||||||||||||||||||||||||
|
Pension benefits:
|
||||||||||||||||||||||||||||||||
|
Net actuarial gain
|
— | — | — | 53 | — | 53 | — | 53 | ||||||||||||||||||||||||
|
Other postretirement benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||
|
Net actuarial gain
|
— | — | — | 9 | — | 9 | — | 9 | ||||||||||||||||||||||||
|
Total other comprehensive loss
|
(61 | ) | (2 | ) | (63 | ) | ||||||||||||||||||||||||||
|
Total comprehensive income
|
929 | 88 | 1,017 | |||||||||||||||||||||||||||||
|
Cash dividends — Common stock ($.39 per share)
|
— | — | (233 | ) | — | — | (233 | ) | — | (233 | ) | |||||||||||||||||||||
|
Sale of limited partner units of consolidated partnership
|
— | — | — | — | — | — | 333 | 333 | ||||||||||||||||||||||||
|
Dividends and distributions to noncontrolling interests
|
— | — | — | — | — | — | (75 | ) | (75 | ) | ||||||||||||||||||||||
|
Initial adjustment for uncertain tax positions
|
— | — | (17 | ) | — | — | (17 | ) | — | (17 | ) | |||||||||||||||||||||
|
Purchase of treasury stock (Note 12)
|
— | — | — | — | (526 | ) | (526 | ) | — | (526 | ) | |||||||||||||||||||||
|
Stock-based compensation, including tax benefit
|
5 | 143 | — | — | — | 148 | — | 148 | ||||||||||||||||||||||||
|
Other
|
— | — | 1 | — | — | 1 | 3 | 4 | ||||||||||||||||||||||||
|
Balance, December 31, 2007
|
608 | 6,748 | (293 | ) | (121 | ) | (567 | ) | 6,375 | 1,430 | 7,805 | |||||||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | 1,418 | — | — | 1,418 | 174 | 1,592 | ||||||||||||||||||||||||
|
Other comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net change in cash flow hedges (Note 17)
|
— | — | — | 453 | — | 453 | 2 | 455 | ||||||||||||||||||||||||
|
Foreign currency translation adjustments
|
— | — | — | (76 | ) | — | (76 | ) | — | (76 | ) | |||||||||||||||||||||
|
Pension benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||
|
Net actuarial loss
|
— | — | — | (337 | ) | — | (337 | ) | (7 | ) | (344 | ) | ||||||||||||||||||||
|
Other postretirement benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 9 | — | 9 | — | 9 | ||||||||||||||||||||||||
|
Net actuarial loss
|
— | — | — | (9 | ) | — | (9 | ) | — | (9 | ) | |||||||||||||||||||||
|
Total other comprehensive income
|
41 | (5 | ) | 36 | ||||||||||||||||||||||||||||
|
Total comprehensive income
|
1,459 | 169 | 1,628 | |||||||||||||||||||||||||||||
|
Cash dividends — Common stock ($.43 per share)
|
— | — | (250 | ) | — | — | (250 | ) | — | (250 | ) | |||||||||||||||||||||
|
Sale of limited partner units of consolidated partnership
|
— | — | — | — | — | — | 362 | 362 | ||||||||||||||||||||||||
|
Dividends and distributions to noncontrolling interests
|
— | — | — | — | — | — | (122 | ) | (122 | ) | ||||||||||||||||||||||
|
Issuance of common stock from 5.5% debentures conversion
(Note 12)
|
2 | 25 | — | — | — | 27 | — | 27 | ||||||||||||||||||||||||
|
Conversion of Williams Partners L.P. subordinated units to
common units (Note 12)
|
— | 1,225 | — | — | — | 1,225 | (1,225 | ) | — | |||||||||||||||||||||||
|
Purchase of treasury stock (Note 12)
|
— | — | — | — | (474 | ) | (474 | ) | — | (474 | ) | |||||||||||||||||||||
|
Stock-based compensation, including tax benefit
|
3 | 67 | — | — | — | 70 | — | 70 | ||||||||||||||||||||||||
|
Other
|
— | 9 | (1 | ) | — | — | 8 | — | 8 | |||||||||||||||||||||||
|
Balance, December 31, 2008
|
613 | 8,074 | 874 | (80 | ) | (1,041 | ) | 8,440 | 614 | 9,054 | ||||||||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | 285 | — | — | 285 | 76 | 361 | ||||||||||||||||||||||||
|
Other comprehensive loss:
|
||||||||||||||||||||||||||||||||
|
Net change in cash flow hedges (Note 17)
|
— | — | — | (221 | ) | — | (221 | ) | — | (221 | ) | |||||||||||||||||||||
|
Foreign currency translation adjustments
|
— | — | — | 83 | — | 83 | — | 83 | ||||||||||||||||||||||||
|
Pension benefits:
|
||||||||||||||||||||||||||||||||
|
Net actuarial gain
|
— | — | — | 46 | — | 46 | 7 | 53 | ||||||||||||||||||||||||
|
Other postretirement benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 4 | — | 4 | — | 4 | ||||||||||||||||||||||||
|
Total other comprehensive loss
|
(88 | ) | 7 | (81 | ) | |||||||||||||||||||||||||||
|
Total comprehensive income
|
197 | 83 | 280 | |||||||||||||||||||||||||||||
|
Cash dividends — Common stock ($.44 per share)
|
— | — | (256 | ) | — | — | (256 | ) | — | (256 | ) | |||||||||||||||||||||
|
Dividends and distributions to noncontrolling interests
|
— | — | — | — | — | — | (129 | ) | (129 | ) | ||||||||||||||||||||||
|
Issuance of common stock from 5.5% debentures conversion
(Note 12)
|
3 | 25 | — | — | — | 28 | — | 28 | ||||||||||||||||||||||||
|
Stock-based compensation, including tax benefit
|
2 | 36 | — | — | — | 38 | — | 38 | ||||||||||||||||||||||||
|
Other
|
— | — | — | — | — | — | 4 | 4 | ||||||||||||||||||||||||
|
Balance, December 31, 2009
|
$ | 618 | $ | 8,135 | $ | 903 | $ | (168 | ) | $ | (1,041 | ) | $ | 8,447 | $ | 572 | $ | 9,019 | ||||||||||||||
See accompanying notes.
87
Table of Contents
THE
WILLIAMS COMPANIES, INC.
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
OPERATING ACTIVITIES:
|
||||||||||||
|
Net income
|
$ | 361 | $ | 1,592 | $ | 1,080 | ||||||
|
Adjustments to reconcile to net cash provided by operating
activities:
|
||||||||||||
|
Reclassification of deferred net hedge gains related to sale of
power business
|
— | — | (429 | ) | ||||||||
|
Depreciation, depletion and amortization
|
1,469 | 1,310 | 1,082 | |||||||||
|
Provision for deferred income taxes
|
249 | 611 | 370 | |||||||||
|
Provision for loss on investments, property and other assets
|
386 | 166 | 162 | |||||||||
|
Net (gain) loss on dispositions of assets and business
|
(44 | ) | (36 | ) | 16 | |||||||
|
Gain on sale of contractual production rights
|
— | (148 | ) | — | ||||||||
|
Early debt retirement costs
|
1 | 1 | 19 | |||||||||
|
Provision for doubtful accounts and notes
|
48 | 15 | 12 | |||||||||
|
Amortization of stock-based awards
|
43 | 31 | 70 | |||||||||
|
Cash provided (used) by changes in current assets and
liabilities:
|
||||||||||||
|
Accounts and notes receivable
|
67 | 329 | (122 | ) | ||||||||
|
Inventories
|
33 | (48 | ) | 29 | ||||||||
|
Margin deposits and customer margin deposits payable
|
4 | 88 | (135 | ) | ||||||||
|
Other current assets and deferred charges
|
(8 | ) | (76 | ) | (10 | ) | ||||||
|
Accounts payable
|
5 | (343 | ) | 26 | ||||||||
|
Accrued liabilities
|
(170 | ) | 7 | (200 | ) | |||||||
|
Changes in current and noncurrent derivative assets and
liabilities
|
36 | (121 | ) | 370 | ||||||||
|
Other, including changes in noncurrent assets and liabilities
|
92 | (23 | ) | (103 | ) | |||||||
|
Net cash provided by operating activities
|
2,572 | 3,355 | 2,237 | |||||||||
|
FINANCING ACTIVITIES:
|
||||||||||||
|
Proceeds from long-term debt
|
595 | 674 | 684 | |||||||||
|
Payments of long-term debt
|
(33 | ) | (665 | ) | (806 | ) | ||||||
|
Proceeds from issuance of common stock
|
6 | 32 | 56 | |||||||||
|
Proceeds from sale of limited partner units of consolidated
partnerships
|
— | 362 | 333 | |||||||||
|
Tax benefit of stock-based awards
|
1 | 21 | 32 | |||||||||
|
Dividends paid
|
(256 | ) | (250 | ) | (233 | ) | ||||||
|
Purchase of treasury stock
|
— | (474 | ) | (526 | ) | |||||||
|
Premiums paid on early debt retirements and tender offer
|
— | — | (27 | ) | ||||||||
|
Dividends and distributions paid to noncontrolling interests
|
(129 | ) | (122 | ) | (75 | ) | ||||||
|
Changes in cash overdrafts
|
(51 | ) | — | 52 | ||||||||
|
Other — net
|
33 | (10 | ) | (1 | ) | |||||||
|
Net cash provided (used) by financing activities
|
166 | (432 | ) | (511 | ) | |||||||
|
INVESTING ACTIVITIES:
|
||||||||||||
|
Property, plant and equipment:
|
||||||||||||
|
Capital expenditures*
|
(2,387 | ) | (3,394 | ) | (2,868 | ) | ||||||
|
Net proceeds from dispositions
|
72 | 119 | 12 | |||||||||
|
Purchases of investments/advances to affiliates
|
(142 | ) | (111 | ) | (60 | ) | ||||||
|
Purchases of auction rate securities
|
— | — | (304 | ) | ||||||||
|
Purchases of ARO trust investments
|
(46 | ) | (31 | ) | — | |||||||
|
Proceeds from sales of ARO trust investments
|
41 | 14 | — | |||||||||
|
Proceeds from sale of business
|
— | 22 | 471 | |||||||||
|
Proceeds from dispositions of investments and other assets
|
3 | 41 | 92 | |||||||||
|
Proceeds from sales of auction rate securities
|
— | — | 353 | |||||||||
|
Proceeds from sale of contractual production rights
|
— | 148 | — | |||||||||
|
Distribution from Gulfstream Natural Gas System, L.L.C.
|
148 | — | — | |||||||||
|
Other — net
|
1 | 9 | 8 | |||||||||
|
Net cash used by investing activities
|
(2,310 | ) | (3,183 | ) | (2,296 | ) | ||||||
|
Increase (decrease) in cash and cash equivalents
|
428 | (260 | ) | (570 | ) | |||||||
|
Cash and cash equivalents at beginning of year
|
1,439 | 1,699 | 2,269 | |||||||||
|
Cash and cash equivalents at end of year
|
1,867 | 1,439 | 1,699 | |||||||||
|
|
||||||||||||
|
* Increases to property, plant and equipment
|
(2,314 | ) | (3,475 | ) | (2,816 | ) | ||||||
|
Changes in related accounts payable and accrued liabilities
|
(73 | ) | 81 | (52 | ) | |||||||
|
Capital expenditures
|
$ | (2,387 | ) | $ | (3,394 | ) | $ | (2,868 | ) | |||
See accompanying notes.
88
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
| Note 1. | Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies |
Description
of Business
Operations of our company 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
(Gas Marketing).
Exploration & Production includes natural gas
development, production and gas management activities primarily
in the Rocky Mountain and Mid-Continent regions of the United
States and oil and natural gas interests in South America.
Gas Pipeline is comprised primarily of two interstate natural
gas pipelines, as well as investments in natural gas
pipeline-related companies. Gas Pipeline includes Northwest
Pipeline GP (Northwest Pipeline), which extends from the
San Juan basin in northwestern New Mexico and southwestern
Colorado to Oregon and Washington, and Transcontinental Gas Pipe
Line Company, LLC (Transco), which extends from the Gulf of
Mexico region to the northeastern United States. In addition, we
own a 50 percent interest in Gulfstream Natural Gas System,
L.L.C. (Gulfstream). Gulfstream is a natural gas pipeline system
extending from the Mobile Bay area in Alabama to markets in
Florida.
Midstream is comprised of natural gas gathering and processing
and treating facilities located primarily in the Rocky Mountain
and Gulf Coast regions of the United States, oil gathering and
transportation facilities in the Gulf Coast region of the United
States, and assets in Canada, consisting primarily of a natural
gas liquids extraction facility and a fractionation plant.
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 (NGLs) sales for
Midstream. Gas Marketing also provides similar services to third
parties, such as producers. In addition, Gas Marketing manages
various natural gas-related contracts such as transportation,
storage, related hedges and proprietary trading positions.
Basis
of Presentation
Prior period amounts reported for Midstream have been adjusted
for certain contracts involving the purchase and resale of NGLs
and/or
oil
with the same counterparties that should have been reported on a
net, rather than gross, basis. The error in presentation
overstated both
revenues
and
costs and operating
expenses
by equal amounts and had no impact on
segment
profit
,
operating income
,
net income
,
net
cash provided by operating activities
or any other key
internal measures of operating performance. These adjustments
reduced previously reported
revenues
and
costs and
operating expenses
by $295 million in 2008 and
$99 million in 2007.
Discontinued
operations
The accompanying consolidated financial statements and notes
reflect the results of operations and financial position of
certain of our Venezuela operations and our former power
business as discontinued operations. (See Note 2). Our
former power business included a 7,500-megawatt portfolio of
power-related contracts that was sold in 2007 and our natural
gas-fired electric generating plant located in Hazleton,
Pennsylvania (Hazleton) that was sold in March 2008, in addition
to other power-related assets.
Unless indicated otherwise, the information in the Notes to the
Consolidated Financial Statements relates to our continuing
operations.
89
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Master
limited partnerships
As of December 31, 2009, we own approximately
23.6 percent of Williams Partners L.P. (WPZ), including the
interests of the general partner, which is wholly owned by us,
and incentive distribution rights. Considering the presumption
of control of the general partner, we consolidate WPZ within our
Midstream segment.
As of December 31, 2009, we own approximately
47.7 percent of the interests in Williams Pipeline Partners
L.P. (WMZ), including the interests of the general partner,
which is wholly owned by us, and incentive distribution rights.
We consolidate WMZ within our Gas Pipeline segment due to our
control through the general partner.
Our overall ownership in WPZ and WMZ has been impacted by our
restructuring transactions in 2010. (See Note 19.)
Summary
of Significant Accounting Policies
Principles
of consolidation
The consolidated financial statements include the accounts of
our corporate parent and our majority-owned or controlled
subsidiaries and investments. We apply the equity method of
accounting for investments in unconsolidated companies in which
we and our subsidiaries own 20 to 50 percent of the voting
interest, otherwise exercise significant influence over
operating and financial policies of the company, or where
majority ownership does not provide us with control due to
significant participatory rights of other owners.
Use of
estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
requires management to make estimates and assumptions that
affect the amounts reported in the consolidated financial
statements and accompanying notes. Actual results could differ
from those estimates.
Significant estimates and assumptions include:
| • | Impairment assessments of investments, long-lived assets and goodwill; | |
| • | Litigation-related contingencies; | |
| • | Valuations of derivatives; | |
| • | Hedge accounting correlations and probability; | |
| • | Environmental remediation obligations; | |
| • | Realization of deferred income tax assets; | |
| • | Valuation of Exploration & Production’s reserves; | |
| • | Asset retirement obligations; | |
| • | Pension and postretirement valuation variables. |
These estimates are discussed further throughout these notes.
Cash and
cash equivalents
Our
cash and cash equivalents
balance includes amounts
primarily invested in funds with high-quality, short-term
securities and instruments that are issued or guaranteed by the
U.S. government. These have maturity dates of three months
or less when acquired.
90
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Accounts
receivable
Accounts receivable
are carried on a gross basis, with no
discounting, less the allowance for doubtful accounts. We
estimate the allowance for doubtful accounts based on existing
economic conditions, the financial conditions of the customers
and the amount and age of past due accounts. Receivables are
considered past due if full payment is not received by the
contractual due date. Interest income related to past due
accounts receivable is generally recognized at the time full
payment is received or collectability is assured. Past due
accounts are generally written off against the allowance for
doubtful accounts only after all collection attempts have been
exhausted.
Inventory
valuation
All
inventories
are stated at the lower of cost or
market. The cost of inventories is primarily determined using
the average-cost method. We determine the cost of certain
natural gas inventories held by Transco using the
last-in,
first-out (LIFO) cost method. LIFO inventory at
December 31, 2009 and 2008, is $7 million and
$11 million, respectively.
Property,
plant and equipment
Property, plant and equipment
is recorded at
cost. We base the carrying value of these assets on
estimates, assumptions and judgments relative to capitalized
costs, useful lives and salvage values.
As regulated entities, Northwest Pipeline and Transco provide
for depreciation using the straight-line method at Federal
Energy Regulatory Commission (FERC)-prescribed rates. See
Note 9 for depreciation rates used for major regulated gas
plant facilities.
Depreciation for nonregulated entities is provided primarily on
the straight-line method over estimated useful lives, except as
noted below for oil and gas exploration and production
activities. See Note 9 for the estimated useful lives
associated with our nonregulated assets.
Gains or losses from the ordinary sale or retirement of
property, plant and equipment for regulated pipelines are
credited or charged to accumulated depreciation; other gains or
losses are recorded in
other (income) expense — net
included in
operating income
.
Ordinary maintenance and repair costs are generally expensed as
incurred. Costs of major renewals and replacements are
capitalized as
property, plant, and equipment —
net
.
Oil and gas exploration and production activities are accounted
for under the successful efforts method. Costs incurred in
connection with the drilling and equipping of exploratory wells,
as applicable, are capitalized as incurred. If proved reserves
are not found, such costs are charged to expense. Other
exploration costs, including lease rentals, are expensed as
incurred. All costs related to development wells, including
related production equipment and lease acquisition costs, are
capitalized when incurred.
Depreciation, depletion and
amortization
is provided under the
units-of-production
method on a field basis.
We record an asset and a liability upon incurrence equal to the
present value of each expected future asset retirement
obligation (ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
other (income) expense — net
included in
operating income
, except for regulated entities, for
which the liability is offset by a regulatory asset.
Goodwill
Goodwill
represents the excess of cost over fair value of
the assets of businesses acquired. It is evaluated at least
annually for impairment by first comparing our management’s
estimate of the fair value of a reporting unit
91
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
with its carrying value, including goodwill. If the carrying
value of the reporting unit exceeds its fair value, a
computation of the implied fair value of the goodwill is
compared with its related carrying value. If the carrying value
of the reporting unit goodwill exceeds the implied fair value of
that goodwill, an impairment loss is recognized in the amount of
the excess. We also consider our market capitalization to
corroborate our estimate of the fair value of the reporting
unit. We have
goodwill
of approximately $1 billion
at December 31, 2009 and 2008, attributable to our
Exploration & Production segment.
When a reporting unit is sold or classified as held for sale,
any goodwill of that reporting unit is included in its carrying
value for purposes of determining any impairment or gain/loss on
sale. If a portion of a reporting unit with goodwill is sold or
classified as held for sale and that asset group represents a
business, a portion of the reporting unit’s goodwill is
allocated to and included in the carrying value of that asset
group. None of the operations sold during the periods reported
represented reporting units with goodwill or businesses within
reporting units to which goodwill was required to be allocated.
Judgments and assumptions are inherent in our management’s
estimate of future cash flows used to determine the estimate of
the reporting unit’s fair value. The use of alternate
judgments
and/or
assumptions could result in the recognition of different levels
of impairment charges in the financial statements. Given the
challenges affecting our businesses and the energy industry in
2010, we may be required to perform interim assessments of
goodwill for possible impairment during 2010, which could result
in a material impairment of our goodwill.
Treasury
stock
Treasury stock
purchases are accounted for under the cost
method whereby the entire cost of the acquired stock is recorded
as treasury stock. Gains and losses on the subsequent reissuance
of shares are credited or charged to
capital in excess of par
value
using the average-cost method.
Derivative
instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These
instruments consist primarily of futures contracts, swap
agreements, option contracts, and forward contracts involving
short- and long-term purchases and sales of a physical energy
commodity.
We report the fair value of derivatives, except for those for
which the normal purchases and normal sales exception has been
elected, on the Consolidated Balance Sheet in
derivative
assets
and
derivative liabilities
as either current
or noncurrent. We determine the current and noncurrent
classification based on the timing of expected future cash flows
of individual trades. We report these amounts on a gross basis.
Additionally, we report cash collateral receivables and payables
with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity
derivative can be summarized as follows:
| Derivative Treatment | Accounting Method | |
|
Normal purchases and normal sales exception
|
Accrual accounting | |
|
Designated in a qualifying hedging relationship
|
Hedge accounting | |
|
All other derivatives
|
Mark-to-market accounting |
We may elect the normal purchases and normal sales exception for
certain short- and long-term purchases and sales of a physical
energy commodity. Under accrual accounting, any change in the
fair value of these derivatives is not reflected on the balance
sheet after the initial election of the exception.
We have also designated a hedging relationship for certain
commodity derivatives. For a derivative to qualify for
designation in a hedging relationship, it must meet specific
criteria and we must maintain appropriate documentation. We
establish hedging relationships pursuant to our risk management
policies. We evaluate the hedging relationships at the inception
of the hedge and on an ongoing basis to determine whether the
hedging relationship is, and is expected to remain, highly
effective in achieving offsetting changes in fair value or cash
flows
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
attributable to the underlying risk being hedged. We also
regularly assess whether the hedged forecasted transaction is
probable of occurring. If a derivative ceases to be or is no
longer expected to be highly effective, or if we believe the
likelihood of occurrence of the hedged forecasted transaction is
no longer probable, hedge accounting is discontinued
prospectively, and future changes in the fair value of the
derivative are recognized currently in
revenues
or
costs and operating expenses
dependent upon the
underlying hedge transaction.
For commodity derivatives designated as a cash flow hedge, the
effective portion of the change in fair value of the derivative
is reported in
accumulated other comprehensive loss
and
reclassified into earnings in the period in which the hedged
item affects earnings. Any ineffective portion of the
derivative’s change in fair value is recognized currently
in
revenues
or
costs and operating expenses
. Gains
or losses deferred in
accumulated other comprehensive loss
associated with terminated derivatives, derivatives that
cease to be highly effective hedges, derivatives for which the
forecasted transaction is reasonably possible but no longer
probable of occurring, and cash flow hedges that have been
otherwise discontinued remain in
accumulated other
comprehensive loss
until the hedged item affects earnings.
If it becomes probable that the forecasted transaction
designated as the hedged item in a cash flow hedge will not
occur, any gain or loss deferred in
accumulated other
comprehensive loss
is recognized in
revenues
or
costs and operating expenses
at that time. The change in
likelihood is a judgmental decision that includes qualitative
assessments made by management.
For commodity derivatives that are not designated in a hedging
relationship, and for which we have not elected the normal
purchases and normal sales exception, we report changes in fair
value currently in
revenues
.
Certain gains and losses on derivative instruments included in
the Consolidated Statement of Income are netted together to a
single net gain or loss, while other gains and losses are
reported on a gross basis. Gains and losses recorded on a net
basis include:
| • | Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception; | |
| • | The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges; | |
| • | Realized gains and losses on all derivatives that settle financially other than natural gas derivatives for NGL processing activities; | |
| • | Realized gains and losses on derivatives held for trading purposes; | |
| • | Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement. |
Realized gains and losses on derivatives that require physical
delivery, as well as natural gas derivatives for NGL processing
activities and which are not held for trading purposes nor were
entered into as a pre-contemplated buy/sell arrangement, are
recorded on a gross basis. In reaching our conclusions on this
presentation, we considered whether we act as principal in the
transaction; whether we have the risks and rewards of ownership,
including credit risk; and whether we have latitude in
establishing prices.
Gas
Pipeline revenues
Gas Pipeline revenues are primarily from services pursuant to
long-term firm transportation and storage agreements. These
agreements provide for a demand charge based on the volume of
contracted capacity and a commodity charge based on the volume
of gas delivered, both at rates specified in our FERC tariffs.
We recognize revenues for demand charges ratably over the
contract period regardless of the volume of natural gas that is
transported or stored. Revenues for commodity charges, from both
firm and interruptible transportation services, and storage
injection and withdrawal services, are recognized when natural
gas is delivered at the agreed upon delivery point or when
natural gas is injected or withdrawn from the storage facility.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In the course of providing transportation services to customers,
we may receive different quantities of gas from shippers than
the quantities delivered on behalf of those shippers. The
resulting imbalances are primarily settled through the purchase
and sale of gas with our customers under terms provided for in
our FERC tariffs. Revenue is recognized from the sale of gas
upon settlement of the transportation and exchange imbalances.
As a result of the ratemaking process, certain revenues
collected by us may be subject to refunds upon the issuance of
final orders by the FERC in pending rate proceedings. We record
estimates of rate refund liabilities considering our and other
third-party regulatory proceedings, advice of counsel and other
risks.
Exploration &
Production revenues
Revenues from the domestic production of natural gas in
properties for which Exploration & Production has an
interest with other producers are recognized based on the actual
volumes sold during the period. Any differences between volumes
sold and entitlement volumes, based on Exploration &
Production’s net working interest, that are determined to
be nonrecoverable through remaining production are recognized as
accounts receivable or accounts payable, as appropriate.
Cumulative differences between volumes sold and entitlement
volumes are not significant.
Midstream
revenues
Natural gas gathering and processing services are performed
under volumetric-based fee contracts, keep-whole agreements and
percent-of-liquids
arrangements. Revenues under volumetric-based fee contracts are
recorded when services have been performed. Under keep-whole and
percent-of-liquids
processing contracts, we retain the rights to all or a portion
of the NGLs extracted from the producers’ natural gas
stream and recognize revenues when the extracted NGLs are sold
and delivered.
We have olefins extraction operations where we retain certain
products extracted from the producers’ off-gas stream and
we recognize revenues when the extracted products are sold and
delivered to our purchasers. We also produce olefins from
purchased feed-stock, and we recognize revenues when the olefins
are sold and delivered.
We also market NGLs and olefins. Revenues from marketing NGLs
and olefins are recognized when the products have been sold and
delivered.
Gas
Marketing revenues
Revenues for sales of natural gas are recognized when the
product is sold and delivered.
All other
revenues
Revenues generally are recorded when services are performed or
products have been delivered.
Impairment
of long-lived assets and investments
We evaluate the long-lived assets of identifiable business
activities for impairment when events or changes in
circumstances indicate, in our management’s judgment, that
the carrying value of such assets may not be recoverable. Except
for proved and unproved properties discussed below, when an
indicator of impairment has occurred, we compare our
management’s estimate of undiscounted future cash flows
attributable to the assets to the carrying value of the assets
to determine whether an impairment has occurred and we apply a
probability-weighted approach to consider the likelihood of
different cash flow assumptions and possible outcomes including
selling in the near term or holding for the remaining estimated
useful life. If an impairment of the carrying value has
occurred, we determine the amount of the impairment recognized
in the financial statements by estimating the fair value of the
assets and recording a loss for the amount that the carrying
value exceeds the estimated fair value.
For assets identified to be disposed of in the future and
considered held for sale, we compare the carrying value to the
estimated fair value less the cost to sell to determine if
recognition of an impairment is required. Until the
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
assets are disposed of, the estimated fair value, which includes
estimated cash flows from operations until the assumed date of
sale, is recalculated when related events or circumstances
change.
Proved properties, including developed and undeveloped, are
assessed for impairment using estimated future undiscounted cash
flows on a field basis. If the undiscounted cash flows are less
than the book value of the assets, then a subsequent analysis is
performed using discounted cash flows. Estimating future cash
flows involves the use of complex judgments such as estimation
of the oil and gas reserve quantities, risk associated with the
different categories of oil and gas reserves, timing of
development and production, expected future commodity prices,
capital expenditures, and production costs.
Unproved properties include lease acquisition costs and costs of
acquired unproved reserves. Individually significant lease
acquisition costs are assessed annually, or as conditions
warrant, for impairment considering our future drilling plans,
the remaining lease term and recent drilling results. Lease
acquisition costs that are not individually significant are
aggregated, and the portion of such costs estimated to be
nonproductive is amortized over the average holding period. The
estimate of what could be nonproductive is based on our
historical experience or other information, including current
drilling plans and existing geological data. A majority of the
costs of acquired unproved reserves are associated with areas to
which proved developed producing reserves are also attributed.
Generally, economic recovery of unproved reserves in such areas
is not yet supported by actual production or conclusive
formation tests, but may be confirmed by our continuing
development program. Ultimate recovery of potentially
recoverable reserves in areas with established production
generally has greater probability than in areas with limited or
no prior drilling activity. Costs of acquired unproved reserves
are assessed annually, or as conditions warrant, for impairment
using estimated future discounted cash flows on a field basis
and considering our future drilling plans. If the unproved
properties are determined to be productive, the appropriate
related costs are transferred to proved oil and gas properties.
We evaluate our investments for impairment when events or
changes in circumstances indicate, in our management’s
judgment, that the carrying value of such investments may have
experienced an
other-than-temporary
decline in value. When evidence of loss in value has occurred,
we compare our estimate of fair value of the investment to the
carrying value of the investment to determine whether an
impairment has occurred. If the estimated fair value is less
than the carrying value and we consider the decline in value to
be
other-than-temporary,
the excess of the carrying value over the fair value is
recognized in the consolidated financial statements as an
impairment.
Judgments and assumptions are inherent in our management’s
estimate of undiscounted future cash flows and an asset’s
fair value. Additionally, judgment is used to determine the
probability of sale with respect to assets considered for
disposal. The use of alternate judgments
and/or
assumptions could result in the recognition of different levels
of impairment charges in the consolidated financial statements.
Capitalization
of interest
We capitalize interest during construction on major projects
with construction periods of at least three months and a total
project cost in excess of $1 million. Interest is
capitalized on borrowed funds and, where regulation by the FERC
exists, on internally generated funds as a component of
other
income — net
. The rates used by regulated
companies are calculated in accordance with FERC rules. Rates
used by nonregulated companies are based on the average interest
rate on debt.
Employee
stock-based awards
Total stock-based compensation expense for the years ending
December 31, 2009, 2008, and 2007 was $43 million,
$31 million, and $70 million, respectively, of which
$1 million and $9 million in 2008 and 2007,
respectively, is included in
income (loss) from discontinued
operations
. Measured but unrecognized stock-based
compensation expense at December 31, 2009, was
approximately $44 million, which does not include the
effect of
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
estimated forfeitures of $2 million. This amount is
comprised of approximately $7 million related to stock
options and approximately $37 million related to restricted
stock units. These amounts are expected to be recognized over a
weighted-average period of 1.7 years.
Income
taxes
We include the operations of our subsidiaries in our
consolidated tax return. Deferred income taxes are computed
using the liability method and are provided on all temporary
differences between the financial basis and the tax basis of our
assets and liabilities. Our management’s judgment and
income tax assumptions are used to determine the levels, if any,
of valuation allowances associated with deferred tax assets.
Earnings
(loss) per common share
Basic earnings (loss) per common share
is based on the
sum of the weighted-average number of common shares outstanding
and vested restricted stock units.
Diluted earnings (loss)
per common share
includes any dilutive effect of stock
options, nonvested restricted stock units and, for applicable
periods presented, convertible debt, unless otherwise noted.
Foreign
currency translation
Certain of our foreign subsidiaries use their local currency as
their functional currency. These foreign currencies include the
Canadian dollar, British pound and Euro. Assets and liabilities
of certain foreign subsidiaries are translated at the spot rate
in effect at the applicable reporting date, and the combined
statements of operations are translated into the
U.S. dollar at the average exchange rates in effect during
the applicable period. The resulting cumulative translation
adjustment is recorded as a separate component of
accumulated
other comprehensive loss
.
Transactions denominated in currencies other than the functional
currency are recorded based on exchange rates at the time such
transactions arise. Subsequent changes in exchange rates result
in transaction gains and losses which are reflected in the
Consolidated Statement of Income.
Issuance
of equity of consolidated subsidiary
Sales of residual equity interests in a consolidated subsidiary
are accounted for as capital transactions. No adjustments to
capital are made for sales of preferential interests in a
subsidiary. No gain or loss is recognized on these transactions.
Accounting
Standards Issued But Not Yet Adopted
In January 2010, the FASB issued Accounting Standards Update
No. 2010-06,
“Fair Value Measurements and Disclosures (Topic
820) — Improving Disclosures about Fair Value
Measurements.” This Update requires new disclosures
regarding the amount of transfers in or out of Levels 1 and
2 along with the reason for such transfers and also requires a
greater level of disaggregation when disclosing valuation
techniques and inputs used in estimating Level 2 and
Level 3 fair value measurements. This Update also includes
conforming amendments to the guidance on employers’
disclosures about postretirement benefit plan assets. The
disclosures will be required for reporting beginning in the
first quarter 2010. Also, beginning with the first quarter 2011,
the Standard requires additional categorization of items
included in the rollforward of activity for Level 3 inputs
on a gross basis. We are assessing the application of this
Standard to disclosures in our Consolidated Financial Statements.
Subsequent
Events
We have evaluated our disclosure of subsequent events through
the time of filing this
Form 10-K
with the Securities and Exchange Commission on February 25,
2010.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 2. | Discontinued Operations |
Our Venezuela operations include majority ownership in entities
that owned and operated the El Furrial and PIGAP II gas
compression facilities prior to their expropriation by the
Venezuelan government in May 2009. We previously operated these
assets under long-term agreements for the exclusive benefit of
the state-owned oil company, Petróleos de Venezuela S.A.
(PDVSA). Construction of these assets was funded through project
financing that is collateralized by the stock, assets, and
contract rights of the entities that operated the Venezuela
assets and is nonrecourse to us. We and the secured lenders are
pursuing rights available to us under our agreements, including
contractual and international arbitration. These operations met
the accounting definition of a component of an entity. As a
result of the expropriation of the assets and the termination of
the associated contracts, we consider these assets to be
disposed and thus qualified for reporting as discontinued
operations.
Considering the expropriation of the assets and the significant
controlling rights of the secured lenders, we no longer control
these entities and no longer meet the criteria to consolidate
them. In conjunction with the deconsolidation of these entities
in the second quarter of 2009, we recorded our retained
investment in these entities at zero and recognized a pre-tax
gain of $9 million. This carrying value was based on our
estimates of probability-weighted discounted cash flows that
considered: (1) alternate arbitration venues,
(2) estimated levels of arbitration awards, (3) the
subsequent likelihood and timing of collection, (4) the
duration of the arbitration process, (5) a discount rate of
20 percent, and (6) the allocation of arbitration
proceeds between parties, including the secured lenders. The use
of alternate judgments
and/or
assumptions would have resulted in a different gain on
deconsolidation. The carrying value of our retained investment
in these entities was significantly impacted by our assumptions
and is not representative of our underlying claims against PDVSA
or the country of Venezuela.
The expropriations in the second quarter of 2009 followed an
extended period of nonpayment by PDVSA and default notices that
we provided in accordance with our agreements. The collection of
receivables from PDVSA was historically slower and required more
effort than with other customers due to PDVSA’s policies
and the political environment in Venezuela. In our year-end 2008
analysis, we expected PDVSA to resume regular payments following
a February 15, 2009, referendum vote in Venezuela; however,
that did not happen. PDVSA’s continued nonperformance
across the industry, their financial distress, and lack of
communications with us caused us to revise our assessment in the
first quarter of 2009.
As a result of this and our first-quarter assessment of the low
likelihood of PDVSA curing the defaults, we fully reserved
$48 million of accounts receivable from PDVSA in the first
quarter of 2009. In addition, we ceased revenue recognition of
these operations in the first quarter of 2009 as we no longer
believed that the collectability of revenues was reasonably
assured. This indicator of impairment required us to review our
Venezuela property, plant and equipment for recoverability,
which resulted in recording a $211 million impairment
charge at March 31, 2009. We estimated this impairment
charge using probability-weighted discounted cash flow estimates
that considered expected cash flows from: (1) the continued
operation of the assets considering a complete cure of the
default or a partial payment and renegotiation of the contracts,
(2) the purchase of the assets by PDVSA, and (3) the
results of arbitration with varying degrees of award and
collection. Considering the risk associated with operating in
Venezuela, we utilized an after-tax discount rate of
20 percent. The use of alternate judgments
and/or
assumptions would have resulted in the recognition of a
different or no impairment charge. Certain deferred charges and
credits, which netted to a $30 million charge, were also
written off because the related future cash inflows and outflows
were no longer expected to occur.
The past due payments from PDVSA triggered technical default of
the related project debt under our financing agreements in the
fourth quarter of 2008, which resulted in classification of the
entire debt balance as current at December 31, 2008.
The summarized results of discontinued operations primarily
reflect the results of the above described Venezuela operations
in 2009 and 2008 and our former power business in 2007, except
where noted otherwise. The summarized assets and liabilities of
discontinued operations primarily reflect the above described
Venezuela
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
operations. In November 2007, we sold substantially all of our
power business for approximately $496 million in cash. In
2008, we received an additional $22 million of proceeds,
including the final purchase price adjustments and
$8 million from the sale of Hazleton.
Summarized
Results of Discontinued Operations
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Revenues
|
$ | — | $ | 172 | $ | 2,584 | ||||||
|
Income (loss) from discontinued operations before (impairments)
and gain (loss) on sales, gain on deconsolidation, and income
taxes
|
$ | (87 | ) | $ | 241 | $ | 454 | |||||
|
(Impairments) and gain (loss) on sales
|
(211 | ) | 8 | (162 | ) | |||||||
|
Gain on deconsolidation
|
9 | — | — | |||||||||
|
(Provision) benefit for income taxes
|
66 | (124 | ) | (122 | ) | |||||||
|
Income (loss) from discontinued operations
|
$ | (223 | ) | $ | 125 | $ | 170 | |||||
|
Income (loss) from discontinued operations:
|
||||||||||||
|
Attributable to noncontrolling interests
|
$ | (70 | ) | $ | 13 | $ | 9 | |||||
|
Attributable to The Williams Companies, Inc.
|
$ | (153 | ) | $ | 112 | $ | 161 | |||||
Income (loss) from discontinued operations before
(impairments) and gain (loss) on sales, gain on deconsolidation,
and income taxes
for 2009 primarily includes losses related
to our discontinued Venezuela operations, including the
previously discussed $48 million of bad debt expense
related to fully reserving accounts receivable from PDVSA and
the $30 million net charge related to the write-off of
certain deferred charges and credits. Offsetting these losses is
a $15 million gain related to our former coal operations.
Income (loss) from discontinued operations before
(impairments) and gain (loss) on sales, gain on deconsolidation,
and income taxes
for 2008 includes:
| • | $140 million of gains related to the favorable resolution of matters involving pipeline transportation rates associated with our former Alaska operations; | |
| • | $77 million of income related to our discontinued Venezuela operations; | |
| • | $54 million of income related to a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank; | |
| • | An $11 million charge associated with an oil purchase contract related to our former Alaska refinery; | |
| • | A $10 million charge associated with a settlement primarily related to the sale of NGL pipeline systems in 2002. |
Income (loss) from discontinued operations before
(impairments) and gain (loss) on sales, gain on deconsolidation,
and income taxes
for 2007 includes a gain of
$429 million (reported in
revenues
of discontinued
operations) associated with the reclassification of deferred net
hedge gains from
accumulated other comprehensive loss
to
earnings in second-quarter 2007. This reclassification was based
on the determination that the hedged forecasted transactions
were probable of not occurring due to the sale of our power
business. This gain is partially offset by unrealized
mark-to-market
losses of approximately $23 million.
Income (loss) from
discontinued operations before (impairments) and gain (loss) on
sales, gain on deconsolidation, and income taxes
also
includes the results of our former power business and
discontinued Venezuela operations.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
(Impairments) and gain (loss) on sales
for 2009 reflects
the previously described $211 million impairment of our
Venezuela property, plant, and equipment.
(Impairments) and gain (loss) on sales
for 2008 includes
the final proceeds from the sale of our former power business.
(Impairments) and gain (loss) on sales
for 2007 includes
a pre-tax loss of $37 million on the sale of substantially
all of our power business. We also recognized impairments of
$111 million related to the carrying value of certain
derivative contracts for which we had previously elected the
normal purchases and normal sales exception and, accordingly,
were no longer recording at fair value, and $14 million
related to Hazleton. These impairments were based on our
comparison of the carrying value to the estimate of fair value
less cost to sell.
(Provision) benefit for income taxes
for 2009 includes a
$76 million benefit from the reversal of deferred tax
balances related to our discontinued Venezuela operations.
Summarized
Assets and Liabilities of Discontinued Operations
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Cash and cash equivalents
|
$ | — | $ | 1 | ||||
|
Accounts receivable — net
|
1 | 62 | ||||||
|
Other current assets
|
— | 79 | ||||||
|
Total current assets
|
1 | 142 | ||||||
|
Property, plant and equipment — net
|
— | 324 | ||||||
|
Other noncurrent assets
|
— | 63 | ||||||
|
Total noncurrent assets
|
— | 387 | ||||||
|
Total assets
|
$ | 1 | $ | 529 | ||||
|
Long-term debt due within one year
|
$ | — | $ | 177 | ||||
|
Other current liabilities
|
— | 40 | ||||||
|
Total current liabilities
|
— | 217 | ||||||
|
Total noncurrent liabilities
|
— | 82 | ||||||
|
Total liabilities
|
$ | — | $ | 299 | ||||
| Note 3. | Investing Activities |
Investing
Income
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Equity earnings*
|
$ | 136 | $ | 137 | $ | 137 | ||||||
|
Income (loss) from investments*
|
(75 | ) | 1 | — | ||||||||
|
Impairment of cost-based investments
|
(22 | ) | (4 | ) | (1 | ) | ||||||
|
Interest income and other
|
7 | 55 | 116 | |||||||||
|
Total investing income
|
$ | 46 | $ | 189 | $ | 252 | ||||||
| * | Items also included in segment profit (loss). (See Note 18.) |
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Income (loss) from investments
in 2009 reflects a
$75 million impairment charge related to an
other-than-temporary
loss in value associated with our Venezuelan investment in
Accroven SRL (Accroven). Accroven owns and operates gas
processing facilities and a NGL fractionation plant for the
exclusive benefit of PDVSA. The deteriorating circumstances in
the first quarter of 2009 for our Venezuelan operations (see
Note 2) caused us to review our investment in
Accroven. We utilized a probability-weighted discounted cash
flow analysis, which included an after-tax discount rate of
20 percent to reflect the risk associated with operating in
Venezuela. (See Note 14.) Accroven was not part of the
operations that were expropriated by the Venezuelan government
in May 2009. We have been engaged in discussions regarding the
eventual disposition of Accroven.
Impairment of cost-based investments
in 2009 includes an
$11 million impairment related to our 4 percent
interest in a Venezuelan corporation that owns and operates oil
and gas activities. This investment resulted from our previous
10 percent direct working interest in a concession that was
converted to a reduced interest in a mixed company at the
direction of the Venezuelan government in 2006. Considering our
evaluation of the deteriorating financial condition of this
corporation, we recorded an
other-than-temporary
decline in value of our remaining investment balance.
The unfavorable change in
interest income and other
in
2009 and 2008 is primarily due to lower average interest rates.
Investments
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Equity method:
|
||||||||
|
Gulfstream — 50%
|
$ | 383 | $ | 525 | ||||
|
Discovery Producer Services LLC — 60%*
|
189 | 184 | ||||||
|
Laurel Mountain Midstream, LLC — 51%*
|
133 | — | ||||||
|
Petrolera Entre Lomas S.A. — 40.8%
|
81 | 73 | ||||||
|
Accroven — 49.3%
|
— | 69 | ||||||
|
Other
|
98 | 96 | ||||||
| 884 | 947 | |||||||
|
Cost method
|
2 | 24 | ||||||
| $ | 886 | $ | 971 | |||||
| * | We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control the investments. |
Differences between the carrying value of our equity investments
and the underlying equity in the net assets of the investees are
primarily related to impairments we previously recognized.
In 2009, we invested $132 million in Laurel Mountain
Midstream, LLC. In addition, we contributed $20 million in
2009 and $90 million in 2008 to Gulfstream.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Dividends and distributions, including those presented below,
received from companies accounted for by the equity method were
$291 million in 2009 and $167 million in 2008. These
transactions reduced the carrying value of our investments.
These dividends and distributions primarily included:
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Gulfstream
|
$ | 223 | $ | 58 | ||||
|
Discovery Producer Services LLC
|
32 | 56 | ||||||
|
Aux Sable Liquid Products LP
|
15 | 28 | ||||||
In 2009, we received a $148 million distribution from
Gulfstream following its debt offering.
Summarized
Financial Position and Results of Operations of Equity Method
Investments
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Current assets
|
$ | 383 | $ | 342 | ||||
|
Noncurrent assets
|
3,723 | 3,505 | ||||||
|
Current liabilities
|
266 | 253 | ||||||
|
Noncurrent liabilities
|
1,511 | 1,278 | ||||||
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Gross revenue
|
$ | 1,115 | $ | 1,246 | $ | 1,163 | ||||||
|
Operating income
|
516 | 521 | 515 | |||||||||
|
Net income
|
396 | 405 | 385 | |||||||||
101
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 4. | Asset Sales, Impairments and Other Accruals |
The following table presents significant gains or losses
reflected in
other (income) expense — net
within
segment costs and expenses.
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Exploration & Production
|
||||||||||||
|
Gain on sale of contractual right to an international production
payment
|
$ | — | $ | (148 | ) | $ | — | |||||
|
Impairment of certain properties
|
20 | 143 | — | |||||||||
|
Penalties from early release of drilling rigs
|
32 | — | — | |||||||||
|
Gas Pipeline
|
||||||||||||
|
Income from change in estimate related to a regulatory liability
|
— | — | (17 | ) | ||||||||
|
Income from payments received for a terminated firm
transportation agreement on Grays Harbor lateral
|
— | — | (18 | ) | ||||||||
|
Gain on sale of certain south Texas assets
|
— | (10 | ) | — | ||||||||
|
Midstream
|
||||||||||||
|
Income from favorable litigation outcome
|
— | — | (12 | ) | ||||||||
|
Impairment of Carbonate Trend pipeline
|
— | 6 | 10 | |||||||||
|
Gulf Liquids litigation contingency accrual reversal (see
Note 16)
|
— | (32 | ) | — | ||||||||
|
Involuntary conversion gains related to Ignacio plant
|
(4 | ) | (12 | ) | — | |||||||
|
Gain on sale of Cameron Meadows plant
|
(40 | ) | — | — | ||||||||
|
Gas Marketing Services
|
||||||||||||
|
Accrual for litigation contingencies
|
— | — | 20 | |||||||||
Other (income) expense — net
within
segment
costs and expenses
also includes net foreign currency
exchange gains of $38 million in 2008 and net foreign
currency exchange losses of $12 million in 2007. The net
gain in 2008 primarily relates to the remeasurement of current
assets held in U.S. dollars within our Canadian operations
in the Midstream segment.
Impairment
of certain Exploration & Production
properties
Based on a comparison of the estimated fair value to the
carrying value, Exploration & Production recorded a
$15 million impairment in December 2009 related to costs of
acquired unproved reserves resulting from a 2008 acquisition in
the Fort Worth basin. Additionally, Exploration &
Production recorded impairment charges of $5 million and
$143 million in 2009 and 2008, respectively, related to
properties in the Arkoma basin. Our impairment analysis included
an assessment of undiscounted (except for the unproved reserves)
and discounted future cash flows, which considered information
obtained from drilling, other activities, and year-end natural
gas reserve quantities.
Additional
Items
In 2009, Exploration & Production recognized
$11 million of income related to the recovery of certain
royalty overpayments from prior periods, which is reflected
within
revenues
.
In 2008, Exploration & Production recorded a
$34 million accrual for Wyoming severance taxes, which is
reflected in
costs and operating expenses
within
segment costs and expenses
. Associated with this charge
is an interest expense accrual of $4 million, which is
included in
interest accrued.
(See Note 16.)
102
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 5. | Provision for Income Taxes |
The
provision for income taxes
from continuing operations
includes:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 10 | $ | 179 | $ | 29 | ||||||
|
State
|
12 | 24 | 9 | |||||||||
|
Foreign
|
21 | 8 | 21 | |||||||||
| 43 | 211 | 59 | ||||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
271 | 466 | 422 | |||||||||
|
State
|
42 | (11 | ) | (4 | ) | |||||||
|
Foreign
|
3 | 11 | 13 | |||||||||
| 316 | 466 | 431 | ||||||||||
|
Total provision
|
$ | 359 | $ | 677 | $ | 490 | ||||||
Reconciliations from the
provision for income taxes
from
continuing operations at the federal statutory rate to the
realized
provision for income taxes
are as follows:
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Provision at statutory rate
|
$ | 330 | $ | 750 | $ | 490 | ||||||
|
Increases (decreases) in taxes resulting from:
|
||||||||||||
|
State income taxes (net of federal benefit)
|
35 | 8 | 4 | |||||||||
|
Foreign operations — net
|
25 | (16 | ) | 1 | ||||||||
|
Impact of nontaxable noncontrolling interests
|
(49 | ) | (54 | ) | (25 | ) | ||||||
|
Other — net
|
18 | (11 | ) | 20 | ||||||||
|
Provision for income taxes
|
$ | 359 | $ | 677 | $ | 490 | ||||||
State income taxes (net of federal benefit) were reduced by
$46 million in 2008 due to a reduction in our estimate of
the effective deferred state rate reflective of a change in the
mix of jurisdictional attribution of taxable income.
Income from continuing operations before income taxes
includes $36 million of foreign loss, and
$139 million and $127 million of foreign income in
2009, 2008, and 2007, respectively.
During the course of audits of our business by domestic and
foreign tax authorities, we frequently face challenges 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. In evaluating the
liability associated with our various filing positions, we apply
the two-step process of recognition and measurement. In
association with this liability, we record an estimate of
related interest and tax exposure as a component of our tax
provision. The impact of this accrual is included within
other — net
in our reconciliation of the tax
provision to the federal statutory rate.
103
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Significant components of
deferred tax liabilities
and
deferred tax assets
as of December 31, 2009 and
2008, are as follows:
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Deferred tax liabilities:
|
||||||||
|
Property, plant and equipment
|
$ | 3,658 | $ | 3,288 | ||||
|
Derivatives — net
|
66 | 263 | ||||||
|
Investments
|
491 | 380 | ||||||
|
Other
|
108 | 112 | ||||||
|
Total deferred tax liabilities
|
4,323 | 4,043 | ||||||
|
Deferred tax assets:
|
||||||||
|
Accrued liabilities
|
557 | 581 | ||||||
|
Foreign carryovers
|
4 | 3 | ||||||
|
Minimum tax credits
|
62 | — | ||||||
|
Other
|
58 | 55 | ||||||
|
Total deferred tax assets
|
681 | 639 | ||||||
|
Less valuation allowance
|
4 | 3 | ||||||
|
Net deferred tax assets
|
677 | 636 | ||||||
|
Overall net deferred tax liabilities
|
$ | 3,646 | $ | 3,407 | ||||
The
valuation allowance
at December 31, 2009 and
2008 serves to reduce the recognized tax benefit associated with
foreign carryovers to an amount that will, more likely than not,
be realized. We do not expect to be able to utilize our
$4 million of foreign deferred tax assets.
Undistributed earnings of certain consolidated foreign
subsidiaries, inclusive of discontinued operations, at
December 31, 2009, totaled approximately $165 million.
No provision for deferred U.S. income taxes has been made
for these subsidiaries because we intend to permanently reinvest
such earnings in foreign operations.
Cash payments for income taxes (net of refunds and including
discontinued operations) were $14 million,
$155 million, and $384 million in 2009, 2008, and
2007, respectively. Cash tax payments include settlements with
taxing authorities associated with prior period audits of
$9 million, $47 million, and $94 million in 2009,
2008, and 2007, respectively.
As of December 31, 2009, we had approximately
$72 million of unrecognized tax benefits. If recognized,
approximately $61 million, net of federal tax expense,
would be recorded as a reduction of income tax expense. A
reconciliation of the beginning and ending amount of
unrecognized tax benefits is as follows:
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Balance at beginning of period
|
$ | 79 | $ | 76 | ||||
|
Additions based on tax positions related to the current year
|
— | 3 | ||||||
|
Additions for tax positions for prior years
|
4 | 8 | ||||||
|
Reductions for tax positions of prior years
|
(7 | ) | (8 | ) | ||||
|
Settlement with taxing authorities
|
(4 | ) | — | |||||
|
Balance at end of period
|
$ | 72 | $ | 79 | ||||
104
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
We recognize related interest and penalties as a component of
income tax expense. Total interest and penalties recognized as
part of income tax expense were $17 million,
$2 million, and $60 million for 2009, 2008, and 2007,
respectively. Approximately $93 million and
$81 million of interest and penalties primarily relating to
uncertain tax positions have been accrued as of
December 31, 2009 and 2008, respectively.
As of December 31, 2009, the Internal Revenue Service (IRS)
examination of our consolidated U.S. income tax return for
2008 is in process. IRS examinations for 1997 through 2007 have
been completed at the field level but the years remain open for
certain unagreed issues. The statute of limitations for most
states expires one year after expiration of the IRS statute.
Generally, tax returns for our Venezuelan, Argentine, and
Canadian entities are open to audit from 2002 through 2009.
Certain Canadian entities are currently under examination.
During the next 12 months, we do not expect ultimate
resolution of any uncertain tax position associated with a
domestic or international matter will result in a significant
increase or decrease of our unrecognized tax benefit. However,
certain matters we have contested to the Internal Revenue
Service Appeals Division could be resolved and result in a
reduction to our unrecognized tax benefit.
| Note 6. | Earnings Per Common Share from Continuing Operations |
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions, except per-share amounts; shares in thousands) | ||||||||||||
|
Income from continuing operations attributable to The Williams
Companies, Inc., available to common stockholders for basic and
diluted earnings per common share(1)
|
$ | 438 | $ | 1,306 | $ | 829 | ||||||
|
Basic weighted-average shares(2)(3)
|
581,674 | 581,342 | 596,174 | |||||||||
|
Effect of dilutive securities:
|
||||||||||||
|
Nonvested restricted stock units
|
2,216 | 1,334 | 1,627 | |||||||||
|
Stock options
|
2,065 | 3,439 | 4,743 | |||||||||
|
Convertible debentures(3)
|
3,430 | 6,604 | 7,322 | |||||||||
|
Diluted weighted-average shares
|
589,385 | 592,719 | 609,866 | |||||||||
|
Earnings per common share from continuing operations:
|
||||||||||||
|
Basic
|
$ | .75 | $ | 2.25 | $ | 1.39 | ||||||
|
Diluted
|
$ | .75 | $ | 2.21 | $ | 1.37 | ||||||
| (1) | The years of 2009, 2008, and 2007 include $1 million, $2 million and $3 million, respectively, of interest expense, net of tax, associated with our 5.5 percent convertible debentures. (See Note 12.) These amounts have been added back to income from continuing operations attributable to The Williams Companies, Inc., available to common stockholders to calculate diluted earnings per common share. | |
| (2) | From the inception of our stock repurchase program in third-quarter 2007 to its completion in July 2008, we purchased 29 million shares of our common stock. (See Note 12.) | |
| (3) | During 2009 and 2008, we issued 3 million shares and 2 million shares, respectively, of our common stock in exchange for a portion of our 5.5 percent convertible debentures. (See Note 12.) |
105
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The table below includes information related to stock options
that were outstanding at the end of each respective year but
have been excluded from the computation of weighted-average
stock options due to the option exercise price exceeding the
fourth quarter weighted-average market price of our common
shares.
| 2009 | 2008 | 2007 | ||||||||||
|
Options excluded (millions)
|
3.7 | 6.4 | .8 | |||||||||
|
Weighted-average exercise prices of options excluded
|
$ | 30.21 | $ | 26.41 | $ | 40.07 | ||||||
|
Exercise price ranges of options excluded
|
$ | 20.28 - $42.29 | $ | 16.40 - $42.29 | $ | 36.66 - $42.29 | ||||||
|
Fourth quarter weighted-average market price
|
$ | 19.81 | $ | 16.37 | $ | 35.14 | ||||||
| Note 7. | Employee Benefit Plans |
We have noncontributory defined benefit pension plans in which
all eligible employees participate. Currently, eligible
employees earn benefits primarily based on a cash balance
formula. Various other formulas, as defined in the plan
documents, are utilized to calculate the retirement benefits for
plan participants not covered by the cash balance formula. At
the time of retirement, participants may elect, to the extent
they are eligible for the various options, to receive annuity
payments, a lump sum payment, or a combination of lump sum and
annuity payments. In addition to our pension plans, we currently
provide subsidized retiree medical and life insurance benefits
(other postretirement benefits) to certain eligible
participants. Generally, employees hired after December 31,
1991, are not eligible for the subsidized retiree medical
benefits, except for participants that were employees of Transco
Energy Company on December 31, 1995, and other
miscellaneous defined participant groups. Certain of these other
postretirement benefit plans, particularly the subsidized
retiree medical benefit plans, provide for retiree contributions
and contain other cost-sharing features such as deductibles,
co-payments, and co-insurance. The accounting for these plans
anticipates future cost-sharing that is consistent with our
expressed intent to increase the retiree contribution level
generally in line with health care cost increases.
106
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Benefit
Obligations
The following table presents the changes in benefit obligations
and plan assets for pension benefits and other postretirement
benefits for the years indicated. The annual measurement date
for our plans is December 31.
|
Other
|
||||||||||||||||
|
Postretirement
|
||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (Millions) | ||||||||||||||||
|
Change in benefit obligation:
|
||||||||||||||||
|
Benefit obligation at beginning of year
|
$ | 1,035 | $ | 896 | $ | 273 | $ | 284 | ||||||||
|
Service cost
|
32 | 23 | 2 | 2 | ||||||||||||
|
Interest cost
|
62 | 60 | 16 | 18 | ||||||||||||
|
Plan participants’ contributions
|
— | — | 5 | 5 | ||||||||||||
|
Benefits paid
|
(59 | ) | (70 | ) | (24 | ) | (23 | ) | ||||||||
|
Medicare Part D subsidy
|
— | — | 2 | 2 | ||||||||||||
|
Plan amendment
|
— | — | (18 | ) | (38 | ) | ||||||||||
|
Actuarial loss
|
48 | 126 | 3 | 23 | ||||||||||||
|
Benefit obligation at end of year
|
1,118 | 1,035 | 259 | 273 | ||||||||||||
|
Change in plan assets:
|
||||||||||||||||
|
Fair value of plan assets at beginning of year
|
705 | 1,074 | 126 | 192 | ||||||||||||
|
Actual return on plan assets
|
153 | (360 | ) | 25 | (62 | ) | ||||||||||
|
Employer contributions
|
61 | 61 | 16 | 14 | ||||||||||||
|
Plan participants’ contributions
|
— | — | 5 | 5 | ||||||||||||
|
Benefits paid
|
(59 | ) | (70 | ) | (24 | ) | (23 | ) | ||||||||
|
Fair value of plan assets at end of year
|
860 | 705 | 148 | 126 | ||||||||||||
|
Funded status — underfunded
|
$ | (258 | ) | $ | (330 | ) | $ | (111 | ) | $ | (147 | ) | ||||
|
Accumulated benefit obligation
|
$ | 1,075 | $ | 959 | ||||||||||||
The underfunded status of our pension plans and other
postretirement benefit plans presented in the previous table are
recognized in the Consolidated Balance Sheet within the
following accounts:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Underfunded pension plans:
|
||||||||
|
Current liabilities
|
$ | 1 | $ | 1 | ||||
|
Noncurrent liabilities
|
257 | 329 | ||||||
|
Underfunded other postretirement benefit plans:
|
||||||||
|
Current liabilities
|
8 | 8 | ||||||
|
Noncurrent liabilities
|
103 | 139 | ||||||
The plan assets within our other postretirement benefit plans
are intended to be used for the payment of benefits for certain
groups of participants. The
current liabilities
for the
other postretirement benefit plans represent the current portion
of benefits expected to be payable in the subsequent year for
the groups of participants whose benefits are not expected to be
paid from plan assets.
107
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The 2009 benefit obligation
actuarial loss
of
$48 million for our pension plans is primarily due to the
impact of decreases in the discount rate utilized to calculate
the benefit obligation. The 2008 benefit obligation
actuarial
losses
of $126 million for our pension plans and
$23 million for our other postretirement benefit plans are
primarily due to the impact of decreases in the discount rate
utilized to calculate the benefit obligation as well as changes
to the mortality assumptions. The other postretirement benefits
plan amendments
of $18 million in 2009 and
$38 million in 2008 are due to consecutive increases in the
retirees’ cost-sharing percentage within our subsidized
retiree medical benefit plans.
At December 31, 2009 and 2008, all of our pension plans had
a projected benefit obligation and accumulated benefit
obligation in excess of plan assets.
The current accounting rules for the determination of
net
periodic benefit expense
allow for the delayed recognition
of gains and losses caused by differences between actual and
assumed outcomes for items such as estimated return on plan
assets, or caused by changes in assumptions for items such as
discount rates or estimated future compensation levels. The
net actuarial gain (loss)
presented in the following
table and recorded in
accumulated other comprehensive loss
and
net regulatory assets
represents the cumulative
net deferred gain (loss) from these types of differences or
changes which have not yet been recognized in the Consolidated
Statement of Income. A portion of the
net actuarial gain
(loss)
is amortized over the participants’ average
remaining future years of service, which is approximately
13 years for our pension plans and approximately
12 years for our other postretirement benefit plans.
Pre-tax amounts not yet recognized in
net periodic benefit
expense
at December 31 are as follows:
|
Other
|
||||||||||||||||
|
Postretirement
|
||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
| (Millions) | ||||||||||||||||
|
Amounts included in
accumulated other comprehensive loss
:
|
||||||||||||||||
|
Prior service (cost) credit
|
$ | (4 | ) | $ | (5 | ) | $ | 15 | $ | 12 | ||||||
|
Net actuarial loss
|
(621 | ) | (708 | ) | (9 | ) | (8 | ) | ||||||||
|
Amounts included in
net regulatory assets
associated with
our FERC-regulated gas pipelines:
|
||||||||||||||||
|
Prior service credit
|
N/A | N/A | $ | 28 | $ | 24 | ||||||||||
|
Net actuarial loss
|
N/A | N/A | (40 | ) | (57 | ) | ||||||||||
108
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Net
Periodic Benefit Expense and Items Recognized in Other
Comprehensive Income (Loss)
Net periodic benefit expense
and other changes in plan
assets and benefit obligations recognized in
other
comprehensive income (loss)
before taxes for the years ended
December 31 consist of the following:
|
Other
|
||||||||||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
|
Components of net periodic benefit expense:
|
||||||||||||||||||||||||
|
Service cost
|
$ | 32 | $ | 23 | $ | 23 | $ | 2 | $ | 2 | $ | 3 | ||||||||||||
|
Interest cost
|
62 | 60 | 54 | 16 | 18 | 17 | ||||||||||||||||||
|
Expected return on plan assets
|
(61 | ) | (79 | ) | (73 | ) | (9 | ) | (13 | ) | (12 | ) | ||||||||||||
|
Amortization of prior service cost (credit)
|
1 | 1 | — | (11 | ) | — | — | |||||||||||||||||
|
Amortization of net actuarial loss
|
43 | 13 | 19 | 3 | — | — | ||||||||||||||||||
|
Amortization of regulatory asset
|
1 | — | 1 | 5 | 5 | 5 | ||||||||||||||||||
|
Net periodic benefit expense
|
$ | 78 | $ | 18 | $ | 24 | $ | 6 | $ | 12 | $ | 13 | ||||||||||||
|
Other changes in plan assets and benefit obligations recognized
in
other comprehensive income (loss):
|
||||||||||||||||||||||||
|
Net actuarial (gain) loss
|
$ | (44 | ) | $ | 565 | $ | (68 | ) | $ | 1 | $ | 15 | $ | (15 | ) | |||||||||
|
Prior service credit
|
— | — | — | (7 | ) | (16 | ) | — | ||||||||||||||||
|
Amortization of prior service (cost) credit
|
(1 | ) | (1 | ) | — | 4 | (1 | ) | (2 | ) | ||||||||||||||
|
Amortization of net actuarial loss
|
(43 | ) | (13 | ) | (19 | ) | — | — | — | |||||||||||||||
|
Other changes in plan assets and benefit obligations recognized
in
other comprehensive income (loss)
|
(88 | ) | 551 | (87 | ) | (2 | ) | (2 | ) | (17 | ) | |||||||||||||
|
Total recognized in
net periodic benefit expense
and
other comprehensive income (loss)
|
$ | (10 | ) | $ | 569 | $ | (63 | ) | $ | 4 | $ | 10 | $ | (4 | ) | |||||||||
Other changes in plan assets and benefit obligations for our
other postretirement benefit plans associated with our
FERC-regulated gas pipelines are recognized in
net regulatory
assets
at December 31, 2009, and include
net
actuarial gain
of $14 million,
prior service credit
of $11 million,
amortization of prior service credit
of $7 million, and
amortization of net actuarial
loss
of $3 million. At December 31, 2008, amounts
recognized in
net regulatory assets
included
net
actuarial loss
of $83 million,
prior service credit
of $22 million, and
amortization of prior service
credit
of $1 million. At December 31, 2007,
amounts recognized in
net regulatory liabilities
included
net actuarial gain
of $18 million and
amortization of prior service credit
of $2 million.
Pre-tax amounts expected to be amortized in
net periodic
benefit expense
in 2010 are as follows:
|
Other
|
||||||||
|
Pension
|
Postretirement
|
|||||||
| Benefits | Benefits | |||||||
| (Millions) | ||||||||
|
Amounts included in
accumulated other comprehensive loss
:
|
||||||||
|
Prior service cost (credit)
|
$ | 1 | $ | (5 | ) | |||
|
Net actuarial loss
|
34 | — | ||||||
|
Amounts included in
net regulatory assets
associated with
our FERC-regulated gas pipelines:
|
||||||||
|
Prior service credit
|
N/A | $ | (9 | ) | ||||
|
Net actuarial loss
|
N/A | 2 | ||||||
109
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The differences in the amount of actuarially determined
net
periodic benefit expense
for our other postretirement
benefit plans and the other postretirement benefit costs
recovered in rates for our FERC-regulated gas pipelines are
deferred as a regulatory asset or liability. At
December 31, 2009, we have
net regulatory liabilities
of $3 million and at December 31, 2008, we had
net regulatory assets
of $26 million related to
these deferrals. These amounts will be reflected in future rates
based on the gas pipelines’ rate structures.
Key
Assumptions
The weighted-average assumptions utilized to determine benefit
obligations as of December 31 are as follows:
|
Other
|
||||||||||||||||
|
Postretirement
|
||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||||||
|
Discount rate
|
5.78 | % | 6.08 | % | 5.80 | % | 6.00 | % | ||||||||
|
Rate of compensation increase
|
5.00 | 5.00 | N/A | N/A | ||||||||||||
The weighted-average assumptions utilized to determine
net
periodic benefit expense
for the years ended December 31 are
as follows:
|
Other
|
||||||||||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
|
Discount rate
|
6.08 | % | 6.41 | % | 5.80 | % | 6.00 | % | 6.40 | % | 5.80 | % | ||||||||||||
|
Expected long-term rate of return on plan assets
|
7.75 | 7.75 | 7.75 | 7.00 | 7.00 | 6.97 | ||||||||||||||||||
|
Rate of compensation increase
|
5.00 | 5.00 | 5.00 | N/A | N/A | N/A | ||||||||||||||||||
The discount rates for our pension and other postretirement
benefit plans were determined separately based on an approach
specific to our plans. The year-end discount rates were
determined considering a yield curve comprised of high-quality
corporate bonds published by a large securities firm and the
timing of the expected benefit cash flows of each plan.
The expected long-term rates of return on plan assets were
determined by combining a review of the 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 and the target weightings of each asset
classification.
The expected return on plan assets component of
net periodic
benefit expense
is calculated using the market-related value
of plan assets. For assets held in our pension plans, the
market-related value of plan assets is equal to the fair value
of plan assets adjusted to reflect amortization of gains or
losses associated with the difference between the expected
return on plan assets and the actual return on plan assets over
a five-year period. Additionally, the market-related value of
plan assets may be no more than 110 percent or less than
90 percent of the fair value of plan assets at the
beginning of the year. The market-related value of plan assets
for our other postretirement benefit plans is equal to the
unadjusted fair value of plan assets at the beginning of the
year.
The mortality assumptions used to determine the obligations for
our pension and other postretirement benefit plans are related
to the experience of the plans and the best estimate of expected
plan mortality. The selected mortality tables are among the most
recent tables available.
110
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The assumed health care cost trend rate for 2010 is
8.2 percent, and systematically decreases to
5.0 percent by 2020. The health care cost trend rate
assumption has a significant effect on the amounts reported. A
one-percentage-point change in assumed health care cost trend
rates would have the following effects:
| Point increase | Point decrease | |||||||
| (Millions) | ||||||||
|
Effect on total of service and interest cost components
|
$ | 2 | $ | (2 | ) | |||
|
Effect on other postretirement benefit obligation
|
33 | (27 | ) | |||||
Plan
Assets
The investment policy for our pension and other postretirement
benefit plans articulates an investment philosophy in accordance
with ERISA, which governs the investment of the assets in a
diversified portfolio. The investment strategy for the assets of
the pension plans and approximately one half of the assets of
the other postretirement benefit plans include maximizing
returns with reasonable and prudent levels of risk. The
investment returns on the approximate one half of remaining
assets of the other postretirement benefit plans is subject to
federal income tax; therefore, the investment strategy also
includes investing in a tax efficient manner. The target
allocation ranges at December 31, 2009, for the pension
plan assets were 65 percent to 90 percent equity
securities, which includes commingled investment funds, and
10 percent to 30 percent debt securities and cash
management.
The assets are invested in accordance with the target
allocations identified previously. Additional target allocation
ranges are identified for U.S. equities and
non-U.S. equities.
The target allocation ranges at December 31, 2009, were a
minimum of 45 percent and a maximum of 70 percent for
U.S. equities and a minimum of 20 percent and a
maximum of 45 percent for
non-U.S. equities.
The asset allocation ranges established by the investment policy
are based upon a long-term investment perspective. The ranges
are weighted toward equity securities since the liabilities of
the pension and other postretirement benefit plans are long-term
in nature and historically equity securities have outperformed
other asset classes over long periods of time.
Equity security investments are restricted to high-quality,
readily marketable securities that are actively traded on the
major U.S. and foreign national exchanges. Investment in
Williams’ securities or an entity in which Williams has a
majority ownership is prohibited in the pension plans except
where these securities may be owned in a commingled investment
fund in which the plans’ trusts invest. No more than
5 percent of the total stock portfolio valued at market may
be invested in the common stock of any one corporation. No more
than 25 percent of stock valued at market may be held in
any one industry category. No more than 10 percent of the
total capitalization of any one issuer shall be held in the
total stock portfolio. The following securities and transactions
are not authorized: unregistered securities, commodities or
commodity contracts, short sales or margin transactions, or
other leveraging strategies. Investment strategies using the
direct holding of options or futures require approval and,
historically, have not been used; however, these instruments may
be used in commingled investment funds.
Fixed income securities are restricted to high-quality,
marketable securities that include U.S. Treasuries,
U.S. government guaranteed and nonguaranteed
mortgage-backed securities, government and municipal bonds, and
investment grade corporate issues. The overall rating of the
debt security assets is required to be at least “A,”
according to the Moody’s or Standard &
Poor’s rating systems. No more than 5 percent of the
total portfolio at the time of purchase may be invested in the
debt securities of any one issuer with the exception of
U.S. government guaranteed and agency securities.
During 2009, ten active investment managers and one passive
investment manager managed substantially all of the pension
plans’ funds and five active investment managers managed
the other postretirement benefit plans’ funds. Each of the
managers had responsibility for managing a specific portion of
these assets and each investment manager was responsible for
2 percent to 17 percent of the assets.
We believe the pension and other postretirement benefit plans
have no significant concentrations of risk because of the
diversity of the types of investments, diversity of the various
industries, and the diversity of the fund
111
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
managers and investment strategies. Generally, the investments
in the plan are publicly traded, therefore, minimizing liquidity
risk in the portfolio.
The pension and other postretirement benefit plans participate
in securities lending programs under which securities are loaned
to selected securities brokerage firms. The title of the
securities is transferred to the borrower, but the plans are
entitled to all distributions made by the issuer of the
securities during the term of the loan and retain the right to
redeem the securities on short notice. All loans require
collateralization by U.S. government securities, cash, or
letters of credit that equal at least 102 percent of the
fair value of the loaned securities plus accrued interest. There
are limitations on the aggregate fair value of securities that
may be loaned to any one broker and to all brokers as a group.
The collateral is invested in repurchase agreements,
asset-backed securities, bank notes, corporate floating rate
notes, and certificates of deposit. At December 31, 2009,
the fair values of the loaned securities are $63 million
for the pension plans and $9 million for the other
postretirement benefit plans and are included in the following
tables. At December 31, 2009, the fair values of securities
held as collateral, and the obligation to return the collateral,
are $66 million for the pension plans and $9 million
for the other postretirement benefit plans and are not included
in the following tables.
The fair values (see Note 14) of our pension plan
assets at December 31, 2009, by asset category are as
follows:
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions) | ||||||||||||||||
|
Pension assets:
|
||||||||||||||||
|
Cash management fund(1)
|
$ | 23 | $ | — | $ | — | $ | 23 | ||||||||
|
Equity securities:
|
||||||||||||||||
|
U.S. large cap
|
244 | — | — | 244 | ||||||||||||
|
U.S. small cap
|
103 | — | — | 103 | ||||||||||||
|
International developed markets large cap growth
|
2 | 58 | — | 60 | ||||||||||||
|
Emerging markets growth
|
10 | 9 | — | 19 | ||||||||||||
|
Commingled investment funds:
|
||||||||||||||||
|
U.S. large cap(2)
|
— | 84 | — | 84 | ||||||||||||
|
Emerging markets value(3)
|
— | 29 | — | 29 | ||||||||||||
|
International developed markets large cap value(4)
|
— | 74 | — | 74 | ||||||||||||
|
Fixed income securities(5):
|
||||||||||||||||
|
U.S. treasuries
|
11 | 3 | — | 14 | ||||||||||||
|
Mortgage-backed securities
|
— | 53 | — | 53 | ||||||||||||
|
Corporate bonds
|
— | 149 | — | 149 | ||||||||||||
|
Insurance company investment contracts and other
|
— | 8 | — | 8 | ||||||||||||
|
Total assets at fair value
|
$ | 393 | $ | 467 | $ | — | $ | 860 | ||||||||
112
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The fair values of our other postretirement benefits plan assets
at December 31, 2009, by asset category are as follows:
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions) | ||||||||||||||||
|
Other postretirement benefit assets:
|
||||||||||||||||
|
Cash management funds(1)
|
$ | 15 | $ | — | $ | — | $ | 15 | ||||||||
|
Equity securities:
|
||||||||||||||||
|
U.S. large cap
|
49 | — | — | 49 | ||||||||||||
|
U.S. small cap
|
19 | — | — | 19 | ||||||||||||
|
International developed markets large cap growth
|
— | 13 | — | 13 | ||||||||||||
|
Emerging markets growth
|
2 | 2 | — | 4 | ||||||||||||
|
Commingled investment funds:
|
||||||||||||||||
|
U.S. large cap(2)
|
— | 8 | — | 8 | ||||||||||||
|
Emerging markets value(3)
|
— | 3 | — | 3 | ||||||||||||
|
International developed markets large cap value(4)
|
— | 7 | — | 7 | ||||||||||||
|
Fixed income securities(6):
|
||||||||||||||||
|
U.S. treasuries
|
1 | — | — | 1 | ||||||||||||
|
Government and municipal bonds
|
— | 8 | — | 8 | ||||||||||||
|
Mortgage-backed securities
|
— | 6 | — | 6 | ||||||||||||
|
Corporate bonds
|
— | 15 | — | 15 | ||||||||||||
|
Total assets at fair value
|
$ | 86 | $ | 62 | $ | — | $ | 148 | ||||||||
| (1) | These funds invest in high credit-quality, short-term corporate, and government money market debt securities that have remaining maturities of approximately one year or less, and are deemed to have minimal credit risk. | |
| (2) | This fund invests primarily in equity securities comprising the Standard & Poor’s 500 Index. The investment objective of the fund is to match the return of the Standard & Poor’s 500 Index. There are certain restrictions that limit the amount that can be withdrawn from the fund to 4 percent per month of the plans’ total net asset value in the fund. If the plans do not withdraw the percentage allowed in a month, the plans accumulate the right to redeem the percentage not withdrawn in future months. As of December 31, 2009, 37 percent was eligible for withdrawal. | |
| (3) | This fund invests in equity securities of international emerging markets for the purpose of capital appreciation. The fund invests primarily in common stocks of the financial, telecommunications, consumer goods, energy, industrial, materials, and utilities sectors, as well as forward foreign currency exchange contracts. | |
| (4) | This fund invests in a diversified portfolio of international equity securities for the purpose of capital appreciation. The fund invests primarily in common stock of the consumer goods, materials, financial, energy, information technology, telecommunications, industrial, utilities, and health care sectors, as well as forward foreign currency exchange contracts. | |
| (5) | The weighted-average credit quality rating of the pension assets fixed income security portfolio is investment grade with a weighted-average duration of 5.1 years. | |
| (6) | The weighted-average credit quality rating of the other postretirement benefit assets fixed income security portfolio is investment grade with a weighted-average duration of 4.5 years. |
The asset’s fair value measurement level within the fair
value hierarchy is based on the lowest level of any input that
is significant to the fair value measurement.
113
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Shares of the cash management funds are valued at fair value
based on published market prices as of the close of business on
the last business day of the year, which represents the net
asset values of the shares held.
The fair values of equity securities traded on
U.S. exchanges are derived from quoted market prices as of
the close of business on the last business day of the year. The
fair values of equity securities traded on foreign exchanges are
also derived from quoted market prices as of the close of
business on an active foreign exchange on the last business day
of the year. However, the valuation requires translation of the
foreign currency to U.S. dollars and this translation is
considered an observable input to the valuation.
The fair value of all commingled investment funds has been
estimated based on the net asset values per unit of each of the
funds. The net asset values per unit of the fund represent the
aggregate value of the fund’s assets less liabilities,
divided by the number of units outstanding. Common stocks traded
in active markets comprise the majority of each commingled
investment fund’s assets. The fair value of these common
stocks is derived from quoted market prices as of the close of
business on the last business day of the year.
The fair value of fixed income securities, except
U.S. treasury notes and bonds, are determined using pricing
models. These pricing models incorporate observable inputs such
as benchmark yields, reported trades, broker/dealer quotes, and
issuer spreads for similar securities to determine fair value.
The treasury notes and bonds are valued at fair value based on
closing prices on the last business day of the year reported in
the active market in which the security is traded.
The investment contracts with insurance companies are valued at
fair value by discounting the cash flow of a bond using a yield
to maturity based on an investment grade index or comparable
index with a similar maturity value, maturity period, and
nominal coupon rate.
The following table presents the weighted-average asset
allocations at December 31, 2008, by asset category.
|
Other
|
||||||||
|
Pension
|
Postretirement
|
|||||||
| Benefits | Benefits | |||||||
|
Equity securities
|
78 | % | 71 | % | ||||
|
Debt securities
|
17 | 17 | ||||||
|
Other
|
5 | 12 | ||||||
| 100 | % | 100 | % | |||||
Equity securities include investments in commingled investment
funds that invest entirely in equity securities and comprise
24 percent of the pension plans’ weighted-average
assets and 13 percent of the other postretirement benefit
plans’ weighted-average assets at December 31, 2008.
Plan
Benefit Payments and Employer Contributions
Following are the expected benefits to be paid by the plans and
the expected federal prescription drug subsidy to be received in
the next ten years. These estimates are based on the same
assumptions previously discussed and reflect future service as
appropriate. The actuarial assumptions are based on long-term
expectations and include, but are not limited to, assumptions as
to average expected retirement age and form of benefit payment.
Actual benefit
114
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
payments could differ significantly from expected benefit
payments if near-term participant behaviors differ significantly
from the actuarial assumptions.
|
Federal
|
||||||||||||
|
Other
|
Prescription
|
|||||||||||
|
Pension
|
Postretirement
|
Drug
|
||||||||||
| Benefits | Benefits | Subsidy | ||||||||||
| (Millions) | ||||||||||||
|
2010
|
$ | 44 | $ | 18 | $ | (2 | ) | |||||
|
2011
|
44 | 18 | (3 | ) | ||||||||
|
2012
|
51 | 18 | (3 | ) | ||||||||
|
2013
|
52 | 18 | (3 | ) | ||||||||
|
2014
|
66 | 18 | (3 | ) | ||||||||
|
2015-2019
|
466 | 99 | (19 | ) | ||||||||
In 2010, we expect to contribute approximately $60 million
to our tax-qualified pension plans and approximately
$1 million to our nonqualified pension plans, for a total
of approximately $61 million, and approximately
$16 million to our other postretirement benefit plans.
Defined
Contribution Plans
We also maintain defined contribution plans for the benefit of
substantially all of our employees. Generally, plan participants
may contribute a portion of their compensation on a pre-tax and
after-tax basis in accordance with the plans’ guidelines.
We match employees’ contributions up to certain limits. Our
matching contributions charged to expense were $25 million
in 2009, $24 million in 2008, and $22 million in 2007.
A fund within one of our defined contribution plans is a
nonleveraged employee stock ownership plan (ESOP). The shares
held by the ESOP are treated as outstanding when computing
earnings per share and the dividends on the shares held by the
ESOP are recorded as a component of retained earnings. There
were no contributions in 2009, 2008, and 2007 to this ESOP,
other than dividend reinvestment, as contributions for purchase
of our stock are no longer allowed within this defined
contribution plan.
| Note 8. | Inventories |
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Natural gas liquids and olefins
|
$ | 70 | $ | 56 | ||||
|
Natural gas in underground storage
|
47 | 97 | ||||||
|
Materials, supplies and other
|
105 | 107 | ||||||
| $ | 222 | $ | 260 | |||||
Inventories
are primarily determined using the
average-cost method.
115
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 9. | Property, Plant and Equipment |
|
Estimated
|
Depreciation
|
|||||||||||||||
|
Useful Life (a)
|
Rates (a)
|
December 31, | ||||||||||||||
| (Years) | (%) | 2009 | 2008 | |||||||||||||
| (Millions) | ||||||||||||||||
|
Nonregulated:
|
||||||||||||||||
|
Oil and gas properties
|
(b) | $ | 9,854 | $ | 8,507 | |||||||||||
|
Natural gas gathering and processing facilities
|
5 - 40 | 5,461 | 4,823 | |||||||||||||
|
Construction in progress
|
(c) | 1,227 | 1,411 | |||||||||||||
|
Other
|
2 - 45 | 816 | 765 | |||||||||||||
|
Regulated:
|
||||||||||||||||
|
Natural gas transmission facilities
|
.01 - 7.25 | 8,814 | 8,441 | |||||||||||||
|
Construction in progress
|
(c) | 152 | 120 | |||||||||||||
|
Other
|
.01 - 50 | 1,301 | 1,293 | |||||||||||||
|
Total property, plant and equipment, at cost
|
27,625 | 25,360 | ||||||||||||||
|
Accumulated depreciation, depletion & amortization
|
(8,981 | ) | (7,619 | ) | ||||||||||||
|
Property, plant and equipment — net
|
$ | 18,644 | $ | 17,741 | ||||||||||||
| (a) | Estimated useful life and depreciation rates are presented as of December 31, 2009. Depreciation rates for regulated assets are prescribed by the FERC. | |
| (b) | Oil and gas properties are depleted using the units-of-production method. See Note 1 of Notes to Consolidated Financial Statements for more information. Balances include $704 million at December 31, 2009, and $571 million at December 31, 2008, of capitalized costs related to properties with unproved reserves not yet subject to depletion at Exploration & Production. | |
| (c) | Construction in progress balances not yet subject to depreciation and depletion. |
Depreciation, depletion and amortization
expense for
property, plant and equipment — net
was
$1.5 billion in 2009, $1.3 billion in 2008, and
$1.0 billion in 2007. Our fourth-quarter depletion includes
an unfavorable adjustment of $17 million. This adjustment
was primarily the result of new oil and gas accounting guidance
(Accounting Standards Update
2010-03)
that requires we value our reserves using an average price. This
price is calculated using prices at the beginning of the month
for the preceding 12 months. This accounting guidance has
been adopted on a prospective basis beginning in the fourth
quarter of 2009.
Regulated
property, plant and equipment — net
includes $946 million and $985 million at
December 31, 2009 and 2008, respectively, related to
amounts in excess of the original cost of the regulated
facilities within Gas Pipeline as a result of our prior
acquisitions. This amount is being amortized over 40 years
using the straight-line amortization method. Current FERC policy
does not permit recovery through rates for amounts in excess of
original cost of construction.
Asset
Retirement Obligations
Our accrued obligations relate to producing wells, underground
storage caverns, offshore platforms, fractionation facilities,
gas gathering well connections and pipelines, and gas
transmission facilities. At the end of the useful life of each
respective asset, we are legally obligated to plug both
producing wells and storage caverns and remove any related
surface equipment, to restore land and remove surface equipment
at fractionation facilities, to dismantle offshore platforms, to
cap certain gathering pipelines at the wellhead connection and
remove any related surface equipment, and to remove certain
components of gas transmission facilities from the ground.
116
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table presents the significant changes to our
asset retirement obligations, of which $716 million and
$630 million are included in
other liabilities and
deferred income
, with the remaining current portion in
accrued liabilities
at December 31, 2009 and 2008,
respectively.
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Beginning balance
|
$ | 644 | $ | 399 | ||||
|
Liabilities settled
|
(13 | ) | (11 | ) | ||||
|
Additions
|
32 | 59 | ||||||
|
Accretion expense
|
51 | 64 | ||||||
|
Revisions
|
14 | 133 | ||||||
| $ | 728 | $ | 644 | |||||
Pursuant to its 2008 rate case settlement, Transco deposits a
portion of its collected rates into an external trust (ARO
Trust) that is specifically designated to fund future asset
retirement obligations. Transco is also required to make annual
deposits into the trust through 2012. The trust is reported as a
component of
other assets and deferred charges
and has a
carrying value of $22 million and $13 million as of
December 31, 2009 and 2008, respectively.
Property
Insurance Changes
As a result of damage caused by recent hurricanes, the
availability of named windstorm insurance has been significantly
reduced. Additionally, named windstorm insurance coverage that
is available for offshore assets comes at significantly higher
premium amounts, higher deductibles and lower coverage limits.
Considering these changes, we have reduced the overall named
windstorm property insurance coverage for our assets in the Gulf
of Mexico area beginning in the second quarter of 2009. In
addition, certain assets are no longer covered for named
windstorm losses, primarily certain offshore lateral pipelines.
| Note 10. | Accounts Payable and Accrued Liabilities |
Under our cash-management system, certain cash accounts
reflected negative balances to the extent checks written have
not been presented for payment. These negative balances
represent obligations and have been reclassified to
accounts
payable. Accounts payable
includes $44 million of these
negative balances at December 31, 2009 and $95 million
at December 31, 2008.
Accrued
Liabilities
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Interest on debt
|
$ | 199 | $ | 179 | ||||
|
Taxes other than income taxes
|
176 | 221 | ||||||
|
Employee costs
|
158 | 167 | ||||||
|
Income taxes
|
112 | 144 | ||||||
|
Other, including other loss contingencies
|
303 | 428 | ||||||
| $ | 948 | $ | 1,139 | |||||
117
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 11. | Debt, Leases and Banking Arrangements |
In February 2010, we completed a strategic restructuring that
impacted our long-term debt and credit facilities. See
Note 19 for further discussion.
|
Weighted-
|
||||||||||||
|
Average
|
||||||||||||
|
Interest
|
December 31, | |||||||||||
| Rate(1) | 2009(2) | 2008(2) | ||||||||||
| (Millions) | ||||||||||||
|
Secured
|
||||||||||||
|
Capital lease obligations
|
9.5 | % | $ | 3 | $ | 5 | ||||||
|
Unsecured
|
||||||||||||
|
5.5% to 10.25%, payable through 2033
|
7.7 | % | 8,023 | 7,446 | ||||||||
|
Adjustable rate, payable through 2012
|
1.2 | % | 250 | 250 | ||||||||
|
Total long-term debt, including current portion
|
8,276 | 7,701 | ||||||||||
|
Long-term debt due within one year
|
(17 | ) | (18 | ) | ||||||||
|
Long-term debt
|
$ | 8,259 | $ | 7,683 | ||||||||
| (1) | At December 31, 2009. | |
| (2) | Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, repurchase equity, and incur additional debt. |
Revolving
Credit and Letter of Credit Facilities (Credit
Facilities)
At December 31, 2009, we have an unsecured,
$1.5 billion credit facility with a maturity date of
May 1, 2012. Northwest Pipeline and Transco each have
access to $400 million under the credit facility to the
extent not otherwise utilized by us. We expect that our ability
to borrow under the credit facility is reduced by
$70 million due to the bankruptcy of a participating bank.
Interest is calculated based on a choice of two methods: a
fluctuating rate equal to the lender’s base rate plus an
applicable margin, or a periodic fixed rate equal to LIBOR plus
an applicable margin. We are required to pay a commitment fee
(currently 0.125 percent) based on the unused portion of
the credit facility. The margins and commitment fee are
generally based on the specific borrower’s senior unsecured
long-term debt ratings. Significant financial covenants under
the credit agreement include the following:
| • | Our ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2009, we are in compliance with this covenant. | |
| • | Ratio of debt to capitalization must be no greater than 55 percent for Northwest Pipeline and Transco. At December 31, 2009, they are in compliance with this covenant. |
We have unsecured credit facilities totaling $700 million,
which mature in October 2010. These credit facilities provide
for both borrowings and issuing letters of credit but are
expected to be used primarily for issuing letters of credit. We
are required to pay the funding bank fixed fees at a
weighted-average interest rate of 2.29 percent on the total
committed amount and interest on any borrowings at a fluctuating
rate comprised of either a base rate or LIBOR.
The funding bank, an affiliate of Citibank N.A., syndicated its
associated credit risk through a private offering that allows
for the resale of certain restricted securities to qualified
institutional buyers. To facilitate the syndication of these
credit facilities, the bank established a trust funded by the
institutional investors. The assets of the trust
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
serve as collateral to reimburse the bank for our borrowings in
the event that the credit facilities are delivered to the
investors as described below. Thus, we have no asset
securitization or collateral requirements under the credit
facilities. Upon the occurrence of certain credit events,
letters of credit under the agreement become cash collateralized
creating a borrowing under the credit facilities. Concurrently,
the funding bank can deliver the credit facilities to the
institutional investors, whereby the investors replace the
funding bank as lender under the credit facilities. Upon such
occurrence, we will pay:
| $700 Million Facilities | ||||||||
| $500 million | $200 million | |||||||
|
Interest Rate
|
4.35 percent | LIBOR | ||||||
|
Facility Fixed Fee
|
2.29 percent | |||||||
In second-quarter 2009, two of our unsecured revolving credit
facilities totaling $500 million expired and were not
renewed. These facilities were originated primarily in support
of our former power business.
At December 31, 2009, WPZ has an unsecured
$450 million credit agreement with a maturity date of
December 2012. This $450 million credit facility is
comprised initially of a $200 million revolving credit
facility available for borrowings and letters of credit and a
$250 million term loan. WPZ expects that its ability to
borrow under this credit facility is reduced by $12 million
due to the bankruptcy of a participating bank. Interest on
borrowings under this agreement will be payable at rates per
annum equal to either (1) a fluctuating base rate equal to
the lender’s prime rate plus the applicable margin, or
(2) a periodic fixed rate equal to LIBOR plus the
applicable margin. At December 31, 2009, WPZ had a
$250 million term loan outstanding and no amounts
outstanding under the $200 million credit facility.
Significant financial covenants under this credit agreement
include the following:
| • | Williams Partners L.P. is required to maintain a ratio of indebtedness to EBITDA (each as defined in the credit agreement) of no greater than 5.0 to 1.0. At December 31, 2009, they are in compliance with this covenant. | |
| • | Williams Partners L.P. is required to maintain a ratio of EBITDA to interest expense (as defined in the credit agreement) of not less than 2.75 to 1.0 as of the last day of any fiscal quarter. At December 31, 2009, they are in compliance with this covenant. |
At December 31, 2009, no loans are outstanding under our
credit facilities. Letters of credit issued under our credit
facilities are:
|
Credit Facilities
|
Letters of Credit at
|
|||||
| Expiration | December 31, 2009 | |||||
| (Millions) | ||||||
|
$700 million unsecured credit facilities
|
October 2010 | $ | 220 | |||
|
$1.5 billion unsecured credit facility
|
May 2012 | — | ||||
|
$200 million Williams Partners L.P. unsecured credit
facility
|
December 2012 | — | ||||
| $ | 220 | |||||
Exploration &
Production’s Credit Agreement
Exploration & Production has an unsecured credit
agreement with certain banks in order to reduce margin
requirements related to our hedging activities as well as lower
transaction fees. The agreement extends through December 2013.
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.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Issuances
On March 5, 2009, we issued $600 million aggregate
principal amount of 8.75 percent senior unsecured notes due
2020 to certain institutional investors in a private debt
placement. In August 2009, we completed an exchange of these
notes for substantially identical new notes that are registered
under the Securities Act of 1933, as amended.
Aggregate minimum maturities of
long-term debt
(excluding
capital leases and unamortized discount and premium) for each of
the next five years are as follows:
| (Millions) | ||||
|
2010
|
$ | 15 | ||
|
2011
|
936 | |||
|
2012
|
1,203 | |||
|
2013
|
— | |||
|
2014
|
— | |||
Cash payments for interest (net of amounts capitalized),
including amounts related to discontinued operations, were as
follows: 2009 — $592 million; 2008 —
$592 million; and 2007 — $634 million.
Leases-Lessee
Future minimum annual rentals under noncancelable operating
leases as of December 31, 2009, are payable as follows:
| (Millions) | ||||
|
2010
|
$ | 48 | ||
|
2011
|
33 | |||
|
2012
|
31 | |||
|
2013
|
27 | |||
|
2014
|
18 | |||
|
Thereafter
|
137 | |||
|
Total
|
$ | 294 | ||
Total rent expense was $70 million in 2009,
$87 million in 2008 and $68 million in 2007. Rent
expense reported in 2007 as discontinued operations, primarily
related to a tolling agreement, was $148 million and was
offset by approximately $276 million resulting from sales
and other transactions made possible by the tolling agreement.
This tolling agreement was included in the sale of our power
business in 2007. (See Note 2.)
| Note 12. | Stockholders’ Equity |
In July 2007, our Board of Directors authorized the repurchase
of up to $1 billion of our common stock. During 2007, we
purchased 16 million shares for $526 million
(including transaction costs) at an average cost of $33.08 per
share. During 2008, we purchased 13 million shares of our
common stock for $474 million (including transaction costs)
at an average cost of $36.76 per share. We completed our
$1 billion stock repurchase program in July 2008. Our
overall average cost per share was $34.74. This stock repurchase
is recorded in
treasury stock
on our Consolidated Balance
Sheet.
At December 31, 2009, approximately $25 million of our
original $300 million, 5.5 percent junior subordinated
convertible debentures, convertible into approximately
2 million shares of common stock, remain outstanding. In
2009 and 2008, we converted $28 million and
$27 million, respectively, of the debentures in exchange
for 3 million and 2 million shares, respectively, of
common stock.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At December 31, 2007, we held all of Williams Partners
L.P.’s seven million subordinated units outstanding. In
February 2008, these subordinated units were converted into
common units of Williams Partners L.P. due to the achievement of
certain financial targets that resulted in the early termination
of the subordination period. While these subordinated units were
outstanding, other issuances of partnership units by Williams
Partners L.P. had preferential rights and the proceeds from
these issuances in excess of the book basis of assets acquired
by Williams Partners L.P. were therefore reflected as
noncontrolling interests in consolidated subsidiaries
on
our Consolidated Balance Sheet. Due to the conversion of the
subordinated units, these original issuances of partnership
units no longer have preferential rights and now represent the
lowest level of equity securities issued by Williams Partners
L.P. In accordance with our policy regarding the issuance of
equity of a consolidated subsidiary, such issuances of
nonpreferential equity are accounted for as capital transactions
and no gain or loss is recognized. Therefore, as a result of the
2008 conversion, we recognized a decrease to
noncontrolling
interests in consolidated subsidiaries
and a corresponding
increase to
capital in excess of par value
of
approximately $1.2 billion.
We maintain a Stockholder Rights Plan, as amended and restated
on September 21, 2004, and further amended May 18,
2007, and October 12, 2007, under which each outstanding
share of our common stock has a right (as defined in the plan)
attached. Under certain conditions, each right may be exercised
to purchase, at an exercise price of $50 (subject to
adjustment), one two-hundredth of a share of Series A
Junior Participating Preferred Stock. The rights may be
exercised only if an Acquiring Person acquires (or obtains the
right to acquire) 15 percent or more of our common stock or
commences an offer for 15 percent or more of our common
stock. The plan contains a mechanism to divest of shares of
common stock if such stock in excess of 14.9 percent was
acquired inadvertently or without knowledge of the terms of the
rights. The rights, which until exercised do not have voting
rights, expire in 2014 and may be redeemed at a price of $.01
per right prior to their expiration, or within a specified
period of time after the occurrence of certain events. In the
event a person becomes the owner of more than 15 percent of
our common stock, each holder of a right (except an Acquiring
Person) shall have the right to receive, upon exercise, our
common stock having a value equal to two times the exercise
price of the right. In the event we are engaged in a merger,
business combination, or 50 percent or more of our assets,
cash flow or earnings power is sold or transferred, each holder
of a right (except an Acquiring Person) shall have the right to
receive, upon exercise, common stock of the acquiring company
having a value equal to two times the exercise price of the
right.
| Note 13. | Stock-Based Compensation |
Plan
Information
On May 17, 2007, our stockholders approved a plan that
provides common-stock-based awards to both employees and
nonmanagement directors. The plan generally contains terms and
provisions consistent with the previous plans. The plan permits
the granting of various types of awards including, but not
limited to, restricted stock units and stock options and
reserves 19 million shares for issuance. At
December 31, 2009, 30 million shares of our common
stock were reserved for issuance pursuant to existing and future
stock awards, of which 11 million shares were available for
future grants. At December 31, 2008, 33 million shares
of our common stock were reserved for issuance pursuant to
existing and future stock awards, of which 16 million
shares were available for future grants.
Additionally, on May 17, 2007, our stockholders approved an
Employee Stock Purchase Plan (ESPP) which authorizes up to
2 million shares of our common stock to be available for
sale under the plan. The ESPP enables eligible participants to
purchase our common stock through payroll deductions not
exceeding an annual amount of $15,000 per participant. The ESPP
provides for offering periods during which shares may be
purchased and continues until the earliest of: (1) the
Board of Directors terminates the ESPP, (2) the sale of all
shares available under the ESPP, or (3) the tenth
anniversary of the date the Plan was approved by the
stockholders. The first offering under the ESPP commenced on
October 1, 2007 and ended on December 31, 2007.
Subsequent offering periods are from January through June and
from July through December. Generally, all employees are
eligible to participate in the ESPP, with the exception of
executives and international employees. The number of shares
eligible for an
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
employee to purchase during each offering period is limited to
750 shares. The purchase price of the stock is
85 percent of the lower closing price of either the first
or the last day of the offering period. The ESPP requires a
one-year holding period before the stock can be sold. Employees
purchased 370 thousand shares at an average price of $13.01 per
share during 2009. Approximately 1.3 million and
1.7 million shares were available for purchase under the
ESPP at December 31, 2009 and 2008, respectively.
Stock
Options
Stock options are valued at the date of award, which does not
precede the approval date, and compensation cost is recognized
on a straight-line basis, net of estimated forfeitures, over the
requisite service period. The purchase price per share for stock
options may not be less than the market price of the underlying
stock on the date of grant. Stock options generally become
exercisable over a three-year period from the date of grant and
can be subject to accelerated vesting if certain future stock
prices or specific financial performance targets are achieved.
Stock options generally expire ten years after the grant.
The following summary reflects stock option activity and related
information for the year ending December 31, 2009.
|
Weighted-
|
||||||||||||
|
Average
|
Aggregate
|
|||||||||||
|
Exercise
|
Intrinsic
|
|||||||||||
|
Stock Options
|
Options | Price | Value | |||||||||
| (Millions) | (Millions) | |||||||||||
|
Outstanding at December 31, 2008
|
11.5 | $ | 18.10 | |||||||||
|
Granted
|
2.1 | $ | 10.86 | |||||||||
|
Exercised
|
(0.2 | ) | $ | 8.46 | $ | 2 | ||||||
|
Expired
|
(0.3 | ) | $ | 33.27 | ||||||||
|
Forfeited
|
(0.1 | ) | $ | 22.73 | ||||||||
|
Outstanding at December 31, 2009
|
13.0 | $ | 16.73 | $ | 90 | |||||||
|
Exercisable at December 31, 2009
|
10.0 | $ | 16.32 | $ | 69 | |||||||
The total intrinsic value of options exercised during the years
ended December 31, 2009, 2008, and 2007 was
$2 million, $49 million, and $74 million,
respectively.
The following summary provides additional information about
stock options that are outstanding and exercisable at
December 31, 2009.
| Stock Options Outstanding | Stock Options Exercisable | |||||||||||||||||||||||
|
Weighted-
|
Weighted-
|
|||||||||||||||||||||||
|
Weighted-
|
Average
|
Weighted-
|
Average
|
|||||||||||||||||||||
|
Average
|
Remaining
|
Average
|
Remaining
|
|||||||||||||||||||||
|
Exercise
|
Contractual
|
Exercise
|
Contractual
|
|||||||||||||||||||||
|
Range of Exercise Prices
|
Options | Price | Life | Options | Price | Life | ||||||||||||||||||
| (Millions) | (Years) | (Millions) | (Years) | |||||||||||||||||||||
|
$2.27 to $12.27
|
6.5 | $ | 8.24 | 5.1 | 4.5 | $ | 7.05 | 3.2 | ||||||||||||||||
|
$12.28 to $22.27
|
3.8 | $ | 19.50 | 4.9 | 3.7 | $ | 19.50 | 4.9 | ||||||||||||||||
|
$22.28 to $32.28
|
1.1 | $ | 28.04 | 6.5 | 0.8 | $ | 27.93 | 6.3 | ||||||||||||||||
|
$32.29 to $42.29
|
1.6 | $ | 37.17 | 5.1 | 1.0 | $ | 37.61 | 3.1 | ||||||||||||||||
|
Total
|
13.0 | $ | 16.73 | 5.2 | 10.0 | $ | 16.32 | 4.1 | ||||||||||||||||
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The estimated fair value at date of grant of options for our
common stock granted in 2009, 2008, and 2007, using the
Black-Scholes option pricing model, is as follows:
| 2009 | 2008 | 2007 | ||||||||||
|
Weighted-average grant date fair value of options for our common
stock granted during the year
|
$ | 5.60 | $ | 12.83 | $ | 9.09 | ||||||
|
Weighted-average assumptions:
|
||||||||||||
|
Dividend yield
|
1.6 | % | 1.2 | % | 1.5 | % | ||||||
|
Volatility
|
60.8 | % | 33.4 | % | 28.7 | % | ||||||
|
Risk-free interest rate
|
2.3 | % | 3.5 | % | 4.6 | % | ||||||
|
Expected life (years)
|
6.5 | 6.5 | 6.3 | |||||||||
The expected dividend yield is based on the average annual
dividend yield as of the grant date. Expected volatility is
based on the historical volatility of our stock and the implied
volatility of our stock based on traded options. In calculating
historical volatility, returns during calendar year 2002 were
excluded as the extreme volatility during that time is not
reasonably expected to be repeated in the future. The risk-free
interest rate is based on the U.S. Treasury Constant
Maturity rates as of the grant date. The expected life of the
option is based on historical exercise behavior and expected
future experience.
Cash received from stock option exercises was $2 million,
$32 million, and $56 million during 2009, 2008, and
2007, respectively; and the tax benefit realized was
$1 million, $17 million, and $27 million,
respectively.
Nonvested
Restricted Stock Units
Restricted stock units are generally valued at market value on
the grant date and generally vest over three years. Restricted
stock unit expense, net of estimated forfeitures, is generally
recognized over the vesting period on a straight-line basis.
The following summary reflects nonvested restricted stock unit
activity and related information for the year ended
December 31, 2009.
|
Weighted-
|
||||||||
|
Average
|
||||||||
|
Restricted Stock Units
|
Shares | Fair Value* | ||||||
| (Millions) | ||||||||
|
Nonvested at December 31, 2008
|
4.4 | $ | 22.91 | |||||
|
Granted
|
3.4 | $ | 10.23 | |||||
|
Forfeited
|
(0.1 | ) | $ | 20.65 | ||||
|
Vested
|
(1.6 | ) | $ | 17.93 | ||||
|
Nonvested at December 31, 2009
|
6.1 | $ | 16.24 | |||||
| * | Performance-based shares are primarily valued using the end-of-period market price until certification that the performance objectives have been completed, a value of zero once it has been determined that it is unlikely that performance objectives will be met, or a valuation pricing model. All other shares are valued at the grant-date market price. |
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Other
restricted stock unit information
| 2009 | 2008 | 2007 | ||||||||||
|
Weighted-average grant date fair value of restricted stock units
granted during the year, per share
|
$ | 10.23 | $ | 30.13 | $ | 30.79 | ||||||
|
Total fair value of restricted stock units vested during the
year ($’s in millions)
|
$ | 28 | $ | 48 | $ | 33 | ||||||
Performance-based shares granted under the Plan represent
29 percent of nonvested restricted stock units outstanding
at December 31, 2009. These grants may be earned at the end
of a three-year period based on actual performance against a
performance target. Expense associated with these
performance-based grants is recognized in periods after
performance targets are established. Based on the extent to
which certain financial targets are achieved, vested shares may
range from zero percent to 200 percent of the original
grant amount.
| Note 14. | Fair Value Measurements |
Fair value is the amount received to sell an asset or the amount
paid to transfer a liability in an orderly transaction between
market participants (an exit price) at the measurement date.
Fair value is a market-based measurement considered from the
perspective of a market participant. We use market data or
assumptions that we believe market participants would use in
pricing the asset or liability, including assumptions about risk
and the risks inherent in the inputs to the valuation. These
inputs can be readily observable, market corroborated, or
unobservable. We apply both market and income approaches for
recurring fair value measurements using the best available
information while utilizing valuation techniques that maximize
the use of observable inputs and minimize the use of
unobservable inputs.
The fair value hierarchy prioritizes the inputs used to measure
fair value, giving the highest priority to quoted prices in
active markets for identical assets or liabilities (Level 1
measurement) and the lowest priority to unobservable inputs
(Level 3 measurement). We classify fair value balances
based on the observability of those inputs. The three levels of
the fair value hierarchy are as follows:
| • | Level 1 — Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange traded. | |
| • | Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 primarily consists of over-the-counter (OTC) instruments such as forwards, swaps, and options. These options, which hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Prior to the third quarter of 2009, these options were included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. However, due to the increased transparency, we now consider this input to be observable and have included these options in Level 2. | |
| • | Level 3 — Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. |
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In valuing certain contracts, the inputs used to measure fair
value may fall into different levels of the fair value
hierarchy. For disclosure purposes, assets and liabilities are
classified in their entirety in the fair value hierarchy level
based on the lowest level of input that is significant to the
overall fair value measurement. Our assessment of the
significance of a particular input to the fair value measurement
requires judgment and may affect the placement within the fair
value hierarchy levels.
The following table presents, by level within the fair value
hierarchy, our assets and liabilities that are measured at fair
value on a recurring basis.
Fair
Value Measurements Using:
| December 31, 2009 | December 31, 2008 | |||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
| (Millions) | (Millions) | |||||||||||||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||||||||||||||
|
Energy derivatives
|
$ | 178 | $ | 911 | $ | 5 | $ | 1,094 | $ | 680 | $ | 1,223 | $ | 547 | $ | 2,450 | ||||||||||||||||
|
Other assets
|
22 | — | — | 22 | 13 | — | 7 | 20 | ||||||||||||||||||||||||
|
Total assets
|
$ | 200 | $ | 911 | $ | 5 | $ | 1,116 | $ | 693 | $ | 1,223 | $ | 554 | $ | 2,470 | ||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||||||||||
|
Energy derivatives
|
$ | 177 | $ | 826 | $ | 3 | $ | 1,006 | $ | 615 | $ | 1,313 | $ | 40 | $ | 1,968 | ||||||||||||||||
|
Total liabilities
|
$ | 177 | $ | 826 | $ | 3 | $ | 1,006 | $ | 615 | $ | 1,313 | $ | 40 | $ | 1,968 | ||||||||||||||||
Energy derivatives include commodity based exchange-traded
contracts and OTC contracts. Exchange-traded contracts include
futures, swaps, and options. OTC contracts include forwards,
swaps and options.
Many contracts have bid and ask prices that can be observed in
the market. Our policy is to use a mid-market pricing (the
mid-point price between bid and ask prices) convention to value
individual positions and then adjust on a portfolio level to a
point within the bid and ask range that represents our best
estimate of fair value. For offsetting positions by location,
the mid-market price is used to measure both the long and short
positions.
The determination of fair value for our assets and liabilities
also incorporates the time value of money and various credit
risk factors which can include the credit standing of the
counterparties involved, master netting arrangements, the impact
of credit enhancements (such as cash collateral posted and
letters of credit) and our nonperformance risk on our
liabilities. The determination of the fair value of our
liabilities does not consider noncash collateral credit
enhancements.
Exchange-traded contracts include New York Mercantile Exchange
and Intercontinental Exchange contracts and are valued based on
quoted prices in these active markets and are classified within
Level 1.
Contracts for which fair value can be estimated from executed
transactions or broker quotes corroborated by other market data
are generally classified within Level 2. These broker
quotes are based on observable market prices at which
transactions could currently be executed. In certain instances
where these inputs are not observable for all periods,
relationships of observable market data and historical
observations are used as a means to estimate fair value. Where
observable inputs are available for substantially the full term
of the asset or liability, the instrument is categorized in
Level 2. Our derivatives portfolio is largely comprised of
exchange-traded products or like products and the tenure of our
derivatives portfolio is relatively short with more than
99 percent expiring in the next 36 months. Due to the
nature of the products and tenure, we are consistently able to
obtain market pricing. All pricing is reviewed on a daily basis
and is formally validated with broker quotes and documented on a
monthly basis.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Certain instruments trade in less active markets with lower
availability of pricing information requiring valuation models
using inputs that may not be readily observable or corroborated
by other market data. These instruments are classified within
Level 3 when these inputs have a significant impact on the
measurement of fair value. The instruments included in
Level 3 at December 31, 2009, consist of natural gas
liquids swaps for our Midstream segment as well as natural gas
index transactions that are used to manage the physical
requirements of our Exploration & Production and
Midstream segments.
The following tables present a reconciliation of changes in the
fair value of net derivatives and other assets classified as
Level 3 in the fair value hierarchy.
Level 3
Fair Value Measurements Using Significant Unobservable
Inputs
| Year Ended December 31, | ||||||||||||||||
| 2009 | 2008 | |||||||||||||||
|
Net
|
Other
|
Net
|
Other
|
|||||||||||||
| Derivatives | Assets | Derivatives | Assets | |||||||||||||
| (Millions) | ||||||||||||||||
|
Beginning balance
|
$ | 507 | $ | 7 | $ | (14 | ) | $ | 10 | |||||||
|
Realized and unrealized gains (losses):
|
||||||||||||||||
|
Included in
income from continuing operations
|
476 | — | 88 | (3 | ) | |||||||||||
|
Included in other comprehensive income (loss)
|
(331 | ) | — | 486 | — | |||||||||||
|
Purchases, issuances, and settlements
|
(477 | ) | (7 | ) | (51 | ) | — | |||||||||
|
Transfers into Level 3
|
— | — | 3 | — | ||||||||||||
|
Transfers out of Level 3
|
(173 | ) | — | (5 | ) | — | ||||||||||
|
Ending balance
|
$ | 2 | $ | — | $ | 507 | $ | 7 | ||||||||
|
Unrealized gains included in
income from continuing
operations
relating to instruments still held at December 31
|
$ | 2 | $ | — | $ | — | $ | — | ||||||||
Realized and unrealized gains (losses) included in
income
from continuing operations
for the above periods are
reported in
revenues
in our Consolidated Statement of
Income. Reclassification of fair value into and out of
Level 3 is made at the end of each quarter.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table presents, by level within the fair value of
hierarchy, certain assets that have been measured at fair value
on a nonrecurring basis, including certain items reported as
discontinued operations.
Fair
Value Measurements Using:
|
Total
|
||||||||||||||||
|
Losses For The
|
||||||||||||||||
| December 31, 2009 |
Year Ended
|
|||||||||||||||
| Level 1 | Level 2 | Level 3 | December 31, 2009 | |||||||||||||
| (Millions) | ||||||||||||||||
|
Impairments:
|
||||||||||||||||
|
Midstream Venezuelan property (see Note 2)
|
$ | — | $ | — | $ | (a | ) | $ | (211 | ) | ||||||
|
Midstream investment in Accroven (see Note 3)
|
— | — | (b | ) | (75 | ) | ||||||||||
|
Exploration & Production cost-based investment (see
Note 3)
|
— | — | (b | ) | (11 | ) | ||||||||||
|
Exploration & Production unproved properties (see
Note 4)
|
— | — | (c | ) | (15 | ) | ||||||||||
| $ | — | $ | — | $ | (312 | ) | ||||||||||
| (a) | Fair value measured at March 31, 2009, was $106 million. These assets were expropriated by the Venezuelan government during the second quarter of 2009 and the entities that previously owned these assets are no longer consolidated within our Midstream segment. We recorded our retained noncontrolling investment in these entities at zero and recognized a gain of $9 million on the deconsolidation. (See Note 2.) | |
| (b) | Fair value measured at March 31, 2009, was zero. | |
| (c) | Fair value measured at December 31, 2009, is $22 million. |
| Note 15. | Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk |
Financial
Instruments
Fair-value
methods
We use the following methods and assumptions in estimating our
fair-value disclosures for financial instruments:
Cash and cash equivalents and restricted
cash
: The carrying amounts reported in the
Consolidated Balance Sheet approximate fair value due to the
short-term maturity of these instruments. Current and noncurrent
restricted cash is included in
other current assets and
deferred charges
and
other assets and deferred
charges
, respectively, in the Consolidated Balance Sheet.
ARO Trust Investments
: Our
Transcontinental Gas Pipe Line Company, LLC (Transco) subsidiary
deposits a portion of its collected rates, pursuant to its 2008
rate case settlement, into an external trust specifically
designated to fund future asset retirement obligations (ARO
Trust). The ARO Trust invests in a portfolio of mutual funds
that are reported at fair value in
other assets and deferred
charges
in the Consolidated Balance Sheet and are classified
as
available-for-sale.
However, both realized and unrealized gains and losses are
ultimately recorded as regulatory assets or liabilities.
Long-term debt
: The fair value of our publicly
traded long-term debt is determined using indicative year-end
traded bond market prices. Private debt is valued based on
market rates and the prices of similar securities with similar
terms and credit ratings. At December 31, 2009 and 2008,
approximately 97 percent of our long-term debt was publicly
traded.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Guarantees
: The
guarantees
represented
in the following table consist primarily of guarantees we have
provided in the event of nonpayment by our previously owned
communications subsidiary, Williams Communications Group
(WilTel), on certain lease performance obligations. To estimate
the fair value of the guarantees, the estimated default rate is
determined by obtaining the average cumulative issuer-weighted
corporate default rate for each guarantee based on the credit
rating of WilTel’s current owner and the term of the
underlying obligation. The default rates are published by
Moody’s Investors Service. Guarantees, if recognized, are
included in
accrued liabilities
in the Consolidated
Balance Sheet.
Other
: Includes notes and other noncurrent
receivables, margin deposits, customer margin deposits payable,
cost-based investments and auction rate securities.
Energy derivatives
: Energy derivatives include
futures, forwards, swaps, and options. These are carried at fair
value in the Consolidated Balance Sheet. See Note 14 for
discussion of valuation of our energy derivatives.
Carrying
amounts and fair values of our financial instruments
| December 31, | ||||||||||||||||
| 2009 | 2008 | |||||||||||||||
|
Carrying
|
Carrying
|
|||||||||||||||
|
Asset (Liability)
|
Amount | Fair Value | Amount | Fair Value | ||||||||||||
| (Millions) | ||||||||||||||||
|
Cash and cash equivalents
|
$ | 1,867 | $ | 1,867 | $ | 1,438 | $ | 1,438 | ||||||||
|
Restricted cash (current and noncurrent)
|
28 | 28 | 37 | 37 | ||||||||||||
|
ARO Trust Investments
|
22 | 22 | 13 | 13 | ||||||||||||
|
Long-term debt, including current portion(a)
|
(8,273 | ) | (9,142 | ) | (7,696 | ) | (6,140 | ) | ||||||||
|
Guarantees
|
(36 | ) | (33 | ) | (38 | ) | (32 | ) | ||||||||
|
Other
|
(23 | ) | (25 | )(b) | 4 | (13 | )(b) | |||||||||
|
Net energy derivatives:
|
||||||||||||||||
|
Energy commodity cash flow hedges
|
178 | 178 | 458 | 458 | ||||||||||||
|
Other energy derivatives
|
(90 | ) | (90 | ) | 24 | 24 | ||||||||||
| (a) | Excludes capital leases. (See Note 11.) | |
| (b) | Excludes certain cost-based investments in companies that are not publicly traded and therefore it is not practicable to estimate fair value. The carrying value of these investments was $2 million and $17 million at December 31, 2009 and December 31, 2008, respectively. |
Energy
Commodity Derivatives
Risk
management activities
We are exposed to market risk from changes in energy commodity
prices within our operations. We manage this risk on an
enterprise basis and may utilize derivatives to manage our
exposure to the variability in expected future cash flows from
forecasted purchases and sales of natural gas and NGLs
attributable to commodity price risk. Certain of these
derivatives utilized for risk management purposes have been
designated as cash flow hedges, while other derivatives have not
been designated as cash flow hedges or do not qualify for hedge
accounting despite hedging our future cash flows on an economic
basis.
Exploration & Production produces, buys, and sells
natural gas at different locations throughout the United States.
To reduce exposure to a decrease in revenues from fluctuations
in natural gas market prices, we enter into natural gas futures
contracts, swap agreements, and financial option contracts to
mitigate the price risk on forecasted sales of natural gas. We
have also entered into basis swap agreements to reduce the
locational price risk associated with our producing basins.
Exploration & Production’s cash flow hedges are
expected to be highly
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
effective in offsetting cash flows attributable to the hedged
risk during the term of the hedge. However, ineffectiveness may
be recognized primarily as a result of locational differences
between the hedging derivative and the hedged item. Our
financial option contracts are either purchased options or a
combination of options that comprise a net purchased option or a
zero-cost collar. Our designation of the hedging relationship
and method of assessing effectiveness for these option contracts
are generally such that the hedging relationship is considered
perfectly effective and no ineffectiveness is recognized in
earnings.
Midstream produces and sells NGLs and olefins at different
locations throughout the United States. Midstream also buys
natural gas to satisfy the required fuel and shrink needed to
generate NGLs and olefins. To reduce exposure to a decrease in
revenues from fluctuations in NGL market prices or increases in
costs and operating expenses from fluctuations in natural gas
and NGL market prices, we may enter into NGL or natural gas swap
agreements, financial forward contracts, and financial option
contracts to mitigate the price risk on forecasted sales of NGLs
and purchases of natural gas and NGLs. Midstream’s cash
flow hedges are expected to be highly effective in offsetting
cash flows attributable to the hedged risk during the term of
the hedge. However, ineffectiveness may be recognized primarily
as a result of locational differences between the hedging
derivative and the hedged item.
Gas Marketing Services supports our natural gas business by
providing marketing and risk management services, which include
marketing the gas produced by Exploration & Production
and procuring fuel and shrink for Midstream. Gas Marketing
Services also enters into forward contracts to buy and sell
natural gas to maximize the economic value of transportation
agreements and storage capacity agreements. To reduce exposure
to a decrease in margins from fluctuations in natural gas market
prices, we may enter into futures contracts, swap agreements,
and financial option contracts to mitigate the price risk
associated with these contracts. Hedges for transportation
contracts are designated as cash flow hedges and are expected to
be highly effective in offsetting cash flows attributable to the
hedged risk during the term of the hedge. However,
ineffectiveness may be recognized primarily as a result of
locational differences between the hedging derivative and the
hedged item. Hedges for storage contracts have not been
designated as hedging instruments, despite economically hedging
the expected cash flows generated by those agreements.
Other
activities
Gas Marketing Services also enters into commodity derivatives
for other than risk management purposes, including managing
certain remaining legacy natural gas contracts and positions
from our former power business and providing services to third
parties. These legacy natural gas contracts include
substantially offsetting positions and have an insignificant net
impact on earnings.
Volumes
Our energy commodity derivatives are comprised of both contracts
to purchase the commodity (long positions) and contracts to sell
the commodity (short positions). Derivative transactions are
categorized into four types:
| • | Fixed price: Includes physical and financial derivative transactions that settle at a fixed location price; | |
| • | Basis: Includes financial derivative transactions priced off the difference in value between a commodity at two specific delivery points; | |
| • | Index: Includes physical derivative transactions at an unknown future price; | |
| • | Options: Includes all fixed price options or combination of options (collars) that set a floor and/or ceiling for the transaction price of a commodity. |
The following table depicts the notional amounts of the net long
(short) positions in our commodity derivatives portfolio as of
December 31, 2009. Natural gas is presented in millions of
British Thermal Units (MMBtu), and NGLs is presented in gallons.
The volumes presented for options that comprise zero-cost
collars represent one side
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
of the short position. While the index volumes are significant,
they represent less than 1 percent of the fair value of our
net derivative balance.
| Derivative Notional Volumes | Measurement | Fixed Price | Basis | Index | Options | |||||||||||||||||
|
Designated as Hedging Instruments
|
||||||||||||||||||||||
|
Exploration & Production
|
Risk Management | MMBtu | (60,125,000 | ) | (58,400,000 | ) | (286,525,000 | ) | ||||||||||||||
|
Gas Marketing Services
|
Risk Management | MMBtu | — | * | — | * | ||||||||||||||||
|
Midstream
|
Risk Management | MMBtu | 1,247,500 | 412,500 | ||||||||||||||||||
|
Midstream
|
Risk Management | Gallons | (30,240,000 | ) | ||||||||||||||||||
|
Not Designated as Hedging Instruments
|
||||||||||||||||||||||
|
Exploration & Production
|
Risk Management | MMBtu | (56,204,466 | ) | ||||||||||||||||||
|
Gas Marketing Services
|
Risk Management | MMBtu | (9,967,499 | ) | (7,805,000 | ) | ||||||||||||||||
|
Midstream
|
Risk Management | MMBtu | 835,000 | 64,418,920 | ||||||||||||||||||
|
Midstream
|
Risk Management | Gallons | (2,998,800 | ) | ||||||||||||||||||
|
Gas Marketing Services
|
Other | MMBtu | (851,850 | ) | (3,737,500 | ) | ||||||||||||||||
| * | Volumes related to offsetting positions net to zero. |
Fair
values and gains (losses)
The following table presents the fair value of energy commodity
derivatives. Our derivatives are presented as separate line
items in our Consolidated Balance Sheet as current and
noncurrent derivative assets and liabilities. Derivatives are
classified as current or noncurrent based on the contractual
timing of expected future net cash flows of individual
contracts. The expected future net cash flows for derivatives
classified as current are expected to occur within the next
12 months. The fair value amounts are presented on a gross
basis and do not reflect the netting of asset and liability
positions permitted under the terms of our master netting
arrangements. Further, the amounts below do not include cash
held on deposit in margin accounts that we have received or
remitted to collateralize certain derivative positions.
| December 31, 2009 | ||||||||
| Assets | Liabilities | |||||||
| (Millions) | ||||||||
|
Designated as hedging instruments
|
$ | 352 | $ | 174 | ||||
|
Not designated as hedging instruments:
|
||||||||
|
Legacy natural gas contracts from former power business
|
505 | 526 | ||||||
|
All other
|
237 | 306 | ||||||
|
Total derivatives not designated as hedging instruments
|
742 | 832 | ||||||
|
Total derivatives
|
$ | 1,094 | $ | 1,006 | ||||
The following table presents pre-tax gains and losses for our
energy commodity derivatives designated as cash flow hedges, as
recognized in accumulated other comprehensive income (AOCI) or
revenues.
|
Year Ended
|
||||||
|
December 31,
|
||||||
| 2009 | Classification | |||||
| (Millions) | ||||||
|
Net gain recognized in other comprehensive income (effective
portion)
|
$ | 262 | AOCI | |||
|
Net gain reclassified from
accumulated other comprehensive
loss
into income (effective portion)
|
$ | 618 | Revenues | |||
|
Gain recognized in income (ineffective portion)
|
$ | 4 | Revenues | |||
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
There were no gains or losses recognized in income as a result
of excluding amounts from the assessment of hedge effectiveness.
The following table presents pre-tax gains and losses for our
energy commodity derivatives not designated as hedging
instruments.
|
Year Ended
|
||||
| December 31, 2009 | ||||
| (Millions) | ||||
|
Revenues
|
$ | 37 | ||
|
Costs and operating expenses
|
33 | |||
|
Net gain
|
$ | 4 | ||
The cash flow impact of our derivative activities is presented
in the Consolidated Statement of Cash Flows as
changes in
current and noncurrent derivative assets and liabilities
.
Credit-risk-related
features
Certain of our derivative contracts contain credit-risk-related
provisions that would require us, in certain circumstances, to
post additional collateral in support of our net derivative
liability positions. These credit-risk-related provisions
require us to post collateral in the form of cash or letters of
credit when our net liability positions exceed an established
credit threshold. The credit thresholds are typically based on
our senior unsecured debt ratings from Standard and Poor’s
and/or
Moody’s Investors Service. Under these contracts, a credit
ratings decline would lower our credit thresholds, thus
requiring us to post additional collateral. We also have
contracts that contain adequate assurance provisions giving the
counterparty the right to request collateral in an amount that
corresponds to the outstanding net liability. Additionally,
Exploration & Production has an unsecured credit
agreement with certain banks related to hedging activities. We
are not required to provide collateral support for net
derivative liability positions under the credit agreement as
long as the value of Exploration & Production’s
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
position on hedges entered into under the credit agreement.
As of December 31, 2009, we have collateral totaling
$96 million posted to derivative counterparties, all of
which is in the form of letters of credit, to support the
aggregate fair value of our net derivative liability position
(reflecting master netting arrangements in place with certain
counterparties) of $167 million, which includes a reduction
of $3 million to our liability balance for our own
nonperformance risk. The additional collateral that we would
have been required to post, assuming our credit thresholds were
eliminated and a call for adequate assurance under the credit
risk provisions in our derivative contracts was triggered, is
$74 million.
Cash flow
hedges
Changes in the fair value of our cash flow hedges, to the extent
effective, are deferred in other comprehensive income and
reclassified into earnings in the same period or periods in
which the hedged forecasted purchases or sales affect earnings,
or when it is probable that the hedged forecasted transaction
will not occur by the end of the originally specified time
period. As of December 31, 2009, we have hedged portions of
future cash flows associated with anticipated energy commodity
purchases and sales for up to three years. Based on recorded
values at December 31, 2009, $64 million of net gains
(net of income tax provision of $39 million) will be
reclassified into earnings within the next year. These recorded
values are based on market prices of the commodities as of
December 31, 2009. Due to the volatile nature of commodity
prices and changes in the creditworthiness of counterparties,
actual gains or losses realized within the next year will likely
differ from these values. These gains or losses are expected to
substantially offset net losses or gains that will be realized
in earnings from previous unfavorable or favorable market
movements associated with underlying hedged transactions.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Guarantees
In addition to the guarantees and payment obligations discussed
in Note 16, we have issued guarantees and other similar
arrangements as discussed below.
We are required by our revolving credit agreement to indemnify
lenders for any taxes required to be withheld from payments due
to the lenders and for any tax payments made by the lenders. The
maximum potential amount of future payments under these
indemnifications is based on the related borrowings and such
future payments cannot currently be determined. These
indemnifications generally continue indefinitely unless limited
by the underlying tax regulations and have no carrying value. We
have never been called upon to perform under these
indemnifications and have no current expectation of a future
claim.
We have provided guarantees in the event of nonpayment by our
previously owned communications subsidiary, WilTel, on certain
lease performance obligations that extend through 2042. The
maximum potential exposure is approximately $40 million at
December 31, 2009, and $42 million at
December 31, 2008. Our exposure declines systematically
throughout the remaining term of WilTel’s obligations. The
carrying value of these guarantees included in
accrued
liabilities
on the Consolidated Balance Sheet is
$36 million at December 31, 2009 and $38 million
at December 31, 2008.
At December 31, 2009, we do not expect these guarantees to
have a material impact on our future liquidity or financial
position. However, if we are required to perform on these
guarantees in the future, it may have a material adverse effect
on our results of operations.
Concentration
of Credit Risk
Cash
equivalents
Our cash equivalents are primarily invested in funds with
high-quality, short-term securities and instruments that are
issued or guaranteed by the U.S. government.
Accounts
and notes receivable
The following table summarizes concentration of receivables
including those related to discontinued operations (see
Note 2), net of allowances, by product or service:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Receivables by product or service:
|
||||||||
|
Sale of natural gas and related products and services(1)
|
$ | 599 | $ | 653 | ||||
|
Transportation of natural gas and related products
|
173 | 158 | ||||||
|
Joint interest
|
56 | 86 | ||||||
|
Other
|
2 | 49 | ||||||
|
Total
|
$ | 830 | $ | 946 | ||||
| (1) | Includes $57 million net receivable from PDVSA at December 31, 2008. This amount has been fully reserved and subsequently deconsolidated in 2009. (See Note 2.) |
Natural gas customers include pipelines, distribution companies,
producers, gas marketers and industrial users primarily located
in the eastern and northwestern United States, Rocky Mountains,
Gulf Coast, and Canada. As a general policy, collateral is not
required for receivables, but customers’ financial
condition and credit worthiness are evaluated regularly.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Derivative
assets and liabilities
We have a risk of loss from counterparties not performing
pursuant to the terms of their contractual obligations.
Counterparty performance can be influenced by changes in the
economy and regulatory issues, among other factors. Risk of loss
is impacted by several factors, including credit considerations
and the regulatory environment in which a counterparty
transacts. We attempt to minimize credit-risk exposure to
derivative counterparties and brokers through formal credit
policies, consideration of credit ratings from public ratings
agencies, monitoring procedures, master netting agreements and
collateral support under certain circumstances. Collateral
support could include letters of credit, payment under margin
agreements, and guarantees of payment by credit worthy parties.
We also enter into master netting agreements to mitigate
counterparty performance and credit risk. During 2009 and 2008,
we did not incur any significant losses due to counterparty
bankruptcy filings.
The gross credit exposure from our derivative contracts as of
December 31, 2009, is summarized as follows.
|
Investment
|
||||||||
|
Counterparty Type
|
Grade(a) | Total | ||||||
| (Millions) | ||||||||
|
Gas and electric utilities
|
$ | 35 | $ | 424 | ||||
|
Energy marketers and traders
|
1 | 9 | ||||||
|
Financial institutions
|
661 | 661 | ||||||
| $ | 697 | 1,094 | ||||||
|
Credit reserves
|
— | |||||||
|
Gross credit exposure from derivatives
|
$ | 1,094 | ||||||
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, 2009,
excluding collateral support discussed below, is summarized as
follows.
|
Investment
|
||||||||
|
Counterparty Type
|
Grade(a) | Total | ||||||
| (Millions) | ||||||||
|
Gas and electric utilities
|
$ | 17 | $ | 17 | ||||
|
Energy marketers and traders
|
1 | 8 | ||||||
|
Financial institutions
|
230 | 230 | ||||||
| $ | 248 | 255 | ||||||
|
Credit reserves
|
— | |||||||
|
Net credit exposure from derivatives
|
$ | 255 | ||||||
| (a) | We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. |
Our eight largest net counterparty positions represent
approximately 95 percent of our net credit exposure from
derivatives and are all with investment grade counterparties.
Included within this group are five counterparty positions,
representing 64 percent of our net credit exposure from
derivatives, associated with Exploration &
Production’s hedging facility. (See Note 11.) Under
certain conditions, the terms of this credit agreement may
require the participating financial institutions to deliver
collateral support to a designated collateral agent (which is
another participating financial institution in the agreement).
The level of collateral support required is dependent on
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
whether the net position of the counterparty financial
institution exceeds specified thresholds. The thresholds may be
subject to prescribed reductions based on changes in the credit
rating of the counterparty financial institution.
At December 31, 2009, the designated collateral agent holds
$27 million of collateral support on our behalf under
Exploration & Production’s hedging facility. In
addition, we hold collateral support, including letters of
credit, of $25 million related to our other derivative
positions.
Revenues
In 2009, 2008, and 2007, there were no customers for which our
sales exceeded 10 percent of our consolidated revenues.
| Note 16. | Contingent Liabilities and Commitments |
Issues
Resulting from California Energy Crisis
Our former power business was engaged in power marketing in
various geographic areas, including California. Prices charged
for power by us and other traders and generators in California
and other western states in 2000 and 2001 were challenged in
various proceedings, including those before the
U.S. Federal Energy Regulatory Commission (FERC). These
challenges included refund proceedings, summer 2002
90-day
contracts, investigations of alleged market manipulation
including withholding, gas indices and other gaming of the
market, new long-term power sales to the State of California
that were subsequently challenged and civil litigation relating
to certain of these issues. We have entered into settlements
with the State of California (State Settlement), major
California utilities (Utilities Settlement), and others that
substantially resolved each of these issues with these parties.
As a result of a June 2008 U.S. Supreme Court decision,
certain contracts that we entered into during 2000 and
2001 may be subject to partial refunds depending on the
results of further proceedings at the FERC. These contracts,
under which we sold electricity, totaled approximately
$89 million in revenue. While we are not a party to the
cases involved in the U.S. Supreme Court decision, the
buyer of electricity from us is a party to the cases and claims
that we must refund to the buyer any loss it suffers due to the
FERC’s reconsideration of the contract terms at issue in
the decision. The FERC has directed the parties to provide
additional information on certain issues remanded by the
U.S. Supreme Court, but delayed the submission of this
information to permit the parties to explore possible
settlements of the contractual disputes. The parties to the
remanded proceeding have engaged the FERC’s Dispute
Resolution Service to assist with settlement discussions.
Certain other issues also remain open at the FERC and for other
nonsettling parties.
Refund
proceedings
Although we entered into the State Settlement and Utilities
Settlement, which resolved a significant portion of the refund
issues among the settling parties, we continue to have potential
refund exposure to nonsettling parties, such as the counterparty
to the contracts described above and various California end
users that did not participate in the Utilities Settlement. As a
part of the Utilities Settlement, we funded escrow accounts that
will be used towards satisfying any ultimate refund
determinations in favor of the nonsettling parties including
interest on refund amounts that we might owe to settling and
nonsettling parties. We are also owed interest from
counterparties in the California market during the refund period
for which we have recorded a receivable totaling
$24 million at December 31, 2009. Collection of the
interest and the payment of interest on refund amounts from the
escrow accounts are subject to the conclusion of this
proceeding. Therefore, we continue to participate in the FERC
refund case and related proceedings.
Challenges to virtually every aspect of the refund proceedings,
including the refund period, continue to be made. Despite two
FERC decisions that will affect the refund calculation,
significant aspects of the refund
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THE
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NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
calculation process remain unsettled, and the final refund
calculation has not been made. Because of our settlements, we do
not expect that the final resolution of refund obligations will
have a material impact on us.
Reporting
of Natural Gas-Related Information to Trade
Publications
Civil suits based on allegations of manipulating published gas
price indices have been brought against us and others, in each
case seeking an unspecified amount of damages. We are currently
a defendant in class action litigation and other litigation
originally filed in state court in Colorado, Kansas, Missouri,
Tennessee and Wisconsin brought on behalf of direct and indirect
purchasers of gas in those states.
| • | The federal court in Nevada currently presides over cases that were transferred to it from state courts in Colorado, Kansas, Missouri, and Wisconsin. In 2008, the federal court in Nevada granted summary judgment in the Colorado case in favor of us and most of the other defendants, and on January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal. We expect that the Colorado plaintiffs will appeal, but the appeal cannot occur until the case against the remaining defendant is concluded. | |
| • | On October 29, 2008, the Tennessee appellate court reversed the state court’s dismissal of the plaintiffs’ claims on federal preemption grounds and sent the case back to the lower court for further proceedings. We and other defendants appealed the reversal to the Tennessee Supreme Court, and we expect the court’s ruling in 2010. | |
| • | On December 8, 2009, the Missouri appellate court upheld the trial court’s dismissal of a case for lack of standing. The plaintiff has appealed to the Missouri Supreme Court. |
Environmental
Matters
Continuing
operations
Since 1989, our Transco subsidiary has had studies underway to
test certain of its facilities for the presence of toxic and
hazardous substances to determine to what extent, if any,
remediation may be necessary. Transco has responded to data
requests from the U.S. Environmental Protection Agency
(EPA) and state agencies regarding such potential contamination
of certain of its sites. Transco has identified polychlorinated
biphenyl (PCB) contamination in compressor systems, soils and
related properties at certain compressor station sites. Transco
has also been involved in negotiations with the EPA and state
agencies to develop screening, sampling and cleanup programs. In
addition, Transco commenced negotiations with certain
environmental authorities and other parties concerning
investigative and remedial actions relative to potential mercury
contamination at certain gas metering sites. The costs of any
such remediation will depend upon the scope of the remediation.
At December 31, 2009, we had accrued liabilities of
$5 million related to PCB contamination, potential mercury
contamination, and other toxic and hazardous substances. Transco
has been identified as a potentially responsible party at
various Superfund and state waste disposal sites. Based on
present volumetric estimates and other factors, we have
estimated our aggregate exposure for remediation of these sites
to be less than $500,000, which is included in the environmental
accrual discussed above. We expect that these costs will be
recoverable through Transco’s rates.
Beginning in the mid-1980s, our Northwest Pipeline GP (Northwest
Pipeline) subsidiary evaluated many of its facilities for the
presence of toxic and hazardous substances to determine to what
extent, if any, remediation might be necessary. Consistent with
other natural gas transmission companies, Northwest Pipeline
identified PCB contamination in air compressor systems, soils
and related properties at certain compressor station sites.
Similarly, Northwest Pipeline identified hydrocarbon impacts at
these facilities due to the former use of earthen pits and
mercury contamination at certain gas metering sites. The PCBs
were remediated pursuant to a Consent Decree with the EPA in the
late 1980s and Northwest Pipeline conducted a voluntary
clean-up
of
the hydrocarbon and mercury impacts in the early 1990s. In 2005,
the Washington Department of Ecology required Northwest Pipeline
to reevaluate its previous mercury
clean-ups
in
Washington. Consequently, Northwest Pipeline is conducting
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
additional assessments and remediation activities at certain
sites to comply with Washington’s current environmental
standards. At December 31, 2009, we have accrued
liabilities of $8 million for these costs. We expect that
these costs will be recoverable through Northwest
Pipeline’s rates.
In March 2008, the EPA issued new air quality standards for
ground level ozone. In September 2009, the EPA announced that it
would reconsider those standards. In January 2010, the EPA
proposed more stringent standards, which are expected to be
final in August 2010. The EPA expects that new
eight-hour
ozone nonattainment areas will be designated in July 2011. The
new standards and nonattainment areas will likely impact the
operations of our interstate gas pipelines and cause us to incur
additional capital expenditures to comply. At this time we are
unable to estimate the cost of these additions that may be
required to meet these regulations. We expect that costs
associated with these compliance efforts will be recoverable
through rates.
We also accrue environmental remediation costs for natural gas
underground storage facilities, primarily related to soil and
groundwater contamination. At December 31, 2009, we have
accrued liabilities totaling $8 million for these costs.
In April 2007, the New Mexico Environment Department’s
(NMED) Air Quality Bureau issued a notice of violation (NOV) to
Williams Four Corners LLC (Four Corners) that alleged various
emission and reporting violations in connection with our Lybrook
gas processing plant’s flare and leak detection and repair
program. In December 2007, the NMED proposed a penalty of
approximately $3 million. In July 2008, the NMED issued an
NOV to Four Corners that alleged air emissions permit
exceedances for three glycol dehydrators at one of our
compressor facilities and proposed a penalty of approximately
$103,000. We are discussing the proposed penalties with the NMED.
In March 2008, the EPA proposed a penalty of $370,000 for
alleged violations relating to leak detection and repair program
delays at our Ignacio gas plant in Colorado and for alleged
permit violations at a compressor station. We met with the EPA
and are exchanging information in order to resolve the issues.
In September 2007, the EPA requested, and our Transco subsidiary
later provided, information regarding natural gas compressor
stations in the states of Mississippi and Alabama as part of the
EPA’s investigation of our compliance with the Clean Air
Act. On March 28, 2008, the EPA issued NOVs alleging
violations of Clean Air Act requirements at these compressor
stations. We met with the EPA in May 2008 and submitted our
response denying the allegations in June 2008. In July 2009, the
EPA requested additional information pertaining to these
compressor stations and in August 2009, we submitted the
requested information.
In January 2010, the Colorado Department of Public Health and
Environment (CDPHE) proposed a penalty of $113,750 against
Williams Production RMT Company for alleged permit violations at
four compressor stations in Colorado. We are discussing the
proposed penalties with CDPHE.
Former
operations, including operations classified as
discontinued
We have potential obligations in connection with assets and
businesses we no longer operate. These potential obligations
include the indemnification of the purchasers of certain of
these assets and businesses for environmental and other
liabilities existing at the time the sale was consummated. Our
responsibilities include those described below.
Agrico
In connection with the 1987 sale of the assets of Agrico
Chemical Company, we agreed to indemnify the purchaser for
environmental cleanup costs resulting from certain conditions at
specified locations to the extent such costs exceed a specified
amount. At December 31, 2009, we have accrued liabilities
of $8 million for such excess costs.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Other
At December 31, 2009, we have accrued environmental
liabilities of $13 million related primarily to our:
| • | Potential indemnification obligations to purchasers of our former retail petroleum and refining operations; | |
| • | Former propane marketing operations, bio-energy facilities, petroleum products and natural gas pipelines; | |
| • | Discontinued petroleum refining facilities; | |
| • | Former exploration and production and mining operations. |
Certain of our subsidiaries have been identified as potentially
responsible parties at various Superfund and state waste
disposal sites. In addition, these subsidiaries have incurred,
or are alleged to have incurred, various other hazardous
materials removal or remediation obligations under environmental
laws.
Summary
of environmental matters
Actual costs incurred for these matters could be substantially
greater than amounts accrued depending on the actual number of
contaminated sites identified, the actual amount and extent of
contamination discovered, the final cleanup standards mandated
by the EPA and other governmental authorities and other factors,
but the amount cannot be reasonably estimated at this time.
Other
Legal Matters
Will
Price (formerly Quinque)
In 2001, fourteen of our entities were named as defendants in a
nationwide class action lawsuit in Kansas state court that had
been pending against other defendants, generally pipeline and
gathering companies, since 2000. The plaintiffs alleged that the
defendants have engaged in mismeasurement techniques that
distort the heating content of natural gas, resulting in an
alleged underpayment of royalties to the class of producer
plaintiffs and sought an unspecified amount of damages. The
fourth amended petition, which was filed in 2003, deleted all of
our defendant entities except two Midstream subsidiaries. All
remaining defendants opposed class certification and on
September 18, 2009, the court denied plaintiffs’ most
recent motion to certify the class. On October 2, 2009, the
plaintiffs filed a motion for reconsideration of the denial. We
are awaiting a decision from the court. The amount of any
possible liability cannot be reasonably estimated at this time.
Gulf
Liquids litigation
Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby)
and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for
the construction of certain gas processing plants in Louisiana.
National American Insurance Company (NAICO) and American Home
Assurance Company provided payment and performance bonds for the
projects. In 2001, the contractors and sureties filed multiple
cases in Louisiana and Texas against Gulf Liquids and us.
In 2006, at the conclusion of the consolidated trial of the
asserted contract and tort claims, the jury returned its actual
and punitive damages verdict against us and Gulf Liquids. Based
on our interpretation of the jury verdicts, we recorded a charge
based on our estimated exposure for actual damages of
approximately $68 million plus potential interest of
approximately $20 million. In addition, we concluded that
it was reasonably possible that any ultimate judgment might have
included additional amounts of approximately $199 million
in excess of our accrual, which primarily represented our
estimate of potential punitive damage exposure under Texas law.
From May through October 2007, the court entered seven
post-trial orders in the case (interlocutory orders) which,
among other things, overruled the verdict award of tort and
punitive damages as well as any damages against us. The court
also denied the plaintiffs’ claims for attorneys’
fees. On January 28, 2008, the court issued its
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
judgment awarding damages against Gulf Liquids of approximately
$11 million in favor of Gulsby and approximately
$4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby,
Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In
February 2009, we settled with certain of these parties and
reduced our liability as of December 31, 2008, by
$43 million, including $11 million of interest. If the
judgment is upheld on appeal, our remaining liability will be
substantially less than the amount of our accrual for these
matters.
Wyoming
severance taxes
In August 2006, the Wyoming Department of Audit (DOA) assessed
our subsidiary, Williams Production RMT Company, additional
severance tax and interest for the production years 2000 through
2002. In addition, the DOA notified us of an increase in the
taxable value of our interests for ad valorem tax purposes. The
negative assessment for the
2000-2002
time period resulted in additional severance and ad valorem
taxes of $4 million. We disputed the DOA’s
interpretation of the statutory obligation and appealed this
assessment to the Wyoming State Board of Equalization (SBOE).
The SBOE upheld the assessment and remanded it to the DOA to
address the disallowance of a credit. We appealed to the Wyoming
Supreme Court but the court ruled against us in December 2008.
On April 14, 2009, the Wyoming Supreme Court denied our
petition for rehearing and issued its mandate affirming its
prior published decision in this case. We had accrued
liabilities of $39 million as of December 31, 2008,
related to this matter representing our estimated exposure,
including interest, through the end of 2008. During 2009, we
reduced our accrual for our estimated exposure by
$6 million, including interest, and made net payments of
$29 million. While certain issues involved remain to be
resolved, we do not expect any material future changes from this
matter and estimate our remaining net exposure, including
interest, to be approximately $4 million at
December 31, 2009, all of which has been recorded.
Royalty
litigation
In September 2006, royalty interest owners in Garfield County,
Colorado, filed a class action suit in Colorado state court
alleging that we improperly calculated oil and gas royalty
payments, failed to account for the proceeds that we received
from the sale of gas and extracted products, improperly charged
certain expenses, and failed to refund amounts withheld in
excess of ad valorem tax obligations. The plaintiffs claim that
the class might be in excess of 500 individuals and seek an
accounting and damages. We have reached a final partial
settlement agreement for an amount that was previously accrued.
We anticipate trial in 2010 on remaining issues related to
royalty payment calculation and obligations under specific lease
provisions. While we are not able to estimate the amount of any
additional exposure at this time, it is reasonably possible that
plaintiff’s claims could reach a material amount.
Other producers have been in litigation or discussions with a
federal regulatory agency and a state agency in New Mexico
regarding certain deductions used in the calculation of
royalties. Although we are not a party to these matters, we have
monitored them to evaluate whether their resolution might have
the potential for unfavorable impact on our results of
operations. One of these matters involving federal litigation
was decided on October 5, 2009. The resolution of this
specific matter is not material to us. However, other related
issues in these matters that could be material to us remain
outstanding.
Other
Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to
divested businesses and assets, we have indemnified certain
purchasers against liabilities that they may incur with respect
to the businesses and assets acquired from us. The indemnities
provided to the purchasers are customary in sale transactions
and are contingent upon the purchasers incurring liabilities
that are not otherwise recoverable from third parties. The
indemnities generally relate to breach of warranties, tax,
historic litigation, personal injury, environmental matters,
right of way and other representations that we have provided.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At December 31, 2009, we do not expect any of the
indemnities provided pursuant to the sales agreements to have a
material impact on our future financial position. However, if a
claim for indemnity is brought against us in the future, it may
have a material adverse effect on our results of operations in
the period in which the claim is made.
In addition to the foregoing, various other proceedings are
pending against us which are incidental to our operations.
Summary
Litigation, arbitration, regulatory matters, and environmental
matters are subject to inherent uncertainties. Were an
unfavorable ruling to occur, there exists the possibility of a
material adverse impact on the results of operations in the
period in which the ruling occurs. Management, including
internal counsel, currently believes that the ultimate
resolution of the foregoing matters, taken as a whole and after
consideration of amounts accrued, insurance coverage, recovery
from customers or other indemnification arrangements, will not
have a material adverse effect upon our future liquidity or
financial position.
Commitments
Commitments for construction and acquisition of property, plant
and equipment are approximately $221 million at
December 31, 2009.
As part of managing our commodity price risk, we utilize
contracted pipeline capacity primarily to move our natural gas
production to other locations with more favorable pricing
differentials. Our commitments under these contracts are as
follows:
| (Millions) | ||||
|
2010
|
$ | 166 | ||
|
2011
|
170 | |||
|
2012
|
159 | |||
|
2013
|
141 | |||
|
2014
|
122 | |||
|
Thereafter
|
526 | |||
|
Total
|
$ | 1,284 | ||
We also have certain commitments to an equity investee for
natural gas gathering and treating services which total
$188 million over approximately eight years.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 17. | Accumulated Other Comprehensive Loss |
The table below presents changes in the components of
accumulated other comprehensive loss.
| Income (Loss) | ||||||||||||||||||||||||||||
|
Other
|
||||||||||||||||||||||||||||
|
Postretirement
|
||||||||||||||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||||||||||||||
|
Foreign
|
Prior
|
Net
|
Prior
|
Net
|
||||||||||||||||||||||||
|
Cash Flow
|
Currency
|
Service
|
Actuarial
|
Service
|
Actuarial
|
|||||||||||||||||||||||
| Hedges | Translation | Cost | Gain (Loss) | Cost | Gain (Loss) | Total | ||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
|
Balance at December 31, 2006
|
$ | 20 | $ | 76 | $ | (4 | ) | $ | (150 | ) | $ | (4 | ) | $ | 2 | $ | (60 | ) | ||||||||||
|
2007 Change:
|
||||||||||||||||||||||||||||
|
Pre-income tax amount
|
201 | 53 | — | 68 | — | 15 | 337 | |||||||||||||||||||||
|
Income tax provision
|
(77 | ) | — | — | (26 | ) | — | (6 | ) | (109 | ) | |||||||||||||||||
|
Net reclassification into earnings of derivative instrument
gains (net of a $187 million income tax provision)
|
(303 | )* | — | — | — | — | — | (303 | ) | |||||||||||||||||||
|
Amortization included in net periodic benefit expense
|
— | — | — | 19 | 2 | — | 21 | |||||||||||||||||||||
|
Income tax provision on amortization
|
— | — | — | (8 | ) | (1 | ) | — | (9 | ) | ||||||||||||||||||
| (179 | ) | 53 | — | 53 | 1 | 9 | (63 | ) | ||||||||||||||||||||
|
Allocation of other comprehensive loss to noncontrolling
interests
|
2 | — | — | — | — | — | 2 | |||||||||||||||||||||
|
Balance at December 31, 2007
|
(157 | ) | 129 | (4 | ) | (97 | ) | (3 | ) | 11 | (121 | ) | ||||||||||||||||
|
2008 Change:
|
||||||||||||||||||||||||||||
|
Pre-income tax amount
|
714 | (76 | ) | — | (565 | ) | 16 | (15 | ) | 74 | ||||||||||||||||||
|
Income tax (provision) benefit
|
(270 | ) | — | — | 213 | (8 | ) | 6 | (59 | ) | ||||||||||||||||||
|
Net reclassification into earnings of derivative instrument
losses (net of a $7 million income tax benefit)
|
11 | — | — | — | — | — | 11 | |||||||||||||||||||||
|
Amortization included in net periodic benefit expense
|
— | — | 1 | 13 | 1 | — | 15 | |||||||||||||||||||||
|
Income tax provision on amortization
|
— | — | — | (5 | ) | — | — | (5 | ) | |||||||||||||||||||
| 455 | (76 | ) | 1 | (344 | ) | 9 | (9 | ) | 36 | |||||||||||||||||||
|
Allocation of other comprehensive income (loss) to
noncontrolling interests
|
(2 | ) | — | — | 7 | — | — | 5 | ||||||||||||||||||||
|
Balance at December 31, 2008
|
296 | 53 | (3 | ) | (434 | ) | 6 | 2 | (80 | ) | ||||||||||||||||||
|
2009 Change:
|
||||||||||||||||||||||||||||
|
Pre-income tax amount
|
262 | 83 | — | 44 | 7 | (1 | ) | 395 | ||||||||||||||||||||
|
Income tax (provision) benefit
|
(99 | ) | — | — | (17 | ) | — | 1 | (115 | ) | ||||||||||||||||||
|
Net reclassification into earnings of derivative instrument
gains (net of a $234 million income tax provision)
|
(384 | ) | — | — | — | — | — | (384 | ) | |||||||||||||||||||
|
Amortization included in net periodic benefit expense
|
— | — | 1 | 42 | (4 | ) | — | 39 | ||||||||||||||||||||
|
Income tax (provision) benefit on amortization
|
— | — | (1 | ) | (16 | ) | 1 | — | (16 | ) | ||||||||||||||||||
| (221 | ) | 83 | — | 53 | 4 | — | (81 | ) | ||||||||||||||||||||
|
Allocation of other comprehensive income to noncontrolling
interests
|
— | — | — | (7 | ) | — | — | (7 | ) | |||||||||||||||||||
|
Balance at December 31, 2009
|
$ | 75 | $ | 136 | $ | (3 | ) | $ | (388 | ) | $ | 10 | $ | 2 | $ | (168 | ) | |||||||||||
| * | Includes a $429 million reclassification into earnings of deferred net hedge gains related to the sale of our power business. (See Note 2.) |
| Note 18. | Segment Disclosures |
Our reportable segments are strategic business units that offer
different products and services. The segments are managed
separately because each segment requires different technology,
marketing strategies and industry knowledge. Our master limited
partnerships, Williams Partners L.P. and Williams Pipeline
Partners L.P., are consolidated within our Midstream and Gas
Pipeline segments, respectively. (See Note 1.) Other
primarily consists of corporate operations.
140
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In February 2010, we completed our strategic restructuring that
will change our reportable segments in first-quarter 2010. (See
Note 19 of Notes to Consolidated Financial Statements.)
Performance
Measurement
We currently evaluate performance based on
segment profit
(loss)
from operations, which includes
segment revenues
from external and internal customers,
segment costs and
expenses, equity earnings (losses)
and
income (loss) from
investments
. The accounting policies of the segments are the
same as those described in Note 1. Intersegment sales are
generally accounted for at current market prices as if the sales
were to unaffiliated third parties.
The primary types of costs and operating expenses by segment can
be generally summarized as follows:
| • | Exploration & Production — depletion, depreciation and amortization, lease and facility operating expenses and operating taxes; | |
| • | Gas Pipeline — depreciation and operation and maintenance expenses; | |
| • | Midstream Gas & Liquids — commodity purchases (primarily for NGL, crude and olefin marketing, shrink, feedstock and fuel), depreciation, and operation and maintenance expenses; | |
| • | Gas Marketing Services — commodity purchases primarily in support of commodity marketing and risk management activities. |
Energy commodity hedging by our business units may be done
through intercompany derivatives with our Gas Marketing segment
which, in turn, enters into offsetting derivative contracts with
unrelated third parties. Gas Marketing bears the counterparty
performance risks associated with the unrelated third parties in
these transactions. Additionally, Exploration &
Production may enter into transactions directly with third
parties under their credit agreement. (See Note 11.)
Exploration & Production bears the counterparty
performance risks associated with the unrelated third parties in
these transactions.
External revenues of our Exploration & Production
segment are presented net of transportation expenses and
royalties due third parties on intersegment sales. In some
periods, transportation expenses and royalties due third parties
on intersegment sales may exceed other external revenues.
The following geographic area data includes
revenues from
external customers
based on product shipment origin and
long-lived assets
based upon physical location.
| United States | Other | Total | ||||||||||
| (Millions) | ||||||||||||
|
Revenues from external customers:
|
||||||||||||
|
2009
|
$ | 8,065 | $ | 190 | $ | 8,255 | ||||||
|
2008
|
11,629 | 261 | 11,890 | |||||||||
|
2007
|
9,966 | 273 | 10,239 | |||||||||
|
Long-lived assets:
|
||||||||||||
|
2009
|
$ | 19,247 | $ | 410 | $ | 19,657 | ||||||
|
2008
|
18,419 | 335 | 18,754 | |||||||||
|
2007
|
16,279 | 361 | 16,640 | |||||||||
Our foreign operations are primarily located in Canada and South
America.
Long-lived assets
are comprised of property,
plant and equipment, goodwill and other intangible assets.
141
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table reflects the reconciliation of
segment
revenues
and
segment profit (loss)
to
revenues
and
operating income (loss)
as reported in the
Consolidated Statement of Income and
other financial
information
related to
long-lived assets.
|
Exploration &
|
Gas
|
Gas
|
||||||||||||||||||||||||||
| Production | Pipeline | Midstream | Marketing | Other | Eliminations | Total | ||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
|
2009
|
||||||||||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||||||||||
|
External
|
$ | 564 | $ | 1,563 | $ | 3,516 | $ | 2,599 | $ | 13 | $ | — | $ | 8,255 | ||||||||||||||
|
Internal
|
1,655 | 28 | 72 | 453 | 14 | (2,222 | ) | — | ||||||||||||||||||||
|
Total revenues
|
$ | 2,219 | $ | 1,591 | $ | 3,588 | $ | 3,052 | $ | 27 | $ | (2,222 | ) | $ | 8,255 | |||||||||||||
|
Segment profit (loss)
|
$ | 418 | $ | 667 | $ | 640 | $ | (18 | ) | $ | (1 | ) | $ | — | $ | 1,706 | ||||||||||||
|
Less:
|
||||||||||||||||||||||||||||
|
Equity earnings
|
18 | 66 | 52 | — | — | — | 136 | |||||||||||||||||||||
|
Loss from investments
|
— | — | (75 | ) | — | — | — | (75 | ) | |||||||||||||||||||
|
Segment operating income (loss)
|
$ | 400 | $ | 601 | $ | 663 | $ | (18 | ) | $ | (1 | ) | $ | — | 1,645 | |||||||||||||
|
General corporate expenses
|
(164 | ) | ||||||||||||||||||||||||||
|
Total operating income
|
$ | 1,481 | ||||||||||||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||||||||||
|
Additions to long-lived assets
|
$ | 1,324 | $ | 518 | $ | 528 | $ | — | $ | 27 | $ | — | $ | 2,397 | ||||||||||||||
|
Depreciation, depletion & amortization
|
$ | 889 | $ | 334 | $ | 217 | $ | 1 | $ | 20 | $ | — | $ | 1,461 | ||||||||||||||
|
2008
|
||||||||||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||||||||||
|
External
|
$ | (215 | ) | $ | 1,600 | $ | 5,124 | $ | 5,371 | $ | 10 | $ | — | $ | 11,890 | |||||||||||||
|
Internal
|
3,336 | 34 | 56 | 1,041 | 14 | (4,481 | ) | — | ||||||||||||||||||||
|
Total revenues
|
$ | 3,121 | $ | 1,634 | $ | 5,180 | $ | 6,412 | $ | 24 | $ | (4,481 | ) | $ | 11,890 | |||||||||||||
|
Segment profit (loss)
|
$ | 1,260 | $ | 689 | $ | 871 | $ | 3 | $ | (3 | ) | $ | — | $ | 2,820 | |||||||||||||
|
Less:
|
||||||||||||||||||||||||||||
|
Equity earnings
|
20 | 59 | 58 | — | — | — | 137 | |||||||||||||||||||||
|
Income from investments
|
— | — | 1 | — | — | — | 1 | |||||||||||||||||||||
|
Segment operating income (loss)
|
$ | 1,240 | $ | 630 | $ | 812 | $ | 3 | $ | (3 | ) | $ | — | 2,682 | ||||||||||||||
|
General corporate expenses
|
(149 | ) | ||||||||||||||||||||||||||
|
Total operating income
|
$ | 2,533 | ||||||||||||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||||||||||
|
Additions to long-lived assets
|
$ | 2,563 | $ | 413 | $ | 676 | $ | — | $ | 42 | $ | — | $ | 3,694 | ||||||||||||||
|
Depreciation, depletion & amortization
|
$ | 737 | $ | 321 | $ | 203 | $ | 1 | $ | 18 | $ | — | $ | 1,280 | ||||||||||||||
|
2007
|
||||||||||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||||||||||
|
External
|
$ | (167 | ) | $ | 1,576 | $ | 4,895 | $ | 3,924 | $ | 11 | $ | — | $ | 10,239 | |||||||||||||
|
Internal
|
2,188 | 34 | 38 | 709 | 15 | (2,984 | ) | — | ||||||||||||||||||||
|
Total revenues
|
$ | 2,021 | $ | 1,610 | $ | 4,933 | $ | 4,633 | $ | 26 | $ | (2,984 | ) | $ | 10,239 | |||||||||||||
|
Segment profit (loss)
|
$ | 756 | $ | 673 | $ | 994 | $ | (337 | ) | $ | (1 | ) | $ | — | $ | 2,085 | ||||||||||||
|
Less equity earnings
|
25 | 51 | 61 | — | — | — | 137 | |||||||||||||||||||||
|
Segment operating income (loss)
|
$ | 731 | $ | 622 | $ | 933 | $ | (337 | ) | $ | (1 | ) | $ | — | 1,948 | |||||||||||||
|
General corporate expenses
|
(161 | ) | ||||||||||||||||||||||||||
|
Total operating income
|
$ | 1,787 | ||||||||||||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||||||||||
|
Additions to long-lived assets
|
$ | 1,717 | $ | 546 | $ | 609 | $ | — | $ | 27 | $ | — | $ | 2,899 | ||||||||||||||
|
Depreciation, depletion & amortization
|
$ | 535 | $ | 315 | $ | 184 | $ | 7 | $ | 10 | $ | — | $ | 1,051 | ||||||||||||||
142
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table reflects
total assets
and
equity
method investments
by reporting segment.
| Total Assets | Equity Method Investments | |||||||||||||||||||||||
|
December 31,
|
December 31,
|
December 31,
|
December 31,
|
December 31,
|
December 31,
|
|||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
|
Exploration & Production(1)
|
$ | 9,682 | $ | 10,286 | $ | 8,692 | $ | 95 | $ | 87 | $ | 72 | ||||||||||||
|
Gas Pipeline
|
9,421 | 9,149 | 8,624 | 429 | 570 | 483 | ||||||||||||||||||
|
Midstream Gas & Liquids
|
7,245 | 6,501 | 6,066 | 360 | 290 | 321 | ||||||||||||||||||
|
Gas Marketing Services(2)
|
1,324 | 3,064 | 4,437 | — | — | — | ||||||||||||||||||
|
Other
|
3,535 | 3,532 | 3,592 | — | — | — | ||||||||||||||||||
|
Eliminations
|
(5,928 | ) | (7,055 | ) | (7,073 | ) | — | — | — | |||||||||||||||
| 25,279 | 25,477 | 24,338 | 884 | 947 | 876 | |||||||||||||||||||
|
Discontinued operations (see Note 2)
|
1 | 529 | 723 | — | — | — | ||||||||||||||||||
|
Total
|
$ | 25,280 | $ | 26,006 | $ | 25,061 | $ | 884 | $ | 947 | $ | 876 | ||||||||||||
| (1) | The 2008 increase in Exploration & Production’s total assets is due to an increase in property, plant and equipment — net as a result of increased drilling activity. | |
| (2) | The decrease in Gas Marketing Services’ total assets for 2009 and 2008 is primarily due to the fluctuations in derivative assets as a result of the impact of changes in commodity prices on existing forward derivative contracts. Gas Marketing Services’ derivative assets are substantially offset by their derivative liabilities. |
| Note 19. | Subsequent Events |
Strategic
Restructuring
On February 17, 2010, we completed a strategic
restructuring that involved contributing certain of our wholly
and partially owned subsidiaries to WPZ in exchange for cash and
WPZ common units. The contributed businesses are currently
reported within our Gas Pipeline and Midstream segments. The
aggregate consideration received from WPZ consisted of the
following:
| • | The issuance to us of 203 million WPZ Class C units, which are identical to common units, except for a prorated initial distribution; | |
| • | An increase in our general-partner’s capital account to maintain our 2 percent general-partner interest and the issuance of WPZ general-partner units equal to 2/98th of the number of WPZ common units issued; | |
| • | Proceeds from the sale of $3.5 billion aggregate principal amount of senior unsecured notes of WPZ to qualified institutional buyers, net of all expenses incurred by WPZ in connection with these transactions. |
Utilizing the cash consideration received from WPZ, we retired
$3 billion of debt and paid $574 million in related
premiums as well as other transaction costs.
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Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Long-term
Debt and Credit Facilities
The WPZ $3.5 billion senior unsecured notes issued, at
face, include:
| (Millions) | ||||
|
3.80% Senior Notes due 2015
|
$ | 750 | ||
|
5.25% Senior Notes due 2020
|
1,500 | |||
|
6.30% Senior Notes due 2040
|
1,250 | |||
|
Total
|
$ | 3,500 | ||
In connection with the issuance of the $3.5 billion
unsecured notes previously discussed, WPZ entered into
registration rights agreements with the initial purchasers of
the notes. WPZ is obligated to file a registration statement for
an offer to exchange the notes for a new issue of substantially
identical notes registered under the Securities Act of 1933, as
amended, within 180 days from closing and use its
commercially reasonable efforts to cause the registration
statement to be declared effective within 270 days after
closing and to consummate the exchange offers within 30 business
days after such effective date. WPZ may also be required to
provide a shelf registration statement to cover resales of the
notes under certain circumstances. If WPZ fails to fulfill these
obligations, additional interest will accrue on the affected
securities. The rate of additional interest will be
0.25 percent per annum on the principal amount of the
affected securities for the first
90-day
period immediately following the occurrence of default,
increasing by an additional 0.25 percent per annum with
respect to each subsequent
90-day
period thereafter, up to a maximum amount for all such defaults
of 0.5 percent annually. Following the cure of any
registration defaults the accrual of additional interest will
cease.
The $3 billion of aggregate principal corporate debt
retired includes:
| (Millions) | ||||
|
7.125% Notes due 2011
|
$ | 429 | ||
|
8.125% Notes due 2012
|
602 | |||
|
7.625% Notes due 2019
|
668 | |||
|
8.75% Senior Notes due 2020
|
586 | |||
|
7.875% Notes due 2021
|
179 | |||
|
7.70% Debentures due 2027
|
98 | |||
|
7.50% Debentures due 2031
|
163 | |||
|
7.75% Notes due 2031
|
111 | |||
|
8.75% Notes due 2032
|
164 | |||
|
Total
|
$ | 3,000 | ||
As part of the restructuring, WPZ, Transco and Northwest
Pipeline, as co-borrowers, entered into a new $1.75 billion
three-year senior unsecured revolving credit facility. The full
amount of the new credit facility is available to WPZ to the
extent not otherwise utilized by Transco and Northwest Pipeline,
and may be increased by up to an additional $250 million.
Transco and Northwest Pipeline each have access to borrow up to
$400 million under the new facility to the extent not
otherwise utilized. WPZ utilized $250 million of the new
credit facility to repay a term loan that was outstanding under
its previously existing $450 million facility. As WPZ will
be funding Midstream and Gas Pipeline projects, we reduced our
$1.5 billion unsecured credit facility that expires May
2012 to $900 million and removed Transco and Northwest
Pipeline as borrowers. Our unsecured credit facility that
expires December 2013 and is used to facilitate our natural gas
production hedging remains unchanged.
The new credit facility contains various covenants that limit,
among other things, a borrower’s and its respective
subsidiaries’ ability to incur indebtedness, grant certain
liens supporting indebtedness, merge or
144
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
consolidate, sell all or substantially all of its assets, enter
into certain affiliate transactions, make certain distributions
during an event of default, and allow any material change in the
nature of its business.
Under the new credit facility, WPZ is required to maintain a
ratio of debt to EBITDA (each as defined) of no greater than
5.00 to 1.00 for itself and its consolidated subsidiaries. For
Transco and Northwest Pipeline and their consolidated
subsidiaries, the ratio of debt to capitalization (each as
defined) is not permitted to be greater than 55 percent.
Each of the above ratios will be tested quarterly, beginning
with the second quarter of 2010, and the debt to EBITDA ratio
will be measured on a rolling four-quarter basis.
Contributed
Businesses
The contributed Gas Pipeline businesses include 100 percent
of Transco, 65 percent of Northwest Pipeline, and
24.5 percent of Gulfstream. We also contributed our
general- and limited-partner interests in WMZ, which owns the
remaining 35 percent of Northwest Pipeline. The contributed
Midstream businesses include significant, large-scale operations
in the Rocky Mountain and Gulf Coast regions, a recently
acquired business in Pennsylvania’s Marcellus Shale region,
and various equity investments in domestic processing and
fractionation assets. Our remaining 25.5 percent ownership
interest in Gulfstream and our Canadian, Venezuelan, and olefins
operations are excluded from the transaction. Additionally, our
Exploration & Production business was not included in this
transaction.
Segment
Changes
As a result of the restructuring, we will change our segment
reporting structure to align with the new parent-level focus,
resource allocation management and related governance
provisions. Beginning with reporting first-quarter 2010 results,
our reportable segments will be Williams Partners,
Exploration & Production, and Other.
Exploration & Production will include the current Gas
Marketing Services segment, and Other will include the Canadian
and olefins operations and the 25.5 percent interest in
Gulfstream, as well as corporate operations.
Stockholders’
Equity & Noncontrolling Interests
We will account for the change in our ownership interest in WPZ
as an equity transaction and adjust the carrying amount of
noncontrolling interest to reflect this change in ownership. As
a result, we expect our
capital in excess of par value
will decrease with a corresponding increase to
noncontrolling interests in consolidated subsidiaries
.
145
Table of Contents
THE
WILLIAMS COMPANIES, INC.
QUARTERLY
FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (millions,
except per-share amounts).
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
|
2009
|
||||||||||||||||
|
Revenues
|
$ | 1,922 | $ | 1,909 | $ | 2,098 | $ | 2,326 | ||||||||
|
Costs and operating expenses
|
1,444 | 1,392 | 1,537 | 1,708 | ||||||||||||
|
Income from continuing operations
|
19 | 151 | 192 | 222 | ||||||||||||
|
Net income (loss)
|
(224 | ) | 169 | 194 | 222 | |||||||||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||||||
|
Income from continuing operations
|
2 | 123 | 141 | 172 | ||||||||||||
|
Net income (loss)
|
(172 | ) | 142 | 143 | 172 | |||||||||||
|
Basic earnings per common share:
|
||||||||||||||||
|
Income from continuing operations
|
— | .21 | .24 | .30 | ||||||||||||
|
Diluted earnings per common share:
|
||||||||||||||||
|
Income from continuing operations
|
— | .21 | .24 | .29 | ||||||||||||
|
2008
|
||||||||||||||||
|
Revenues
|
$ | 3,095 | $ | 3,574 | $ | 3,137 | $ | 2,084 | ||||||||
|
Costs and operating expenses
|
2,264 | 2,614 | 2,280 | 1,618 | ||||||||||||
|
Income from continuing operations
|
448 | 471 | 411 | 137 | ||||||||||||
|
Net income
|
539 | 500 | 421 | 132 | ||||||||||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||||||
|
Income from continuing operations
|
411 | 412 | 360 | 123 | ||||||||||||
|
Net income
|
500 | 437 | 366 | 115 | ||||||||||||
|
Basic earnings per common share:
|
||||||||||||||||
|
Income from continuing operations
|
.70 | .71 | .62 | .21 | ||||||||||||
|
Diluted earnings per common share:
|
||||||||||||||||
|
Income from continuing operations
|
.69 | .69 | .61 | .21 | ||||||||||||
The sum of earnings per share for the four quarters may not
equal the total earnings per share for the year due to changes
in the average number of common shares outstanding and
rounding.
Amounts reported above for 2008 have been adjusted to reflect
the presentation of certain revenues and costs for Midstream on
a net basis. These adjustments reduced previously reported
revenues
and
costs and operating expenses
by the
same amount, with no impact on segment profit. The reductions
were as follows (in millions):
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
|
2008
|
$ | 69 | $ | 83 | $ | 64 | $ | 79 | ||||||||
Net income
for fourth-quarter 2009 includes the following
pre-tax items:
| • | $40 million gain related to the sale of our Cameron Meadows processing plant at Midstream (see Note 4 of Notes to Consolidated Financial Statements); | |
| • | $17 million unfavorable depletion adjustment at Exploration & Production primarily as the result of new oil and gas accounting guidance that requires we value our reserves using an average price; | |
| • | $15 million impairment of certain natural gas properties at Exploration & Production (see Note 4). |
146
Table of Contents
Net income
for second-quarter 2009 includes the following
pre-tax items:
| • | $15 million gain related to our former coal operations (see summarized results of discontinued operations at Note 2); | |
| • | $11 million of income related to the recovery of certain royalty overpayments from prior periods (see Note 4). |
Net income
for first-quarter 2009 includes the following
pre-tax items:
| • | $211 million impairment of Venezuela property, plant and equipment (see summarized results of discontinued operations at Note 2); | |
| • | $75 million impairment of a Venezuelan investment in Accroven at Midstream (see Note 3); | |
| • | $48 million of bad debt expense related to our discontinued Venezuela operations (see summarized results of discontinued operations at Note 2); | |
| • | $30 million net charge related to the write-off of certain deferred charges related to our discontinued Venezuela operations (see summarized results of discontinued operations at Note 2); | |
| • | $34 million of penalties from early release of drilling rigs at Exploration & Production (see Note 4); | |
| • | $11 million impairment of a Venezuelan cost-based investment at Exploration & Production (see Note 3). |
Net income
for first-quarter 2009 also includes a
$76 million benefit from the reversal of deferred tax
balances related to our discontinued Venezuela operations (see
summarized results of discontinued operations at Note 2).
Net income
for fourth-quarter 2008 includes both the
unfavorable impact of the significant decline in energy
commodity prices and the following pre-tax items:
| • | $129 million impairment of certain natural gas producing properties at Exploration & Production (see Note 4); | |
| • | $43 million of income including associated interest related to the partial settlement of the Gulf Liquids litigation at Midstream (see Note 16); | |
| • | $38 million accrual for Wyoming severance taxes and associated interest expense at Exploration & Production (see Notes 4 and 16); | |
| • | $12 million gain related to the favorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Note 2). |
Net income
for fourth-quarter 2008 also includes a
$46 million adjustment to decrease state income taxes (net
of federal benefit) due to a reduction in our estimate of the
effective deferred state rate (see Note 5).
Net income
for third-quarter 2008 includes the following
pre-tax items:
| • | $14 million impairment of certain natural gas producing properties at Exploration & Production (see Note 4); | |
| • | $10 million gain from the sale of certain south Texas assets at Gas Pipeline (see Note 4). |
Net income
for second-quarter 2008 includes the following
pre-tax items:
| • | $54 million gain related to the favorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Note 2); | |
| • | $30 million gain recognized upon receipt of the remaining proceeds related to the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production (see Note 4); |
147
Table of Contents
| • | $10 million charge associated with a settlement primarily related to the sale of natural gas liquids pipeline systems in 2002 (see summarized results of discontinued operations at Note 2); | |
| • | $10 million charge associated with an oil purchase contract related to our former Alaska refinery (see summarized results of discontinued operations at Note 2). |
Net income
for first-quarter 2008 includes the following
pre-tax items:
| • | $118 million gain on the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production (see Note 4); | |
| • | $74 million gain related to the favorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Note 2); | |
| • | $54 million of income related to a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank (see summarized results of discontinued operations at Note 2). |
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Table of Contents
THE
WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(Unaudited)
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(Unaudited)
We have significant oil and gas producing activities primarily
in the Rocky Mountain and Mid-continent areas of the United
States. Additionally, we have international oil- and
gas-producing activities, primarily in Argentina. Proved
reserves and revenues related to international activities are
approximately 4 percent and 3 percent, respectively,
of our total international and domestic proved reserves and
revenues. Accordingly, the following information relates only to
the oil and gas activities in the United States.
Capitalized
Costs
| As of December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Proved properties
|
$ | 9,165 | $ | 8,099 | ||||
|
Unproved properties
|
953 | 806 | ||||||
| 10,118 | 8,905 | |||||||
|
Accumulated depreciation, depletion and amortization and
valuation provisions
|
(3,212 | ) | (2,353 | ) | ||||
|
Net capitalized costs
|
$ | 6,906 | $ | 6,552 | ||||
| • | Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $762 million and $726 million, net, for 2009 and 2008, respectively. The capitalized cost amounts do not include approximately $1 billion of goodwill related to the purchase of Barrett Resources Corporation (Barrett) in 2001. | |
| • | Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs, and successful exploratory wells. | |
| • | Unproved properties consist primarily of costs for acquired unproven reserves. |
Costs
Incurred
|
For The Year Ended
|
||||||||||||
| December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Acquisition
|
$ | 305 | $ | 543 | $ | 82 | ||||||
|
Exploration
|
51 | 38 | 38 | |||||||||
|
Development
|
878 | 1,699 | 1,374 | |||||||||
| $ | 1,234 | $ | 2,280 | $ | 1,494 | |||||||
| • | Costs incurred include capitalized and expensed items. | |
| • | Acquisition costs are as follows: The 2009 costs are primarily for additional leasehold and reserve acquisitions in the Piceance basin, and includes $85 million of proved property values. The 2008 and 2007 costs are primarily for additional leasehold and reserve acquisitions in the Piceance and Fort Worth basins. Included in the 2008 acquisition amounts is $140 million of proved property values and $71 million related to an interest in a portion of acquired assets that a third party subsequently exercised its contractual option to purchase from us, on the same terms and conditions. | |
| • | Exploration costs include the costs of geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions, and the cost of retaining undeveloped leaseholds. |
149
Table of Contents
| • | Development costs include costs incurred to gain access to and prepare development well locations for drilling and to drill and equip wells in our development basins. |
Results
of Operations
| For The Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Revenues:
|
||||||||||||
|
Oil and gas revenues
|
$ | 1,974 | $ | 2,699 | $ | 1,788 | ||||||
|
Other revenues
|
170 | 350 | 169 | |||||||||
|
Total revenues
|
2,144 | 3,049 | 1,957 | |||||||||
|
Costs:
|
||||||||||||
|
Production costs
|
487 | 610 | 423 | |||||||||
|
General & administrative
|
162 | 169 | 144 | |||||||||
|
Exploration expenses
|
58 | 27 | 21 | |||||||||
|
Depreciation, depletion & amortization
|
873 | 724 | 523 | |||||||||
|
Impairment of certain natural gas properties in the Arkoma basin
|
— | 143 | — | |||||||||
|
Other expenses
|
178 | 295 | 134 | |||||||||
|
Total costs
|
1,758 | 1,968 | 1,245 | |||||||||
|
Results of operations
|
386 | 1,081 | 712 | |||||||||
|
Provision for income taxes
|
(146 | ) | (406 | ) | (273 | ) | ||||||
|
Exploration and production net income
|
$ | 240 | $ | 675 | $ | 439 | ||||||
| • | Results of operations for producing activities consist of all related domestic activities within the Exploration & Production reporting unit. Amounts for 2008 exclude a $148 million gain on sale of a contractual right to a production payment on certain future international hydrocarbon production. | |
| • | Oil and gas revenues consist primarily of natural gas production sold to the Gas Marketing Services subsidiary and includes the impact of hedges, including intercompany hedges. | |
| • | Other revenues and other expenses consist of activities within the Exploration & Production segment that are not a direct part of the producing activities. These nonproducing activities include acquisition and disposition of other working interest gas and the movement of gas from the wellhead to the tailgate of the respective plants for sale to the Gas Marketing Services subsidiary or third-party purchasers. In addition, other revenues include recognition of income from transactions which transferred certain nonoperating benefits to a third party. Other expenses also include $15 million write-down of costs associated with acquired unproved reserves. | |
| • | Production costs consist of costs incurred to operate and maintain wells and related equipment and facilities used in the production of petroleum liquids and natural gas. These costs also include production taxes other than income taxes and administrative expenses in support of production activity. Excluded are depreciation, depletion and amortization of capitalized costs. | |
| • | Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes, and the cost of retaining undeveloped leaseholds including lease amortization and impairments. | |
| • | Depreciation, depletion and amortization includes depreciation of support equipment. Additionally, 2009 includes $17 million additional depreciation, depletion and amortization as a result of our recalculation of fourth quarter depreciation, depletion and amortization utilizing our year-end reserves which were lower than 2008. The lower reserves are primarily a result of the application of new rules issued by the SEC. |
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Table of Contents
Proved
Reserves
| 2009 | 2008 | 2007 | ||||||||||
| (Bcfe) | ||||||||||||
|
Proved reserves at beginning of period
|
4,339 | 4,143 | 3,701 | |||||||||
|
Revisions
|
(859 | ) | (220 | ) | (106 | ) | ||||||
|
Purchases
|
159 | 31 | 19 | |||||||||
|
Extensions and discoveries
|
1,051 | 791 | 863 | |||||||||
|
Wellhead production
|
(435 | ) | (406 | ) | (334 | ) | ||||||
|
Proved reserves at end of period
|
4,255 | 4,339 | 4,143 | |||||||||
|
Proved developed reserves at end of period
|
2,387 | 2,456 | 2,252 | |||||||||
| • | The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. | |
| • | A significant portion of the revisions for 2009 are a result of the impact of the new SEC rules. Proved reserves are lower because of the lower 12 month average, first-of-the-month price as compared to the 2008 year-end price and the revision of proved undeveloped reserve estimates based on new guidance. Approximately one-half of the revisions for 2008 relate to the impact of lower average year-end natural gas prices used in 2008 compared to the 2007. | |
| • | Extensions and discoveries in 2009 are higher this year as compared to prior years due in part to the expanded definition of oil and gas reserves supported by reliable technology and reasonable certainty used for reserves estimation. | |
| • | Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. Crude oil reserves are insignificant and have been included in the proved reserves on a basis of billion cubic feet equivalents (Bcfe). |
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The following is based on the estimated quantities of proved
reserves. During 2009 we adopted prescribed accounting revisions
associated with oil and gas authoritative guidance. Those
revisions include using the
12-month
average price computed as an unweighted arithmetic average of
the price as of the first day of each month, unless prices are
defined by contractual arrangements. These revisions are
reflected in our 2009 amounts. For the year-ended
December 31, 2009, the average natural gas equivalent price
used in the estimates was $2.76 per MMcfe. For the years ended
December 31, 2008 and 2007, the average year-end natural
gas equivalent prices used in the estimates were $4.41 and $5.78
per MMcfe, respectively. Future income tax expenses have been
computed considering applicable taxable cash flows and
appropriate statutory tax rates. The discount rate of
10 percent is as prescribed by authoritative guidance.
Continuation of year-end economic conditions also is assumed.
The calculation is based on estimates of proved reserves,
151
Table of Contents
which are revised over time as new data becomes available.
Probable or possible reserves, which may become proved in the
future, are not considered. The calculation also requires
assumptions as to the timing of future production of proved
reserves, and the timing and amount of future development and
production costs. Of the $2,833 million of future
development costs, approximately 60 percent is estimated to
be spent in 2010, 2011 and 2012.
Numerous uncertainties are inherent in estimating volumes and
the value of proved reserves and in projecting future production
rates and timing of development expenditures. Such reserve
estimates are subject to change as additional information
becomes available. The reserves actually recovered and the
timing of production may be substantially different from the
reserve estimates.
Standardized
Measure of Discounted Future Net Cash Flows
| At December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Millions) | ||||||||
|
Future cash inflows
|
$ | 11,729 | $ | 19,127 | ||||
|
Less:
|
||||||||
|
Future production costs
|
3,990 | 5,516 | ||||||
|
Future development costs
|
2,833 | 3,772 | ||||||
|
Future income tax provisions
|
1,404 | 3,284 | ||||||
|
Future net cash flows
|
3,502 | 6,555 | ||||||
|
Less 10 percent annual discount for estimated timing of
cash flows
|
(1,789 | ) | (3,382 | ) | ||||
|
Standardized measure of discounted future net cash flows
|
$ | 1,713 | $ | 3,173 | ||||
Sources
of Change in Standardized Measure of Discounted Future Net Cash
Flows
| 2009 | 2008 | 2007 | ||||||||||
| (Millions) | ||||||||||||
|
Standardized measure of discounted future net cash flows
beginning of period
|
$ | 3,173 | $ | 4,803 | $ | 2,856 | ||||||
|
Changes during the year:
|
||||||||||||
|
Sales of oil and gas produced, net of operating costs
|
(1,006 | ) | (2,091 | ) | (1,426 | ) | ||||||
|
Net change in prices and production costs
|
(3,310 | ) | (2,548 | ) | 2,019 | |||||||
|
Extensions, discoveries and improved recovery, less estimated
future costs
|
1,131 | 1,423 | 2,163 | |||||||||
|
Development costs incurred during year
|
389 | 817 | 738 | |||||||||
|
Changes in estimated future development costs
|
701 | (724 | ) | (931 | ) | |||||||
|
Purchase of reserves in place, less estimated future costs
|
171 | 55 | 48 | |||||||||
|
Revisions of previous quantity estimates
|
(923 | ) | (395 | ) | (266 | ) | ||||||
|
Accretion of discount
|
450 | 714 | 434 | |||||||||
|
Net change in income taxes
|
932 | 1,108 | (1,108 | ) | ||||||||
|
Other
|
5 | 11 | 276 | |||||||||
|
Net changes
|
(1,460 | ) | (1,630 | ) | 1,947 | |||||||
|
Standardized measure of discounted future net cash flows end of
period
|
$ | 1,713 | $ | 3,173 | $ | 4,803 | ||||||
In relation to the new SEC rules, we estimate that the
standardized measure of discounted future net cash flows
declined approximately $840 million on a before tax basis
and excluding the overall price rule impact. The significant
components of this decline include an estimated
$640 million decrease included in revisions of previous
quantity estimates and a related $430 million decrease
included in the net change in prices and production costs,
partially offset by a $210 million increase included in
extensions, discoveries and improved recovery, less estimated
future costs. Additionally, we estimate that a significant
portion of the remaining net change in price and production
costs is due to the application of the new pricing rules which
resulted in the use of lower prices at December 31, 2009
than would have resulted under the previous rules.
152
Table of Contents
THE
WILLIAMS COMPANIES, INC.
SCHEDULE II —
VALUATION AND QUALIFYING ACCOUNTS
| ADDITIONS | ||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
(Credited)
|
||||||||||||||||||||
|
Beginning
|
To Cost and
|
Ending
|
||||||||||||||||||
| Balance | Expenses | Other | Deductions | Balance | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
|
Year ended December 31, 2009:
|
||||||||||||||||||||
|
Allowance for doubtful accounts — accounts and notes
receivable(a)
|
$ | 29 | $ | 4 | $ | — | $ | 11 | (d) | $ | 22 | |||||||||
|
Deferred tax asset valuation allowance(a)
|
3 | 1 | — | — | 4 | |||||||||||||||
|
Price-risk management credit reserves — assets(a)
|
6 | (3 | )(e) | (3 | )(f) | — | — | |||||||||||||
|
Price-risk management credit reserves — liabilities(b)
|
(15 | ) | 12 | (e) | — | — | (3 | ) | ||||||||||||
|
Year ended December 31, 2008:
|
||||||||||||||||||||
|
Allowance for doubtful accounts — accounts and notes
receivable(a)
|
16 | 15 | — | 2 | (d) | 29 | ||||||||||||||
|
Deferred tax asset valuation allowance(a)
|
50 | (14 | ) | — | 33 | (d) | 3 | |||||||||||||
|
Price-risk management credit reserves — assets(a)
|
1 | 1 | (e) | 4 | (f) | — | 6 | |||||||||||||
|
Price-risk management credit reserves — liabilities(b)
|
— | (16 | )(e) | 1 | (f) | — | (15 | ) | ||||||||||||
|
Year ended December 31, 2007:
|
||||||||||||||||||||
|
Allowance for doubtful accounts — accounts and notes
receivable(a)
|
13 | 3 | — | — | 16 | |||||||||||||||
|
Deferred tax asset valuation allowance(a)
|
36 | 14 | — | — | 50 | |||||||||||||||
|
Price-risk management credit reserves — assets(a)
|
7 | (6 | )(e) | — | — | 1 | ||||||||||||||
|
Processing plant major maintenance accrual
|
8 | — | — | 8 | (c) | — | ||||||||||||||
| (a) | Deducted from related assets. | |
| (b) | Deducted from related liabilities. | |
| (c) | 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 2007 earnings, as well as the impact to prior periods, is not material. We have adopted the deferral method of accounting for these costs going forward. | |
| (d) | Represents balances written off, reclassifications, and recoveries. | |
| (e) | Included in revenues. | |
| (f) | Included in accumulated other comprehensive loss . |
153
Table of Contents
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
Disclosure
Controls and Procedures
Our management, including our Chief Executive Officer and Chief
Financial Officer, does not expect that our disclosure controls
and procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
of
the Securities Exchange Act) (Disclosure Controls) will prevent
all errors and all fraud. A control system, no matter how well
conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system
are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits
of controls must be considered relative to their costs. Because
of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all
control issues and instances of fraud, if any, within the
company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty,
and that breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more
people, or by management override of the control. The design of
any system of controls also is based in part upon certain
assumptions about the likelihood of future events, and there can
be no assurance that any design will succeed in achieving its
stated goals under all potential future conditions. Because of
the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be
detected. We monitor our Disclosure Controls and make
modifications as necessary; our intent in this regard is that
the Disclosure Controls will be modified as systems change and
conditions warrant.
An evaluation of the effectiveness of the design and operation
of our Disclosure Controls was performed as of the end of the
period covered by this report. This evaluation was performed
under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief
Financial Officer. Based upon that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that
these Disclosure Controls are effective at a reasonable
assurance level.
Management’s
Annual Report on Internal Control over Financial
Reporting
See report set forth above in Item 8, “Financial
Statements and Supplementary Data.”
Report of
Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting
See report set forth above in Item 8, “Financial
Statements and Supplementary Data.”
Changes
in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2009
that have materially affected, or are reasonably likely to
materially affect, our Internal Controls over financial
reporting.
| Item 9B. | Other Information |
None.
| Item 10. | Directors, Executive Officers and Corporate Governance |
The information regarding our directors and nominees for
director required by Item 401 of
Regulation S-K
will be presented under the heading.
“Proposal 1 — Election of Directors” in
our Proxy Statement prepared for the solicitation of proxies in
connection with our Annual Meeting of Stockholders to be held
May 20, 2010 (Proxy Statement), which information is
incorporated by reference herein.
154
Table of Contents
Information regarding our executive officers required by
Item 401(b) of
Regulation S-K
is presented at the end of Part I herein and captioned
“Executive Officers of the Registrant” as permitted by
General Instruction G(3) to
Form 10-K
and Instruction 3 to Item 401(b) of
Regulation S-K.
Information required by Item 405 of
Regulation S-K
will be included under the heading “Section 16(a)
Beneficial Ownership Reporting Compliance” in our Proxy
Statement, which information is incorporated by reference herein.
Information required by paragraphs (c)(3), (d)(4) and (d)(5) of
Item 407 of
Regulation S-K
will be included under the heading “Corporate Governance
and Board Matters” in our Proxy Statement, which
information is incorporated by reference herein.
We have adopted a Code of Ethics for Senior Officers that
applies to our Chief Executive Officer, Chief Financial Officer,
and Controller, or persons performing similar functions. The
Code of Ethics for Senior Officers, together with our Corporate
Governance Guidelines, the charters for each of our board
committees, and our Code of Business Conduct applicable to all
employees are available on our Internet website at
http://www.williams.com.
We will provide, free of charge, a copy of our Code of
Ethics or any of our other corporate documents listed above upon
written request to our Corporate Secretary at Williams, One
Williams Center, Suite 4700, Tulsa, Oklahoma 74172. We
intend to disclose any amendments to or waivers of the Code of
Ethics on behalf of our Chief Executive Officer, Chief Financial
Officer, Controller, and persons performing similar functions on
our Internet website at
http://www.williams.com
under the Investor Relations caption, promptly following the
date of any such amendment or waiver.
| Item 11. | Executive Compensation |
The information required by Item 402 and paragraphs (e)(4)
and (e)(5) of Item 407 of
Regulation S-K
regarding executive compensation will be presented under the
headings “Compensation Discussion and Analysis,”
“Executive Compensation and Other Information,” and
“Compensation Committee Report on Executive
Compensation” in our Proxy Statement, which information is
incorporated by reference herein. Notwithstanding the foregoing,
the information provided under the heading “Compensation
Committee Report on Executive Compensation” in our Proxy
Statement is furnished and shall not be deemed to be filed for
purposes of Section 18 of the Securities Exchange Act of
1934, as amended, is not subject to the liabilities of that
section and is not deemed incorporated by reference in any
filing under the Securities Act of 1933, as amended.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information regarding securities authorized for issuance
under equity compensation plans required by Item 201(d) of
Regulation S-K
and the security ownership of certain beneficial owners and
management required by Item 403 of
Regulation S-K
will be presented under the headings “Equity Compensation
Stock Plans” and “Security Ownership of Certain
Beneficial Owners and Management” in our Proxy Statement,
which information is incorporated by reference herein.
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
The information regarding certain relationships and related
transactions required by Item 404 and Item 407(a) of
Regulation S-K
will be presented under the heading “Corporate Governance
and Board Matters” in our Proxy Statement, which
information is incorporated by reference herein.
| Item 14. | Principal Accounting Fees and Services |
The information regarding our principal accounting fees and
services required by Item 9(e) of Schedule 14A will be
presented under the heading “Principal Accounting Fees and
Services” in our Proxy Statement, which information is
incorporated by reference herein.
155
| Item 15. | Exhibits, Financial Statement Schedules |
(a) 1 and 2.
| Page | ||||
|
Covered by report of independent auditors:
|
||||
|
Consolidated statement of income for each year in the three-year
period ended December 31, 2009
|
85 | |||
|
Consolidated balance sheet at December 31, 2009 and 2008
|
86 | |||
|
Consolidated statement of changes in equity for each year in the
three-year period ended December 31, 2009
|
87 | |||
|
Consolidated statement of cash flows for each year in the
three-year period ended December 31, 2009
|
88 | |||
|
Notes to consolidated financial statements
|
89 | |||
|
Schedule for each year in the three-year period ended
December 31, 2009:
|
||||
|
II — Valuation and qualifying accounts
|
153 | |||
|
Not covered by report of independent auditors:
|
||||
|
Quarterly financial data (unaudited)
|
146 | |||
|
Supplemental oil and gas disclosures (unaudited)
|
149 | |||
All other schedules have been omitted since the required
information is not present or is not present in amounts
sufficient to require submission of the schedule, or because the
information required is included in the financial statements and
notes thereto.
(a) 3 and (b). The exhibits listed below are filed as part
of this annual report.
INDEX TO
EXHIBITS
|
Exhibit No.
|
Description
|
|||
|
3.1
|
— | Restated Certificate of Incorporation, as supplemented (filed on August 6, 2009 as Exhibit 3.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
3.2
|
— | Restated By-Laws (filed on September 24, 2008 as Exhibit 3.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.1
|
— | Form of Senior Debt Indenture between Williams and Bank One Trust company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on September 8, 1997 as Exhibit 4.1 to The Williams Companies, Inc.’s Form S-3) and incorporated herein by reference. | ||
|
4.2
|
— | Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001 as Exhibit 4(k) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
4.3
|
— | Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.4
|
— | Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed February 25, 1997 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to Form S-3) and incorporated herein by reference. | ||
|
4.5
|
— | Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. |
156
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
4.6
|
— | Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. | ||
|
4.7
|
— | Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s Form 10-K for the fiscal year ended December 31, 1998) and incorporated herein by reference. | ||
|
4.8
|
— | Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000 as Exhibit 4(q) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
4.9
|
— | Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.10
|
— | Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.11
|
— | Registration Rights Agreement dated as of March 5, 2009 between The Williams Companies, Inc. and Citigroup Global Markets Inc. on behalf of themselves and the Initial Purchasers listed on Schedule I thereto (filed on March 11, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.12
|
— | Eleventh Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.13
|
— | First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.14
|
— | Fifth Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.3 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.15
|
— | Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed on September 24, 2004 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.16
|
— | Amendment No. 1 dated May 18, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on May 22, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.17
|
— | Amendment No. 2 dated October 12, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on October 15, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.18
|
— | Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee with regard to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Form S-3) and incorporated herein by reference. | ||
|
4.19
|
— | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’s Form 8-K) and incorporated herein by reference. |
157
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
4.20
|
— | Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K) (Commission File number 001-07414) and incorporated herein by reference. | ||
|
4.21
|
— | Indenture dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s Form 8-K) and incorporated herein by reference. | ||
|
4.22
|
— | Registration Rights Agreement, dated as of May 23, 2008, among Northwest Pipeline GP and Banc of America Securities, LLC, BNP Paribas Securities Corp, and Greenwich Capital Markets, Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed on May 23, 2008 as Exhibit 10.1 to Northwest Pipeline GP’s Form 8-K) and incorporated herein by reference. | ||
|
4.23
|
— | Senior Indenture dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-3) and incorporated herein by reference. | ||
|
4.24
|
— | Indenture dated as of August 27, 2001 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on November 8, 2001 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-4) and incorporated herein by reference. | ||
|
4.25
|
— | Indenture dated as of July 3, 2002 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed August 14, 2002 as Exhibit 4.1 to The Williams Companies Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.26
|
— | Indenture dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. | ||
|
4.27
|
— | Indenture dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. | ||
|
4.28
|
— | Registration Rights Agreement, dated as of May 22, 2008, among Transcontinental Gas Pipe Line Corporation and Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J.P. Morgan Securities Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed on May 23, 2008 as Exhibit 10.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. | ||
|
4.29
|
— | Indenture dated June 20, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and JPMorgan Chase Bank, N.A. (filed on June 20, 2006 as Exhibit 4.1 to Williams Partners L.P. Form 8-K) and incorporated herein by reference. | ||
|
4.30
|
— | Indenture dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Williams Partners L.P. Form 8-K) and incorporated herein by reference. | ||
|
4.31
|
— | Indenture dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.32
|
— | Registration Rights Agreement dated as of February 9, 2010, among Williams Partners L.P. and Barclays Capital Inc. and Citigroup Global Markets Inc., on behalf of themselves and the Initial Purchasers listed on Schedule I thereto (filed on February 10, 2010 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.1
|
— | The Williams Companies Amended and Restated Retirement Restoration Plan effective January 1, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference.. |
158
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
10.2
|
— | The Williams Companies, Inc. 1996 Stock Plan (filed on March 27, 1996 as Exhibit A to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
|
10.3
|
— | The Williams Companies, Inc. 1996 Stock Plan for Non-employee Directors (filed on March 27, 1996 as Exhibit B to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
|
10.4
|
— | Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.5*
|
— | Form of 2010 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
|
10.6*
|
— | Form of 2010 Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
|
10.7*
|
— | Form of 2010 Nonqualified Stock Option Agreement among Williams and certain employees and officers. | ||
|
10.8*
|
— | Form of 2009 Restricted Stock Unit Agreement among Williams and non-management directors. | ||
|
10.9
|
— | The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed on August 5, 2004 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.10
|
— | Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.11 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.11
|
— | Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.12 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.12
|
— | The Williams Companies, Inc. 2007 Incentive Plan (filed on April 10, 2007 as Appendix C to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
|
10.13
|
— | Amendment No. 1 to The Williams Companies, Inc. 2007 Incentive Plan (filed on February 25, 2009 as Exhibit 10.14 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.14
|
— | The Williams Companies, Inc. Employee Stock Purchase Plan (filed on April 10, 2007 as Appendix D to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
|
10.15
|
— | Amendment No. 1 to The Williams Companies, Inc. Employee Stock Purchase (filed on February 25, 2009 as Exhibit 10.16 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference Plan . | ||
|
10.16
|
— | Amendment No. 2 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2009 as Exhibit 10.17 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.17*
|
— | Amendment No. 3 to The Williams Companies, Inc. Employee Stock Purchase Plan. | ||
|
10.18
|
— | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (filed on February 25, 2009 as Exhibit 10.18 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference . | ||
|
10.19
|
— | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on May 15, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. |
159
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
10.20
|
— | Amendment Agreement dated November 21, 2007 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline GP, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on November 28, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.21
|
— | Credit Agreement dated as of May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers and Citibank, N.A., as Administrative Agent (filed on May 1, 2006 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.22
|
— | U.S. $500,000,000 Five Year Credit Agreement dated September 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders, the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A., as Agent (filed on September 26, 2005 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.23
|
— | U.S. $200,000,000 Five Year Credit Agreement dated September 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders, the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A., as Agent (filed on September 26, 2005 as Exhibit 10.2 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.24
|
— | Master Professional Services Agreement dated as of June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation (filed on August 5, 2004 as Exhibit 10.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.25
|
— | Amendment No. 1 to the Master Professional Services Agreement dated June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation made as of June 1, 2004 (filed on August 5, 2004 as Exhibit 10.3 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.26
|
— | Purchase and Sale Agreement, dated November 16, 2006, by and among Williams Energy Services, LLC, Williams Field Services Group, LLC, Williams Field Services Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams Partners Operating, LLC (filed on November 21, 2006 as Exhibit 2.1 to Williams Partners L.P.’s Form 8-K) and incorporated herein by reference. | ||
|
10.27
|
— | Credit Agreement dated February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on February 28, 2007 as Exhibit 10.41 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.28
|
— | Asset Purchase Agreement between Williams Power Company, Inc. and Bear Energy LP dated May 20, 2007 (filed on May 22, 2007 as Exhibit 99.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.29
|
— | Credit Agreement dated as of December 11, 2007, by and among Williams Partners L.P., the lenders party hereto, Citibank, N.A., as Administrative Agent and Issuing Bank, and The Bank of Nova Scotia, as Swingline Lender (filed on December 17, 2007 as Exhibit 10.5 to Williams Partners L.P. Form 8-K) and incorporated herein by reference. | ||
|
10.30
|
— | Contribution Conveyance and Assumption Agreement, dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC, Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC Holdings LLC and Williams Pipeline Services Company (filed on January 30, 2008 as Exhibit 10.2 to 1 to Williams Pipeline Partners L.P.’s Form 8-K) and incorporated herein by reference. |
160
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
10.31
|
— | Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to The Williams Companies Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.32
|
— | Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed on February 22, 2010 as Exhibit 10.5 to Williams Partners L.P.’s current report on Form 8-K) and incorporated herein by reference. | ||
|
12*
|
— | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. | ||
|
14
|
— | Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
21*
|
— | Subsidiaries of the registrant. | ||
|
23.1*
|
— | Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. | ||
|
23.2*
|
— | Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | ||
|
23.3*
|
— | Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
24*
|
— | Power of Attorney. | ||
|
31.1*
|
— | Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
31.2*
|
— | Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
32*
|
— | Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
|
99.1*
|
— | Report of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | ||
|
99.2*
|
— | Report of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
101.INS**
|
— | XBRL Instance Document | ||
|
101.SCH**
|
— | XBRL Taxonomy Extension Schema | ||
|
101.CAL**
|
— | XBRL Taxonomy Extension Calculation Linkbase | ||
|
101.DEF**
|
— | XBRL Taxonomy Extension Definition Linkbase | ||
|
101.LAB**
|
— | XBRL Taxonomy Extension Label Linkbase | ||
|
101.PRE**
|
— | XBRL Taxonomy Extension Presentation Linkbase |
| * | Filed herewith |
| ** | Furnished herewith |
161
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
The Williams Companies,
Inc.
(Registrant)
(Registrant)
| By: |
/s/
Ted
T. Timmermans
|
Ted T. Timmermans
Controller
Date: February 25, 2010
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
Signature
|
Title
|
Date
|
||||
|
/s/
Steven
J. Malcolm
|
President, Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | February 25, 2010 | ||||
|
/s/
Donald
R. Chappel
|
Senior Vice President and Chief Financial Officer (Principal Financial Officer) | February 25, 2010 | ||||
|
/s/
Ted
T. Timmermans
|
Controller (Principal Accounting Officer) | February 25, 2010 | ||||
|
/s/
Joseph
R. Cleveland*
|
Director | February 25, 2010 | ||||
|
/s/
Kathleen
B. Cooper*
|
Director | February 25, 2010 | ||||
|
/s/
Irl
F. Engelhardt*
|
Director | February 25, 2010 | ||||
|
/s/
William
R. Granberry*
|
Director | February 25, 2010 | ||||
|
/s/
William
E. Green*
|
Director | February 25, 2010 | ||||
|
/s/
Juanita
H. Hinshaw*
|
Director | February 25, 2010 | ||||
|
/s/
W.R.
Howell*
|
Director | February 25, 2010 | ||||
162
Table of Contents
|
Signature
|
Title
|
Date
|
||||
|
/s/
George
A. Lorch*
|
Director | February 25, 2010 | ||||
|
/s/
William
G. Lowrie*
|
Director | February 25, 2010 | ||||
|
/s/
Frank
T. MacInnis*
|
Director | February 25, 2010 | ||||
|
/s/
Janice
D. Stoney*
|
Director | February 25, 2010 | ||||
| *By: |
/s/
La
Fleur C. Browne
Attorney-in-Fact |
February 25, 2010 | ||||
163
Table of Contents
INDEX TO
EXHIBITS
|
Exhibit No.
|
Description
|
|||
|
3.1
|
— | Restated Certificate of Incorporation, as supplemented (filed on August 6, 2009 as Exhibit 3.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
3.2
|
— | Restated By-Laws (filed on September 24, 2008 as Exhibit 3.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.1
|
— | Form of Senior Debt Indenture between Williams and Bank One Trust company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on September 8, 1997 as Exhibit 4.1 to The Williams Companies, Inc.’s Form S-3) and incorporated herein by reference. | ||
|
4.2
|
— | Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001 as Exhibit 4(k) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
4.3
|
— | Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.4
|
— | Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed February 25, 1997 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to Form S-3) and incorporated herein by reference. | ||
|
4.5
|
— | Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. | ||
|
4.6
|
— | Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. | ||
|
4.7
|
— | Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s Form 10-K for the fiscal year ended December 31, 1998) and incorporated herein by reference. | ||
|
4.8
|
— | Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000 as Exhibit 4(q) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
4.9
|
— | Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.10
|
— | Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.11
|
— | Registration Rights Agreement dated as of March 5, 2009 between The Williams Companies, Inc. and Citigroup Global Markets Inc. on behalf of themselves and the Initial Purchasers listed on Schedule I thereto (filed on March 11, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.12
|
— | Eleventh Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.13
|
— | First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. |
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
4.14
|
— | Fifth Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.3 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.15
|
— | Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed on September 24, 2004 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.16
|
— | Amendment No. 1 dated May 18, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on May 22, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.17
|
— | Amendment No. 2 dated October 12, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on October 15, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.18
|
— | Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee with regard to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Form S-3) and incorporated herein by reference. | ||
|
4.19
|
— | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’s Form 8-K) and incorporated herein by reference. | ||
|
4.20
|
— | Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K) (Commission File number 001-07414) and incorporated herein by reference. | ||
|
4.21
|
— | Indenture dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s Form 8-K) and incorporated herein by reference. | ||
|
4.22
|
— | Registration Rights Agreement, dated as of May 23, 2008, among Northwest Pipeline GP and Banc of America Securities, LLC, BNP Paribas Securities Corp, and Greenwich Capital Markets, Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed on May 23, 2008 as Exhibit 10.1 to Northwest Pipeline GP’s Form 8-K) and incorporated herein by reference. | ||
|
4.23
|
— | Senior Indenture dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-3) and incorporated herein by reference. | ||
|
4.24
|
— | Indenture dated as of August 27, 2001 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on November 8, 2001 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-4) and incorporated herein by reference. | ||
|
4.25
|
— | Indenture dated as of July 3, 2002 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed August 14, 2002 as Exhibit 4.1 to The Williams Companies Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.26
|
— | Indenture dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. | ||
|
4.27
|
— | Indenture dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. | ||
|
4.28
|
— | Registration Rights Agreement, dated as of May 22, 2008, among Transcontinental Gas Pipe Line Corporation and Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J.P. Morgan Securities Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed on May 23, 2008 as Exhibit 10.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. |
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
4.29
|
— | Indenture dated June 20, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and JPMorgan Chase Bank, N.A. (filed on June 20, 2006 as Exhibit 4.1 to Williams Partners L.P. Form 8-K) and incorporated herein by reference. | ||
|
4.30
|
— | Indenture dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Williams Partners L.P. Form 8-K) and incorporated herein by reference. | ||
|
4.31
|
— | Indenture dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.32
|
— | Registration Rights Agreement dated as of February 9, 2010, among Williams Partners L.P. and Barclays Capital Inc. and Citigroup Global Markets Inc., on behalf of themselves and the Initial Purchasers listed on Schedule I thereto (filed on February 10, 2010 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.1
|
— | The Williams Companies Amended and Restated Retirement Restoration Plan effective January 1, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference.. | ||
|
10.2
|
— | The Williams Companies, Inc. 1996 Stock Plan (filed on March 27, 1996 as Exhibit A to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
|
10.3
|
— | The Williams Companies, Inc. 1996 Stock Plan for Non-employee Directors (filed on March 27, 1996 as Exhibit B to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
|
10.4
|
— | Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.5*
|
— | Form of 2010 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
|
10.6*
|
— | Form of 2010 Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
|
10.7*
|
— | Form of 2010 Nonqualified Stock Option Agreement among Williams and certain employees and officers. | ||
|
10.8*
|
— | Form of 2009 Restricted Stock Unit Agreement among Williams and non-management directors. | ||
|
10.9
|
— | The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed on August 5, 2004 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.10
|
— | Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.11 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.11
|
— | Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.12 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.12
|
— | The Williams Companies, Inc. 2007 Incentive Plan (filed on April 10, 2007 as Appendix C to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
|
10.13
|
— | Amendment No. 1 to The Williams Companies, Inc. 2007 Incentive Plan (filed on February 25, 2009 as Exhibit 10.14 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.14
|
— | The Williams Companies, Inc. Employee Stock Purchase Plan (filed on April 10, 2007 as Appendix D to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
|
10.15
|
— | Amendment No. 1 to The Williams Companies, Inc. Employee Stock Purchase (filed on February 25, 2009 as Exhibit 10.16 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference Plan . |
Table of Contents
|
Exhibit No.
|
Description
|
|||
|
10.16
|
— | Amendment No. 2 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2009 as Exhibit 10.17 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.17*
|
— | Amendment No. 3 to The Williams Companies, Inc. Employee Stock Purchase Plan. | ||
|
10.18
|
— | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (filed on February 25, 2009 as Exhibit 10.18 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference . | ||
|
10.19
|
— | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on May 15, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.20
|
— | Amendment Agreement dated November 21, 2007 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline GP, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on November 28, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.21
|
— | Credit Agreement dated as of May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers and Citibank, N.A., as Administrative Agent (filed on May 1, 2006 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.22
|
— | U.S. $500,000,000 Five Year Credit Agreement dated September 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders, the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A., as Agent (filed on September 26, 2005 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.23
|
— | U.S. $200,000,000 Five Year Credit Agreement dated September 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders, the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A., as Agent (filed on September 26, 2005 as Exhibit 10.2 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.24
|
— | Master Professional Services Agreement dated as of June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation (filed on August 5, 2004 as Exhibit 10.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.25
|
— | Amendment No. 1 to the Master Professional Services Agreement dated June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation made as of June 1, 2004 (filed on August 5, 2004 as Exhibit 10.3 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.26
|
— | Purchase and Sale Agreement, dated November 16, 2006, by and among Williams Energy Services, LLC, Williams Field Services Group, LLC, Williams Field Services Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams Partners Operating, LLC (filed on November 21, 2006 as Exhibit 2.1 to Williams Partners L.P.’s Form 8-K) and incorporated herein by reference. | ||
|
10.27
|
— | Credit Agreement dated February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on February 28, 2007 as Exhibit 10.41 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.28
|
— | Asset Purchase Agreement between Williams Power Company, Inc. and Bear Energy LP dated May 20, 2007 (filed on May 22, 2007 as Exhibit 99.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. |
Table of Contents
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Exhibit No.
|
Description
|
|||
|
10.29
|
— | Credit Agreement dated as of December 11, 2007, by and among Williams Partners L.P., the lenders party hereto, Citibank, N.A., as Administrative Agent and Issuing Bank, and The Bank of Nova Scotia, as Swingline Lender (filed on December 17, 2007 as Exhibit 10.5 to Williams Partners L.P. Form 8-K) and incorporated herein by reference. | ||
|
10.30
|
— | Contribution Conveyance and Assumption Agreement, dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC, Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC Holdings LLC and Williams Pipeline Services Company (filed on January 30, 2008 as Exhibit 10.2 to 1 to Williams Pipeline Partners L.P.’s Form 8-K) and incorporated herein by reference. | ||
|
10.31
|
— | Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to The Williams Companies Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.32
|
— | Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed on February 22, 2010 as Exhibit 10.5 to Williams Partners L.P.’s current report on Form 8-K) and incorporated herein by reference. | ||
|
12*
|
— | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. | ||
|
14
|
— | Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
21*
|
— | Subsidiaries of the registrant. | ||
|
23.1*
|
— | Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. | ||
|
23.2*
|
— | Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | ||
|
23.3*
|
— | Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
24*
|
— | Power of Attorney. | ||
|
31.1*
|
— | Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
31.2*
|
— | Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
32*
|
— | Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
|
99.1*
|
— | Report of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | ||
|
99.2*
|
— | Report of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
101.INS**
|
— | XBRL Instance Document | ||
|
101.SCH**
|
— | XBRL Taxonomy Extension Schema | ||
|
101.CAL**
|
— | XBRL Taxonomy Extension Calculation Linkbase | ||
|
101.DEF**
|
— | XBRL Taxonomy Extension Definition Linkbase | ||
|
101.LAB**
|
— | XBRL Taxonomy Extension Label Linkbase | ||
|
101.PRE**
|
— | XBRL Taxonomy Extension Presentation Linkbase |
| * | Filed herewith |
| ** | Furnished herewith |
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. Submission Of Matters To A Vote Of Security HoldersPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataNote 1. Description Of Business, Basis Of Presentation, and Summary Of Significant Accounting PoliciesNote 2. Discontinued OperationsNote 3. Investing ActivitiesNote 4. Asset Sales, Impairments and Other AccrualsNote 5. Provision For Income TaxesNote 6. Earnings Per Common Share From Continuing OperationsNote 7. Employee Benefit PlansNote 8. InventoriesNote 9. Property, Plant and EquipmentNote 10. Accounts Payable and Accrued LiabilitiesNote 11. Debt, Leases and Banking ArrangementsNote 12. Stockholders EquityNote 13. Stock-based CompensationNote 14. Fair Value MeasurementsNote 15. Financial Instruments, Derivatives, Guarantees and Concentration Of Credit RiskNote 16. Contingent Liabilities and CommitmentsNote 17. Accumulated Other Comprehensive LossNote 18. Segment DisclosuresNote 19. Subsequent EventsItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits, Financial Statement Schedules