(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, 2008 | ||
or
|
||
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
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) |
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 |
Large accelerated filer
þ
|
Accelerated filer o |
Non-accelerated
filer
o
(Do not check if a smaller reporting company) |
Smaller reporting company o |
i
ii
Item 1.
Business
1
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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 also includes
Williams Partners L.P. (WPZ), our master limited partnership
formed in 2005.
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.
2
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2008
2007
2006
(Bcfe)
2,456
2,252
1,945
1,883
1,891
1,756
4,339
4,143
3,701
Expanding the definition of oil and gas reserves and providing
clarification of certain concepts and technologies used in the
reserve estimation process.
Allowing optional disclosure of probable and possible reserves
and permitting optional disclosure of price sensitivity analysis.
Modifying prices used to estimate reserves for SEC disclosure
purposes to a
12-month
average price instead of a
single-day,
period-end
price.
Requiring 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.
3
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Wells
Wells
Wells
Wells
Wellhead
Proved
% of Total
Drilled
Drilled
Producing
Producing
Production
Reserves
Proved
(Gross)
(Operated)
(Gross)
(Net)
(Net Bcfe)
(Bcfe)
Reserves
687
646
3,163
2,894
238
3,095
71
%
95
37
3,129
852
55
523
12
%
703
366
5,407
2,465
84
390
9
%
82
76
672
434
25
224
5
%
220
0
611
21
4
107
3
%
1,787
1,125
12,982
6,666
406
4,339
100
%
Gross Acres
Net Acres
981,853
512,896
1,269,350
661,568
4
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Gross Wells
Net Wells
1,783
1,050
1,590
904
1,783
954
1,782
1,050
1,581
899
1,770
948
2008
2007
2006
400.4
333.1
274.4
$
1.26
$
0.98
$
1.02
$
6.39
$
4.92
$
5.24
$
0.09
$
0.16
$
(0.73
)
5
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6
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2008
2007
2006
(In trillion British
Thermal Units)
753
839
795
969
875
817
1,722
1,714
1,612
188
190
247
1,910
1,904
1,859
5.2
5.2
5.1
6.8
6.6
6.6
7
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8
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2008
2007
2006
(In trillion British
Thermal Units)
781
757
676
2.1
2.1
1.8
2.5
2.5
2.5
.7
.8
.9
(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.
9
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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.
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.
10
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Approximately 3,500 miles of gathering pipelines 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.
Approximately 3,800 miles of gathering pipelines 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;
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 the steam generated by
gas-driven turbines to produce approximately 60 mega-watts per
day of electricity which we primarily sell into the local
electrical grid.
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
new Willow Creek processing plant (see expansion projects below)
will process gas flowing through the Parachute Lateral in
addition to processing gas from other sources. In an arrangement
approved by the FERC, Midstream is leasing the
11
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pipeline to Gas Pipeline, who will continue to operate the
Parachute Lateral until completion of a planned FERC abandonment
filing;
PGX pipeline delivering NGLs previously transported by truck
from Exploration & Productions existing
Parachute area processing plants to a major NGL transportation
pipeline system.
The Willow Creek processing plant is a
450 MMcf/d
cryogenic natural gas processing plant in western
Colorados Piceance Basin, where Exploration &
Production has its most significant volume of natural gas
production, reserves and development activity. The plant is
designed to recover 25 Mbbls/d of NGLs and the plants
inlet processing capacity is expected to be full at
start-up
expected in late 2009.
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 Springs capacities in both
cases. We expect to begin construction on the fourth train at
Echo Springs during the second half of 2009 and to bring the
additional capacity online during late 2010, subject to all
applicable permitting.
Over 700 miles of onshore and offshore natural gas
gathering pipelines, 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;
The
139-mile
Canyon Chief gas pipeline, now including the new
37-mile
Blind Faith extension, 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, Markham, and Cameron Meadows processing plants with
a combined daily inlet capacity of nearly
1,500 MMcf/d
and NGL handling capacity of 65 Mbbls/d;
Canyon Station offshore gas production system fixed-leg
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 300 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 ExxonMobils 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
ChevronTexacos Empire Terminal in Plaquemines Parish,
Louisiana;
Devils Tower floating 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
worlds deepest dry tree
12
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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.
In the deepwater of the Gulf of Mexico, we completed
construction of
37-mile
extensions of both of our oil and gas pipelines from our Devils
Tower spar to the Blind Faith discovery located in Mississippi
Canyon in the eastern deepwater of the Gulf of Mexico. The
pipelines have been commissioned and production began flowing in
the fourth quarter of 2008;
In the western deepwater of the Gulf of Mexico, we continued
construction activities on our Perdido Norte project which will
include an expansion of our onshore Markham gas processing
facility and oil and gas lines that would expand the scale of
our existing infrastructure.
13
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2008
2007
2006
1,013
1,045
1,181
1,311
1,275
1,222
154
163
152
80
92
88
70
80
86
7
9
8
1,605
1,401
988
(1)
Excludes volumes associated with partially owned assets that are
not consolidated for financial reporting purposes.
(2)
Annual Average Mbbls/d.
14
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15
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Costs of providing service, including depreciation expense;
Allowed rate of return, including the equity component of the
capital structure and related income taxes; and
Volume throughput assumptions.
16
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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; and
Blowouts, cratering and explosions.
17
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18
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Item 1A.
Risk
Factors
FOR PURPOSES OF THE SAFE HARBOR PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
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 NGL prices and demand.
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 costs of capital;
Inflation, interest rates, fluctuation in foreign exchange, and
general economic conditions (including the recent economic
slowdown and the disruption of 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;
19
Table of Contents
Our costs and funding obligations for defined benefit pension
plans and other postretirement benefit plans;
Changes in the current geopolitical situation;
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 and
Additional risks described in our filings with the SEC.
20
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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; and
Compliance with environmental and other governmental
requirements.
21
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22
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Fires, blowouts, cratering and explosions;
Uncontrollable releases of oil, natural gas or well fluids;
Pollution and other environmental risks;
Natural disasters;
Aging infrastructure;
Damage inadvertently caused by third party activity, such as
operation of construction equipment; and
Terrorist attacks or threatened attacks on our facilities or
those of other energy companies.
23
Table of Contents
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; and
The ability to access capital markets to fund construction
projects.
24
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25
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Production is less than expected;
The hedging instrument is not perfectly effective in mitigating
the risk being hedged; and
The counterparties to our hedging arrangements fail to honor
their financial commitments.
26
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27
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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; and
The overall health of the energy industry, including the
bankruptcy or insolvency of other companies.
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;
28
Table of Contents
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; and
The adoption of regulations or legislation relating to climate
change.
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; and
Market manipulation in connection with interstate sales,
purchases or transportation of natural gas.
29
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30
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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; and
The effects of state regulation on customer contracting
practices.
31
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32
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Item 1B.
Unresolved
Staff Comments
Item 2.
Properties
Item 3.
Legal
Proceedings
Item 4.
Submission
of Matters to a Vote of Security Holders
Alan S. Armstrong
Senior Vice President, Midstream
Age: 46
Position held since February 2002.
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 of Williams
Partners GP LLC, the general partner of Williams Partners L.P.
James J. Bender
Senior Vice President and General Counsel
Age: 52
Position held since December 2002.
33
Table of Contents
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.
Donald R. Chappel
Senior Vice President and Chief Financial Officer
Age: 57
Position held since April 2003.
Prior to joining us, Mr. Chappel held various financial,
administrative and operational leadership positions.
Mr. Chappel serves as a director of Williams Partners GP
LLC, the general partner of Williams Partners L.P., and as 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: 53
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: 49
Position held since December 1998.
Mr. Hill 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 Argentina Inc.
Steven J. Malcolm
Chairman of the Board, Chief Executive Officer and President
Age: 60
Position held since September 2001.
From May 2001 to September 2001, Mr. Malcolm was Executive
Vice President of the Company. He was President and Chief
Executive Officer of our subsidiary Williams Energy Services,
LLC from December 1998 to May 2001 and Senior Vice President and
General Manager of our subsidiary, Williams Field Services
Company from November 1994 to December 1998. Mr. Malcolm
serves as a director of Williams Partners GP LLC, the general
partner of Williams Partners L.P., Williams Pipeline GP LLC, the
general partner of Williams Pipeline Partners L.P., BOK
Financial Corporation and the Bank of Oklahoma, N.A.
Phillip D. Wright
Senior Vice President, Gas Pipeline
Age: 53
Position held since January 2005.
From October 2002 to January 2005, Mr. Wright 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 has held various positions with us since 1989.
Mr. Wright serves as a director of Williams Pipeline GP
LLC, the general partner of Williams Pipeline Partners L.P.
34
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118
119
Item 5.
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
2008
2007
High
Low
Dividend
High
Low
Dividend
$
36.99
$
30.96
$
.10
$
28.94
$
25.32
$
.09
$
40.31
$
33.65
$
.11
$
32.43
$
28.20
$
.10
$
39.90
$
21.85
$
.11
$
34.72
$
30.08
$
.10
$
22.50
$
12.13
$
.11
$
37.16
$
33.68
$
.10
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2003
2004
2005
2006
2007
2008
100.0
166.9
240.2
274.7
380.9
156.8
100.0
110.9
116.3
134.7
142.1
89.5
100.0
130.9
173.3
200.9
238.2
145.5
36
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Item 6.
Selected
Financial Data
2008
2007
2006
2005
2004
(Millions, except per-share amounts)
$
12,352
$
10,486
$
9,299
$
9,690
$
8,343
1,334
847
347
473
149
84
143
(38
)
(157
)
15
(2
)
2.26
1.40
.57
.79
.28
.14
.23
(.06
)
(.26
)
.03
26,006
25,061
25,402
29,443
23,993
196
143
392
123
250
7,683
7,757
7,622
7,591
7,712
8,440
6,375
6,073
5,427
4,956
.43
.39
.345
.25
.08
(1)
Prior period amounts reported for Exploration &
Production have been adjusted to reflect the presentation of
certain revenues and costs on a net basis. These adjustments
reduced
revenues
and reduced
costs and operating
expenses
by the same amount, with no net impact on segment
profit. The reductions were $72 million in 2007,
$77 million in 2006, $91 million in 2005 and
$65 million in 2004.
(2)
See Note 4 of Notes to Consolidated Financial Statements
for discussion of asset sales, impairments, and other accruals
in 2008, 2007, and 2006. 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. Income from continuing operations
for 2004 includes $94 million of income from a favorable
arbitration award and $282 million of early debt retirement
costs.
(3)
See Note 2 of Notes to Consolidated Financial Statements
for the analysis of the 2008, 2007, and 2006 income (loss) from
discontinued operations. The discontinued operations results for
2005 includes our former power business while 2004 includes the
power business, the Canadian straddle plants, and the Alaska
refining, retail, and pipeline operations.
(4)
The 2005
cumulative effect of change in accounting principles
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).
37
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Item 7.
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
Objectives
Highlights
Continuing to improve both
EVA
®
and segment profit.
2008 segment profit of $2.9 billion, an increase of $749
million from 2007, contributed to improving our
EVA
®
.
Continuing to increase natural gas production and reserves.
We invested $2.5 billion in capital expenditures in Exploration
& Production, increasing average daily domestic production
by approximately 20 percent over last year while adding 602
billion cubic feet equivalent in net reserves. Total year-end
2008 proved domestic natural gas reserves are 4.3 trillion cubic
feet equivalent, up 5 percent from year-end 2007 reserves.
Increasing the scale of our gathering and processing business in
key growth basins.
We invested $608 million in capital expenditures in Midstream,
primarily Deepwater Gulf expansion projects and gas-processing
capacity in the western United States.
Continue to invest in expansion projects on our interstate
natural gas pipelines.
We invested $306 million in capital expenditures in Gas Pipeline
during 2008.
Strong earnings from Gas Pipeline, which benefited from new
rates enacted during 2007, and the nature of its contracts;
Hedge positions 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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Continuing to invest our gathering and processing and interstate
natural gas pipeline systems, primarily through the completion
of projects currently underway;
Continuing to invest in our natural gas production development,
although at a lower level than in recent years;
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.
Lower than anticipated commodity prices;
39
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Lower than expected levels of cash flow from operations;
Availability of capital;
Counterparty credit and performance risk;
Decreased drilling success at Exploration & Production;
Decreased drilling success or abandonment of projects by third
parties served by Midstream and Gas Pipeline;
Additional general economic, financial markets, or industry
downturn;
Changes in the political and regulatory environments;
Exposure associated with our efforts to resolve regulatory and
litigation issues (see Note 16 of Notes to Consolidated
Financial Statements).
Expanding the definition of oil and gas reserves and providing
clarification of certain concepts and technologies used in the
reserve estimation process.
Allowing optional disclosure of probable and possible reserves
and permitting optional disclosure of price sensitivity analysis.
Modifying prices used to estimate reserves for SEC disclosure
purposes to a
12-month
average price instead of a
single-day,
period-end price.
Requiring 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.
40
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41
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The testing for recoverability of a significant long-lived asset
group within the reporting unit;
Recent operating losses or negative cash flows at the reporting
unit level;
A decline in natural gas prices or reserve quantities;
Not meeting internal forecasts, or downward adjustments to
future forecasts;
A decline in enterprise market capitalization below our
consolidated stockholders equity;
Industry trends.
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.
42
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Consolidated Statement of Income
Consolidated Balance Sheet
Drivers
Impact
Drivers
Impact
Realizations
Less Volatility
None
No Impact
Realizations & Ineffectiveness
Less Volatility
Fair Value Changes
More Volatility
Fair Value Changes
More Volatility
Fair Value Changes
More Volatility
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.
43
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44
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Benefit Expense
Benefit Obligation
One-Percentage-
One-Percentage-
One-Percentage-
One-Percentage-
Point Increase
Point Decrease
Point Increase
Point Decrease
(Millions)
$
(13
)
$
14
$
(133
)
$
154
(7
)
7
3
(3
)
17
(17
)
(2
)
2
(32
)
37
(1
)
1
8
(6
)
53
(42
)
45
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Years Ended December 31,
$ Change
% Change
$ Change
% Change
from
from
from
from
2008
2007*
2007*
2007
2006*
2006*
2006
(Millions)
(Millions)
(Millions)
$
12,352
+1,866
+18
%
$
10,486
+1,187
+13
%
$
9,299
9,156
−1,149
−14
%
8,007
−518
−7
%
7,489
504
−33
−7
%
471
−82
−21
%
389
(82
)
+64
NM
(18
)
+52
NM
34
149
+12
+7
%
161
−29
−22
%
132
+167
+100
%
167
9,727
8,621
8,211
2,625
1,865
1,088
(594
)
+59
+9
%
(653
)
(653
)
191
−66
−26
%
257
+89
+53
%
168
(1
)
+18
+95
%
(19
)
+12
+39
%
(31
)
(174
)
−84
−93
%
(90
)
−50
−125
%
(40
)
−11
−100
%
11
−15
−58
%
26
2,047
1,371
558
713
−189
−36
%
524
−313
−148
%
211
1,334
847
347
84
−59
−41
%
143
+181
NM
(38
)
$
1,418
$
990
$
309
*
+ = Favorable change to
net income
; =
Unfavorable change to
net income
; NM = A percentage
calculation is not meaningful due to change in signs, a
zero-value denominator, or a percentage change greater than 200.
47
Table of Contents
Gain of $148 million on the sale of a contractual right to
a production payment on certain future international hydrocarbon
production at Exploration & Production;
Net gains of $49 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.
Income of $18 million associated with payments received for
a terminated firm transportation agreement on Northwest
Pipelines 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 Services;
Expense of $10 million related to an impairment of the
Carbonate Trend pipeline at Midstream.
48
Table of Contents
A $73 million accrual for a Gulf Liquids litigation
contingency;
Income of $9 million due to a settlement of an
international contract dispute at Midstream.
A $27 million increase in interest income primarily
associated with larger cash and cash equivalent balances
combined with slightly higher rates of return in 2007 compared
to 2006;
Increased equity earnings of $38 million due largely to
increased earnings of our Gulfstream Natural Gas System, L.L.C.
(Gulfstream), Discovery Producer Services LLC (Discovery) and
Aux Sable Liquid Products, L.P. (Aux Sable) investments;
49
Table of Contents
The absence of a $16 million impairment in 2006 of a
Venezuelan cost-based investment at Exploration &
Production;
$14 million of gains from sales of cost-based investments
in 2007.
Benefited from increased domestic net realized average prices
for the total year of 2008, which increased by approximately
28 percent compared to 2007. The domestic net realized
average price for 2008 was $6.48 per thousand cubic feet of gas
equivalent (Mcfe) compared to $5.08 per Mcfe in 2007. Net
realized average prices include market prices, net of fuel and
shrink and hedge positions, less gathering and transportation
expenses. The domestic net realized average price for the fourth
quarter 2008 was $4.43 per Mcfe reflecting the significant
decline in natural gas prices.
Increased average daily domestic production levels by
approximately 20 percent compared to 2007. The average
daily domestic production for 2008 was approximately
1,094 million cubic feet of gas equivalent (MMcfe) compared
to 913 MMcfe in 2007. The increased production is primarily
due to increased development within the Piceance, Powder River,
and Fort Worth basins.
Drilled 1,783 gross domestic development wells in 2008 with
a success rate of approximately 99 percent. This
contributed to total net additions of 602 billion cubic
feet equivalent (Bcfe) in net reserves a replacement
rate for our domestic production of 148 percent. Capital
expenditures for domestic drilling, development, and acquisition
activity in 2008 were approximately $2.5 billion compared
to $1.7 billion in
50
Table of Contents
2007. Capital expenditures for 2008 include acquisitions in the
Piceance and Fort Worth basins discussed in
Significant
events
below.
Continuing our development drilling program in the Piceance,
Fort Worth, Powder River and San Juan basins through
our planned capital expenditures projected between
$950 million and $1.05 billion.
Slight growth in our annual average daily domestic production
level compared to 2008, with fourth quarter 2009 volumes likely
to be less than the prior comparable period.
Declines in the costs of services and materials associated with
development activities as demand for these resources decline.
However, in the first quarter of 2009, we estimate we will incur
between $25 million and $35 million in expense from
contract penalties associated with the reduction in drilling
rigs deployed.
51
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Price ($/Mcf)
Volume
Floor-Ceiling for
(MMcf/d)
Collars
150
$
6.11 - $9.04
245
$
6.58 - $9.62
95
$
7.08 - $9.73
106
$3.67
2008
2007
2006
Price ($/Mcf)
Price ($/Mcf)
Price ($/Mcf)
Volume
Floor-Ceiling for
Volume
Floor-Ceiling for
Volume
Floor-Ceiling for
(MMcf/d)
Collars
(MMcf/d)
Collars
(MMcf/d)
Collars
15
$6.50 - $8.25
49
$6.50 - $8.25
15
$7.00 - $9.00
170
$6.16 - $9.14
50
$5.65 -$7.45
50
$6.05 - $7.90
202
$6.35 - $8.96
130
$5.98 - $9.63
63
$7.02 - $9.72
76
$6.82 -$10.77
70
$3.97
172
$3.90
299
$3.82
Years Ended December 31,
2008
2007
2006
(Millions)
$
3,121
$
2,021
$
1,411
$
1,260
$
756
$
552
$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,
52
Table of Contents
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 sold on behalf of 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.
$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 on behalf of certain outside
parties, which is offset by a similar increase in
segment
revenues
.
$143 million of property impairments in 2008 in the Arkoma
basin as previously discussed.
$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 previously discussed.
$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.
$487 million, or 39 percent, increase in domestic
production revenues reflecting $264 million associated with
a 21 percent increase in production volumes sold and
$223 million associated with a 15 percent increase in
net realized average prices. The increase in production volumes
reflects an increase in the number of producing wells primarily
from the Piceance and Powder River basins. The impact of hedge
positions on increased net realized average prices includes both
the expiration of a portion of fixed-price hedges that are lower
than the current market prices and higher than current market
prices related to basin-specific collars entered into during the
period. Production revenues in 2007 include approximately
$53 million related to natural gas liquids. In 2006,
approximately $29 million of similar revenues were
classified within other revenues.
$144 million increase in revenues for gas management
activities related to gas sold on behalf of certain outside
parties which is offset by a similar increase in
segment
costs and expenses
.
53
Table of Contents
$173 million higher depreciation, depletion and
amortization expense primarily due to higher production volumes
and increased capitalized drilling costs.
$144 million increase in expenses for gas management
activities related to gas purchased on behalf of certain outside
parties which is offset by a similar increase in
segment
revenues
.
$46 million higher lease operating expenses from the
increased number of producing wells primarily within the
Piceance, Powder River, and Fort Worth basins in
combination with higher well service expenses, facility
expenses, equipment rentals, maintenance and repair services,
and salt water disposal expenses.
$36 million higher
SG&A expenses
primarily due
to increased staffing in support of increased drilling and
operational activity, including higher compensation. In
addition, we incurred higher insurance and information
technology support costs related to the increased activity.
First quarter 2007 also includes approximately $5 million
of expenses associated with a correction of costs incorrectly
capitalized in prior periods.
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Years Ended December 31,
2008
2007
2006
(Millions)
$
1,634
$
1,610
$
1,348
$
689
$
673
$
467
55
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An increase of $59 million associated with the sale of
excess inventory gas;
An increase in depreciation expense of $30 million due to
property additions;
An increase in personnel costs of $10 million due primarily
to higher compensation as well as an increase in number of
employees.
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Sales Volumes by Quarter
(excludes partially owned plants)
57
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58
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Margins in our NGL and olefins business are highly dependent
upon continued demand within the global economy. NGL products
are currently the preferred feedstock for ethylene and propylene
olefin production, which are the building blocks of polyethylene
or plastics. Forecasted domestic and global demand for
polyethylene has weakened with the recent instability in the
global economy. A continued slow down in domestic and global
economies could further reduce the demand for the petrochemical
products we produce in both Canada and the United States.
As evidenced by recent events, NGL, crude and natural gas prices
are highly volatile. NGL price changes have historically tracked
with changes in the price of crude oil; however ethane prices
have recently disassociated from crude prices. As NGL prices,
especially ethane, decline, we expect lower
per-unit
NGL
margins in 2009 compared to 2008. Additionally, we anticipate
periods when it is not economical to recover ethane, which will
further reduce our segment profit.
Although natural gas prices declined significantly during the
fourth-quarter of 2008, which reduced our costs associated with
the production of NGLs, NGL margins were compressed as NGL
prices fell more than natural gas prices. However, we expect
continued favorable gas price differentials in the Rocky
Mountain area to partially mitigate such
per-unit
margin declines.
In our olefin production business, we continue to maintain a
cost advantage as our propylene and ethylene olefin production
processes use NGL-based feedstocks, which are less expensive
than other olefin production processes that use alternative
crude-based feedstocks. However, margins have narrowed and we
anticipate results from our olefins production business for the
2009 year to be below 2008 levels.
Fee-based revenues generally reduce our exposure to commodity
price risks, but may also reduce our profitability compared to
keep-whole arrangements in high margin environments. Certain of
our gas processing contracts contain provisions that allow
customers to periodically elect processing services on either a
fee-basis or a keep-whole or percent-of-liquids basis. If
customers switch from keep-whole to fee-based processing, we
expect a reduction in our NGL equity sales volumes in 2009
compared to 2008.
Natural gas supplies supporting our gathering and processing
volumes are dependent upon producer drilling activities. The
current credit crisis and economic downturn, together with the
low commodity price environment, are expected to reduce certain
producer drilling activities. Although our customers in the West
region are generally large producers and we anticipate they will
continue with some level of drilling plans, certain reductions
are expected in 2009. A significant decline in drilling activity
would likely reduce our gathered volumes and volumes available
for both fee-based and keep-whole processing.
We expect higher fee revenues, depreciation and operating
expenses in our Gulf Coast region as our Devils Tower
infrastructure expansions serving the Blind Faith and Bass Lite
prospects move into a full
59
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year of operation in 2009. While we expect to continue to
connect new supplies in the deepwater, this increase is expected
to be partially offset by lower volumes in other Gulf Coast
areas due to natural declines.
In the eastern deepwater of the Gulf of Mexico, we completed
construction of
37-mile
extensions of both of our oil and gas pipelines from our Devils
Tower spar to the Blind Faith prospect located in Mississippi
Canyon. The pipelines have been commissioned and production
began flowing in the fourth quarter of 2008.
In the western deepwater of the Gulf of Mexico, we expect to
spend $205 million on our major expansion projects in 2009,
including the Perdido Norte project, which will include an
expansion of our Markham gas processing facility and oil and gas
lines that will expand the scale of our existing infrastructure.
We expect this project to begin contributing to our segment
profit at the end of 2009.
In the West Region, we expect to spend $260 million on our
major expansion projects in 2009, including the Willow Creek
facility and additional capacity at our Echo Springs facility.
The current economic and commodity price environment may cause
financial difficulties for certain of our customers. Many of our
marketing counterparties are in the petrochemicals industry,
which has been under severe stress from the current economic
downturn. Although we actively manage our credit exposure
through certain collateral or payment terms and arrangements,
continued economic downturn may result in significant credit or
bad debt losses.
We expect significant savings in certain NGL transportation
costs in the West region due to the transition from our previous
shipping arrangement to transportation on the Overland Pass
pipeline. NGL volumes from our Wyoming plants began to flow into
the Overland Pass pipeline in the fourth quarter of 2008,
relieving pipeline capacity constraints and resulting in an
expected increase in NGL volumes for 2009.
Our Venezuelan operations are operated for the exclusive benefit
of the Venezuelan state-owned oil company, Petróleos de
Venezuela S.A. (PDVSA). As energy commodity prices have sharply
declined, PDVSA has failed to make regular payments to many
service providers, including us. At December 31, 2008, we
had a net receivable of $57 million from PDVSA, none of
which was 60 days old or older at that date. This does not
include $15 million owed to our 49 percent equity
investee, Accroven, of which $5 million was 60 days
old or older at December 31, 2008. We continue to monitor
the situation and are actively seeking resolution with PDVSA.
The collection of receivables from PDVSA has historically been
slower and more time consuming than our other customers due to
their policies and the political unrest in Venezuela. We expect,
at this time, that the amounts will ultimately be paid. The
failure of PDVSA to make payments to service providers, however,
could jeopardize the Venezuelan oil industry and thereby
unfavorably impact all service providers, including us.
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Years Ended December 31,
2008
2007
2006
(Millions)
$
5,642
$
5,180
$
4,159
841
897
631
104
89
98
113
174
16
(95
)
(88
)
(70
)
$
963
$
1,072
$
675
A $210 million increase in revenues in our olefins
production business due primarily 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 due primarily 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 $69 million increase in fee-based revenues due primarily
to the West region, Venezuela, the deepwater Gulf Coast region
and at our Conway fractionation and storage facilities.
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 due primarily to higher average natural gas
prices.
A $126 million increase in NGL, olefin and crude marketing
purchases due primarily to higher average NGL and crude prices,
partially offset by lower volumes as discussed in the revenue
section above. The increase also includes a $19 million
higher charge in 2008 to write down the value of NGL and olefin
inventories.
A $107 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, employee costs, and higher costs
associated with the increase of our ownership interest in the
Geismar olefins facility.
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Table of Contents
A $44 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 related to the partial settlement of
our Gulf Liquids litigation (see Note 16 of Notes to
Consolidated Financial Statements).
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.
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 due primarily 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 related to our
Ignacio plant. These insurance recoveries were used to rebuild
the plant.
$123 million in lower margins related to the marketing of
NGLs and olefins due primarily 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 to write
down the value of NGL and olefin inventories.
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Table of Contents
$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 related to the partial settlement of
our Gulf Liquids litigation (see Note 16 of Notes to
Consolidated Financial Statements).
A $528 million increase in revenues from the marketing of
NGLs and olefins.
A $303 million increase in revenues from our olefins
production business.
A $244 million increase in revenues associated with the
production of NGLs.
A $491 million increase in NGL and olefin marketing
purchases.
A $257 million increase in costs from our olefins
production business.
A $37 million increase in operating expenses including
higher depreciation, maintenance, gathering fuel expenses and
operating taxes.
$24 million higher general and administrative expenses.
A $10 million loss on impairment of the Carbonate Trend
pipeline and an $8 million loss on impairment of other
assets.
The absence of $11 million of net gains on the sales of
assets in 2006.
The absence of a 2006 charge of $73 million related to our
Gulf Liquids litigation (see Note 15 of Notes to
Consolidated Financial Statements).
A $95 million decrease in costs associated with the
production of NGLs due primarily to lower natural gas prices.
$12 million income in 2007 from a favorable litigation
outcome.
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Table of Contents
NGL margins increased $326 million in 2007 compared to
2006. This increase was driven by an increase in average per
unit NGL prices, a decrease in costs associated with the
production of NGLs reflecting lower natural gas prices and
higher volumes due primarily to new capacity on the fifth
cryogenic train at our Opal plant.
Processing fee revenues increased $12 million. Processing
volumes are higher due to customers electing to take liquids and
pay processing fees.
$12 million income in 2007 from a favorable litigation
outcome.
Gathering fee revenues decreased $6 million due primarily
to natural volume declines and the shutdown of the Ignacio plant
in the fourth quarter of 2007 as a result of the fire.
Operating expenses increased $21 million including
$9 million in higher depreciation, $9 million in
higher treating plant and gathering fuel due primarily to the
expiration of a favorable gas purchase contract, $5 million
related to gas imbalance revaluation losses in the current year
compared to gains in the prior year, $5 million higher
leased compression costs and $4 million higher costs
related to the Jicarilla lease arrangement. These were partially
offset by the absence of a $7 million accounts payable
accrual adjustment in 2006 and $5 million in lower system
product losses.
Fee revenues from our deepwater assets decreased
$40 million due primarily to declines in producers
volumes.
A $10 million loss on impairment of the Carbonate Trend
pipeline and a $6 million loss on impairment of our other
assets.
The absence of $8 million in gains on the sales of certain
gathering assets and a processing plant in 2006 and
$5 million lower involuntary conversion gains resulting
from insurance proceeds used to rebuild the Cameron Meadows
plant.
NGL margins increased $14 million driven by higher NGL
prices, partially offset by lower NGL recoveries and an increase
in costs associated with the production of NGLs.
Other fee revenues increased $8 million driven by higher
water removal fees.
The absence of the previously mentioned $73 million Gulf
Liquids litigation charge in 2006.
$46 million in higher margins from our olefins production
business due primarily to the increase in ownership of the
Geismar olefins facility in July 2007 and higher prices of NGL
products produced in our Canadian olefins operations.
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Table of Contents
$18 million in higher margins related to the marketing of
olefins and $21 million in higher margins related to the
marketing of NGLs due to more favorable changes in pricing while
product was in transit during 2007 as compared to 2006.
An $8 million reversal of a maintenance accrual (see below).
$9 million higher Aux Sable equity earnings primarily due
to favorable processing margins.
$11 million higher Discovery equity earnings primarily due
to higher NGL margins and volumes.
$19 million in higher foreign exchange losses related to
the revaluation of current assets held in U.S. dollars
within our Canadian operations.
The absence of a $4 million favorable transportation
settlement in 2006.
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Years Ended December 31,
2008
2007
2006
(Millions)
$
6,385
$
4,948
$
5,185
27
(315
)
(136
)
$
6,412
$
4,633
$
5,049
$
3
$
(337
)
$
(195
)
A $20 million accrual for litigation contingencies in 2007.
The absence of a $25 million gain from the sale of certain
receivables to a third party in 2006.
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Years Ended December 31,
2008
2007
2006
(Millions)
$
24
$
26
$
27
$
(3
)
$
(1
)
$
(13
)
Continued investment in Exploration &
Productions development drilling programs.
Expansion of Gas Pipelines interstate natural gas pipeline
system to meet the demand of growth markets.
Continued investment in Midstreams Deepwater Gulf
expansion projects and gas processing capacity in the western
United States.
We have sharply reduced our forecasted levels of capital
expenditures and have the flexibility to make further reductions
if needed.
As of December 31, 2008, we have approximately
$1.4 billion of cash and cash equivalents and approximately
$2.5 billion of available credit capacity under our credit
facilities, of which $400 million expires in
April 2009 and $100 million expires in May 2009. Our
primary $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.)
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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.
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, and utilization of our revolving credit facilities as
needed. However, we may be opportunistic in accessing the
capital markets to build additional liquidity. We estimate our
cash flow from operations to be between $1.9 billion and
$2.2 billion in 2009.
Lower than expected levels of cash flow from operations.
Sustained reductions in energy commodity prices from year-end
2008 levels.
Exposure associated with our efforts to resolve regulatory and
litigation issues (see Note 16 of Notes to Consolidated
Financial Statements).
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Year Ended
Credit Facilities
December 31, 2008
Expiration
(Millions)
$
1,439
April 2009
400
May 2009
100
September 2010
480
May 2012
1,359
December 2012
188
$
3,966
(1)
Cash and cash equivalents
includes $30 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
$609 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)
Northwest Pipeline and Transco each have access to
$400 million under this facility to the extent not utilized
by us. We expect that the ability of both Northwest Pipeline and
Transco to borrow under this facility is reduced by
approximately $19 million each due to the bankruptcy of a
participating bank. We also expect that our consolidated ability
to borrow under this facility is reduced by a total of
$70 million, including the reductions related to Northwest
Pipeline and Transco. The available liquidity in the table above
reflects this $70 million reduction. (See Note 11 of
Notes to Consolidated Financial Statements.) The committed
amounts of other participating banks under this agreement remain
in effect and are not impacted by this reduction.
Our primary credit facility contains financial covenants
including the requirement that we not exceed stated debt to
capitalization ratios. At December 31, 2008, we are
significantly below the maximum allowed ratios (see Note 11
of Notes to Consolidated Financial Statements).
(3)
This facility is only available to Williams Partners L.P. We
expect that Williams Partners L.P.s ability to borrow
under this facility is reduced by $12 million due to the
bankruptcy of a participating bank. The available liquidity in
the table above reflects this $12 million reduction. (See
Note 11 of Notes to Consolidated Financial Statements.) The
committed amounts of other participating banks under this
agreement remain in effect and are not impacted by this
reduction.
This credit facility contains financial covenants related to
Williams Partners L.P.s EBITDA to interest expense ratio
and indebtedness to EBITDA ratio (all as defined in the credit
agreement). At December 31, 2008, they are in compliance
with these covenants. However, since the ratios are calculated
on a rolling four-quarter basis, the ratios at December 31,
2008, do not reflect the full-year impact of lower commodity
prices in the fourth quarter which have continued into 2009.
69
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Years Ended December 31,
2008
2007
2006
(Millions)
$
3,355
$
2,237
$
1,890
(432
)
(511
)
1,103
(3,183
)
(2,296
)
(2,321
)
$
(260
)
$
(570
)
$
672
$140 million of cash received 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).
70
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$144 million of required refunds paid by Transco related to
a general rate case with the FERC (see Results of
Operations Segments, Gas Pipeline).
We received $362 million from the completion of the
Williams Pipeline Partners L.P. initial public offering (see
Note 1 of Notes to Consolidated Financial Statements).
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 from debt
transactions (see Note 11 of Notes to Consolidated
Financial Statements).
We paid $250 million of quarterly dividends on common stock
for the year ended December 31, 2008.
We paid $526 million for the repurchase of our common stock.
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.
Transco issued $200 million aggregate principal amount of
6.4 percent senior unsecured notes due 2016.
Northwest Pipeline issued $175 million aggregate principal
amount of 7 percent senior unsecured notes due 2016.
Williams Partners L.P. acquired our interest in Williams Four
Corners LLC for $1.6 billion. The acquisition was completed
after Williams Partners L.P. successfully closed a
$150 million private debt offering of 7.5 percent
senior unsecured notes due 2011, a $600 million private
debt offering of 7.25 percent senior unsecured notes due
2017, $350 million of common and Class B units, and
equity offerings of $519 million in net proceeds.
We paid $489 million to retire a secured floating-rate term
loan due in 2008.
We paid $26 million in premiums related to the conversion
of $220 million of 5.5 percent junior subordinated
convertible debentures into common stock.
71
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We paid $207 million of quarterly dividends on common stock
for the year ended December 31, 2006.
Our net investment in property, plant and equipment totaled
$3.3 billion and was primarily related to
Exploration & Productions drilling activity.
This total includes Exploration & Productions
acquisitions of certain interests in the Piceance and
Fort Worth basins (see Results of Operations
Segments, Exploration & Production).
$148 million of cash received from Exploration &
Productions sale of a contractual right to a production
payment (see Note 4 of Notes to Consolidated Financial
Statements).
We contributed $111 million to our investments, including
$90 million related to our Gulfstream equity investment.
Our net investment in property, plant and equipment totaled
$2.9 billion and was primarily related to
Exploration & Productions 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.
Our net investment in property, plant and equipment totaled
$2.4 billion and was primarily related to
Exploration & Productions drilling activity,
mostly in the Piceance basin, and Northwest Pipelines
capacity replacement project.
We purchased $386 million and received $414 million
from the sale of auction rate securities.
72
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2010-
2012-
2009
2011
2013
Thereafter
Total
(Millions)
$
53
$
994
$
1,248
$
5,611
$
7,906
588
1,151
894
4,452
7,085
3
2
5
96
80
42
44
262
1,299
1,342
1,209
2,405
6,255
575
606
296
196
1,673
1
1
$
2,614
$
4,176
$
3,689
$
12,708
$
23,187
(1)
The debt instruments in this table are classified by stated
maturity date. See Note 11 of Notes to Consolidated
Financial Statements for discussion of certain non-recourse debt
of two of our Venezuelan subsidiaries that is in technical
default and classified as current on our Consolidated Balance
Sheet.
(2)
Includes $3.7 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, 2008 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 $3.6 billion at
December 31, 2008, 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
$75 million in 2008 and $56 million in 2007. In 2009,
we expect to contribute approximately $77 million to these
plans (see Note 7 of Notes to Consolidated Financial
Statements). During 2008, we contributed $60 million to our
tax-qualified pension plans which was greater than the minimum
funding requirements. Although the 2008 economic downturn
resulted in a significant decrease in the funded status of our
tax-qualified pension plans, we expect to contribute
approximately $60 million to these pension plans again in
2009, which is expected to be greater than the minimum funding
requirements. Estimated future minimum funding requirements may
vary significantly from historical requirements if investment
returns do not return to expected levels. Future minimum funding
requirements may also be impacted if actual results differ
significantly from estimated results for assumptions such as
interest rates, retirement rates, mortality and other
significant assumptions or by changes to current legislation and
regulations.
(6)
As of December 31, 2008, we have accrued approximately
$79 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.
73
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74
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Item 7A.
Quantitative
and Qualitative Disclosures About Market Risk
Fair Value
December 31,
2009
2010
2011
2012
2013
Thereafter(1)
Total
2008
(Dollars in millions)
$
41
$
27
$
948
$
971
$
17
$
5,566
$
7,570
$
6,011
7.6
%
7.6
%
7.6
%
7.6
%
7.5
%
7.9
%
$
12
$
12
$
7
$
255
$
5
$
13
$
304
$
274
Fair Value
December 31,
2008
2009
2010
2011
2012
Thereafter(1)
Total
2007
(Dollars in millions)
$
53
$
41
$
27
$
948
$
971
$
5,111
$
7,151
$
7,994
7.7
%
7.7
%
7.4
%
7.4
%
7.3
%
7.7
%
$
85
$
12
$
12
$
7
$
605
(5)
$
18
$
739
$
735
(1)
Includes unamortized discount and premium.
(2)
The interest rate at December 31, 2008, is LIBOR plus
0.76 percent.
(3)
The interest rate at December 31, 2007 was LIBOR plus
0.75 percent.
(4)
Excludes capital leases.
(5)
Includes Transcos subsequent refinancing of its
$100 million notes, due on January 15, 2008, under our
$1.5 billion revolving credit facility. (See Note 11
of Notes to Consolidated Financial Statements.)
(6)
The debt instruments in this table are classified by stated
maturity date. See Note 11 of Notes to Consolidated
Financial Statements for discussion of certain non-recourse debt
of two of our Venezuelan subsidiaries that is in technical
default and classified as current on our Consolidated Balance
Sheet.
75
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76
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77
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Item 8.
Financial
Statements and Supplementary Data
FINANCIAL REPORTING
78
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FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
79
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80
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Years Ended December 31,
2008
2007
2006
(Millions, except per-share amounts)
$
3,121
$
2,021
$
1,411
1,634
1,610
1,348
5,642
5,180
4,159
6,412
4,633
5,049
24
26
27
(4,481
)
(2,984
)
(2,695
)
12,352
10,486
9,299
9,156
8,007
7,489
504
471
389
(82
)
(18
)
34
9,578
8,460
7,912
149
161
132
167
1,240
731
530
630
622
430
904
1,011
635
3
(337
)
(195
)
(3
)
(1
)
(13
)
(149
)
(161
)
(132
)
(167
)
2,625
1,865
1,088
(653
)
(685
)
(670
)
59
32
17
191
257
168
(1
)
(19
)
(31
)
(174
)
(90
)
(40
)
11
26
2,047
1,371
558
713
524
211
1,334
847
347
84
143
(38
)
$
1,418
$
990
$
309
$
2.30
$
1.42
$
.58
.14
.24
(.06
)
$
2.44
$
1.66
$
.52
581,342
596,174
595,053
$
2.26
$
1.40
$
.57
.14
.23
(.06
)
$
2.40
$
1.63
$
.51
592,719
609,866
608,627
81
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82
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Accumulated
Capital in
Retained
Other
Common
Excess of
Earnings
Comprehensive
Treasury
Stock
Par Value
(Deficit)
Loss
Other
Stock
Total
(Dollars in millions, except per-share amounts)
$
579
$
6,328
$
(1,136
)
$
(298
)
$
(5
)
$
(41
)
$
5,427
309
309
394
394
(4
)
(4
)
(1
)
(1
)
389
698
(4
)
(4
)
(150
)
(150
)
5
5
(4
)
(4
)
2
2
20
193
213
(207
)
(207
)
5
5
4
84
88
603
6,605
(1,034
)
(60
)
(41
)
6,073
990
990
(179
)
(179
)
53
53
53
53
1
1
9
9
(63
)
2
2
929
(233
)
(233
)
(17
)
(17
)
(526
)
(526
)
5
143
148
1
1
608
6,748
(293
)
(121
)
(567
)
6,375
1,418
1,418
455
455
(76
)
(76
)
1
1
(344
)
(344
)
9
9
(9
)
(9
)
36
5
5
1,459
(250
)
(250
)
2
25
27
1,225
1,225
(474
)
(474
)
3
67
70
9
(1
)
8
$
613
$
8,074
$
874
$
(80
)
$
$
(1,041
)
$
8,440
83
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Years Ended December 31,
2008
2007
2006
(Millions)
$
1,418
$
990
$
309
(429
)
1,310
1,082
866
611
370
154
166
162
26
(36
)
16
(23
)
(148
)
1
19
31
174
90
40
31
70
44
329
(122
)
386
(48
)
29
31
88
(135
)
98
(76
)
(10
)
(30
)
(343
)
26
(184
)
7
(200
)
(110
)
(121
)
370
303
(8
)
(91
)
(51
)
3,355
2,237
1,890
674
684
1,299
(665
)
(806
)
(777
)
32
56
34
362
333
863
21
32
16
(250
)
(233
)
(207
)
(474
)
(526
)
(4
)
(4
)
(37
)
(27
)
(26
)
(122
)
(75
)
(36
)
52
(25
)
(6
)
3
(1
)
(432
)
(511
)
1,103
(3,475
)
(2,816
)
(2,509
)
119
12
23
81
(52
)
105
(111
)
(60
)
(49
)
(304
)
(386
)
(31
)
353
414
22
471
148
41
92
62
14
9
8
19
(3,183
)
(2,296
)
(2,321
)
(260
)
(570
)
672
1,699
2,269
1,597
$
1,439
$
1,699
$
2,269
84
Table of Contents
Note 1.
Description
of Business, Basis of Presentation, and Summary of Significant
Accounting Policies
85
Table of Contents
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 & Productions reserves;
Asset retirement obligations;
Pension and postretirement valuation variables.
86
Table of Contents
87
Table of Contents
88
Table of Contents
Accrual accounting
Hedge accounting
Mark-to-market accounting
89
Table of Contents
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;
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.
90
Table of Contents
91
Table of Contents
92
Table of Contents
93
Table of Contents
94
Table of Contents
Note 2.
Discontinued
Operations
95
Table of Contents
2008
2007
2006
(Millions)
$
5
$
2,436
$
2,437
$
163
$
392
$
(58
)
8
(162
)
(87
)
(87
)
20
$
84
$
143
$
(38
)
96
Table of Contents
December 31,
December 31,
2008
2007
(Millions)
$
1
$
114
5
55
3
6
172
8
5
13
$
6
$
185
$
1
$
114
61
1
175
$
1
$
175
Note 3.
Investing
Activities
Years Ended December 31,
2008
2007
2006
(Millions)
$
137
$
137
$
99
1
(4
)
(1
)
(20
)
57
121
89
$
191
$
257
$
168
*
Items also included in
segment profit
. (See Note 18.)
97
Table of Contents
December 31,
2008
2007
(Millions)
$
525
$
439
184
215
73
65
69
62
96
95
947
876
24
25
$
971
$
901
*
Our consolidated subsidiary, Williams Partners L.P., owns
60 percent. However, we continue to account for this
investment under the equity method due to the voting provisions
of Discoverys limited liability company, which provide the
other member of Discovery significant participatory rights such
that we do not control the investment.
2008
2007
(Millions)
$
58
$
34
56
36
28
22
7
12
98
Table of Contents
Note 4.
Asset
Sales, Impairments and Other Accruals
Years Ended December 31,
2008
2007
2006
(Millions)
$
(148
)
$
$
143
(17
)
(18
)
(10
)
(12
)
6
10
(32
)
73
(12
)
20
99
Table of Contents
Note 5.
Provision
for Income Taxes
2008
2007
2006
(Millions)
$
179
$
29
$
(9
)
24
9
3
35
46
43
238
84
37
466
422
146
(11
)
(4
)
4
20
22
24
475
440
174
$
713
$
524
$
211
2008
2007
2006
(Millions)
$
717
$
480
$
195
8
4
7
18
23
(5
)
(40
)
10
(7
)
22
16
$
713
$
524
$
211
100
Table of Contents
2008
2007
(Millions)
$
3,568
$
3,192
263
163
176
112
89
4,106
3,457
581
433
173
3
50
8
55
53
639
717
15
57
624
660
$
3,482
$
2,797
101
Table of Contents
2008
2007
(Millions)
$
76
$
93
3
8
5
(8
)
(19
)
(3
)
$
79
$
76
Note 6.
Earnings
Per Common Share from Continuing Operations
2008
2007
2006
(Dollars in millions, except per-share amounts; shares in
thousands)
$
1,334
$
847
$
347
581,342
596,174
595,053
1,334
1,627
1,029
3,439
4,743
4,440
6,604
7,322
8,105
592,719
609,866
608,627
$
2.30
$
1.42
$
.58
$
2.26
$
1.40
$
.57
102
Table of Contents
(1)
The years ended December 31, 2008, 2007 and 2006, include
$2 million, $3 million and $3 million of interest
expense, net of tax, associated with our convertible debentures.
(See Note 12.) These amounts have been added back to
income from continuing operations 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 third-quarter 2008, we issued 2 million shares of
our common stock in exchange for a portion of our
5.5 percent convertible debentures. During January 2006, we
issued 20 million shares of common stock related to a
conversion offer for our 5.5 percent convertible debentures.
2008
2007
2006
6.4
.8
3.6
$26.41
$40.07
$36.14
$16.40 - $42.29
$36.66 -$42.29
$26.79 - $42.29
$16.37
$35.14
$25.77
Note 7.
Employee
Benefit Plans
103
Table of Contents
Other
Postretirement
Pension Benefits
Benefits
2008
2007
2008
2007
(Millions)
$
896
$
931
$
284
$
312
23
23
2
3
60
54
18
17
5
5
(70
)
(64
)
(23
)
(23
)
2
(38
)
126
(48
)
23
(30
)
1,035
896
273
284
1,074
1,005
192
180
(360
)
92
(62
)
15
61
41
14
15
5
5
(70
)
(64
)
(23
)
(23
)
705
1,074
126
192
$
(330
)
$
178
$
(147
)
$
(92
)
$
959
$
838
December 31,
2008
2007
(Millions)
$
$
203
1
1
329
24
8
9
139
83
104
Table of Contents
Other
Postretirement
Pension Benefits
Benefits
2008
2007
2008
2007
(Millions)
$
(5
)
$
(6
)
$
12
$
(5
)
(708
)
(156
)
(8
)
7
N/A
N/A
$
24
$
3
N/A
N/A
(57
)
26
105
Table of Contents
Other
Pension Benefits
Postretirement Benefits
2008
2007
2006
2008
2007
2006
(Millions)
$
23
$
23
$
22
$
2
$
3
$
3
60
54
51
18
17
17
(79
)
(73
)
(67
)
(13
)
(12
)
(11
)
1
(1
)
13
19
21
1
5
5
7
$
18
$
24
$
26
$
12
$
13
$
16
$
565
$
(68
)
$
15
$
(15
)
(16
)
(13
)
(19
)
(1
)
(1
)
(2
)
551
(87
)
(2
)
(17
)
$
569
$
(63
)
$
10
$
(4
)
Other
Pension
Postretirement
Benefits
Benefits
(Millions)
$
1
$
(2
)
45
N/A
$
(5
)
N/A
3
106
Table of Contents
Other
Postretirement
Pension Benefits
Benefits
2008
2007
2008
2007
6.08
%
6.41
%
6.00
%
6.40
%
5.00
5.00
N/A
N/A
Other
Pension Benefits
Postretirement Benefits
2008
2007
2006
2008
2007
2006
6.41
%
5.80
%
5.65
%
6.40
%
5.80
%
5.60
%
7.75
7.75
7.75
7.00
6.97
6.95
5.00
5.00
5.00
N/A
N/A
N/A
107
Table of Contents
Point increase
Point decrease
(Millions)
$
3
$
(4
)
53
(42
)
Other
Pension Benefits
Postretirement Benefits
2008
2007
Target
2008
2007
Target
78
%
84
%
84
%
71
%
79
%
80
%
17
12
16
17
12
20
5
4
12
9
100
%
100
%
100
%
100
%
100
%
100
%
108
Table of Contents
Federal
Other
Prescription
Pension
Postretirement
Drug
Benefits
Benefits
Subsidy
(Millions)
$
44
$
17
$
(2
)
38
18
(2
)
38
18
(2
)
42
18
(2
)
42
18
(2
)
263
96
(13
)
109
Table of Contents
Note 8.
Inventories
2008
2007
(Millions)
$
56
$
66
97
45
107
98
$
260
$
209
Note 9.
Property,
Plant and Equipment
Estimated
Depreciation
Useful Life(b)
Rates(b)
(Years)
(%)
2008
2007
(Millions)
(a)
$
8,749
$
6,844
3 - 40
5,394
4,781
(d)
1,169
908
2 - 45
770
702
.01 - 7.25
8,441
8,208
(d)
120
72
.01 - 50
1,293
1,272
25,936
22,787
(7,871
)
(6,806
)
$
18,065
$
15,981
(a)
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 $571 million at December 31, 2008, and
$378 million at December 31, 2007, of capitalized
costs related to properties with unproven reserves not yet
subject to depletion at Exploration & Production.
(b)
Estimated useful life and depreciation rates are presented as of
December 31, 2008.
(c)
Certain assets above are currently pledged as collateral to
secure debt. See Note 11 of Notes to Consolidated Financial
Statements.
(d)
Construction in progress balances not yet subject to
depreciation.
110
Table of Contents
Note 10.
Accounts
Payable and Accrued Liabilities
2008
2007
(Millions)
$
223
$
169
185
208
168
174
165
75
51
94
38
39
14
96
326
303
$
1,170
$
1,158
*
Includes interest of $14 million in 2008 and
$25 million in 2007.
111
Table of Contents
Note 11.
Debt,
Leases and Banking Arrangements
Weighted-
Average
Interest
December 31,
Rate(1)
2008(2)
2007
(Millions)
8.0
%
$
123
$
148
3.9
%
54
64
6.0
%
5
10
7.6
%
7,447
7,103
250
1.2
%
250
325
7,879
7,900
(196
)
(143
)
$
7,683
$
7,757
(1)
At December 31, 2008.
(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.
(3)
Includes $177 million and $212 million at
December 31, 2008 and 2007, respectively, collateralized by
certain fixed assets of two of our Venezuelan subsidiaries with
a net book value of $324 million and $351 million at
December 31, 2008 and 2007, respectively. The non-recourse
debt at both subsidiaries is currently in technical default
triggered by past due payments from their sole customer,
Petróleos de Venezuela S.A. (PDVSA), under the related
services contracts. We are in discussion with the associated
lenders to obtain waivers. This has no impact on our other debt
agreements or our liquidity.
(4)
2007 includes Transcos $100 million 6.25 percent
notes, due on January 15, 2008, that were reclassified as
long-term debt as a result of a subsequent refinancing under the
$1.5 billion revolving credit facility.
112
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Our ratio of debt to capitalization must be no greater than
65 percent. At December 31, 2008, we are in compliance
with this covenant as our ratio of debt to capitalization, as
calculated under this covenant, is approximately 40 percent.
Ratio of debt to capitalization must be no greater than
55 percent for Northwest Pipeline and Transco. At
December 31, 2008, they are in compliance with this
covenant as their ratio of debt to capitalization, as calculated
under this covenant, is approximately 36 percent for
Northwest Pipeline and 26 percent for Transco.
$500 Million Facility
$700 Million Facility
$400 million
$100 million
$500 million
$200 million
3.57 percent
LIBOR
4.35 percent
LIBOR
3.19 percent
2.29 percent
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, 2008, they
are in compliance with this covenant as their ratio is 2.98.
113
Table of Contents
Williams Partners L.P. is required to maintain an 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, 2008, they are in compliance with this
covenant as their ratio is 5.13.
Letters of Credit at
December 31, 2008
(Millions)
$
$
220
$
71
114
Table of Contents
(Millions)
$
192
927
1,203
(1)
Maturities for 2009 includes $177 million related to the
non-recourse debt of two of our Venezuela subsidiaries. Only
$38 million of this debt has a stated maturity in 2009, but
the entire balance is reflected in 2009 as the debt is currently
in technical default triggered by past due payments from their
sole customer, PDVSA, under the related services contracts. We
are in discussion with the associated lenders to obtain waivers.
This has no impact on our other debt agreements or our liquidity.
(Millions)
$
69
53
26
23
19
45
$
235
Note 12.
Stockholders
Equity
115
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Note 13.
Stock-Based
Compensation
116
Table of Contents
Weighted-
Average
Aggregate
Exercise
Intrinsic
Options
Price
Value
(Millions)
(Millions)
13.2
$
16.62
1.0
$
36.50
(2.3
)
$
14.45
$
49
(.4
)
$
33.44
11.5
$
18.10
$
35
9.6
$
15.44
$
35
117
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Stock Options Outstanding
Stock Options Exercisable
Weighted-
Weighted-
Weighted-
Average
Weighted-
Average
Average
Remaining
Average
Remaining
Exercise
Contractual
Exercise
Contractual
Options
Price
Life
Options
Price
Life
(Millions)
(Years)
(Millions)
(Years)
4.7
$
7.12
4.1
4.7
$
7.12
4.1
3.8
$
19.51
6.0
3.5
$
19.32
5.8
1.1
$
28.11
7.5
.5
$
27.79
6.6
1.9
$
37.06
5.4
.9
$
37.64
1.4
11.5
$
18.10
5.3
9.6
$
15.44
4.6
2008
2007
2006
$
12.83
$
9.09
$
8.36
1.2
%
1.5
%
1.4
%
33.4
%
28.7
%
36.3
%
3.5
%
4.6
%
4.7
%
6.5
6.3
6.5
Table of Contents
Weighted-
Average
Shares
Fair Value*
(Millions)
4.4
$
27.78
1.4
$
30.13
(.2
)
$
27.52
(1.2
)
$
27.51
4.4
$
22.91
*
Performance-based shares are valued at the end-of-period market
price until certification that the performance objectives have
been completed. Upon certification, these shares are valued at
that days end-of-period market price. All other shares are
valued at the grant-date market price.
2008
2007
2006
$
30.13
$
30.79
$
23.39
$
48
$
33
$
15
Note 14.
Fair
Value Measurements
Table of Contents
Level 1 Quoted prices in active markets for
identical assets or liabilities 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, including certain instruments that were
part of sales transactions in 2007 and remain to be assigned to
the purchaser. These unassigned instruments are entirely offset
by reciprocal positions entered into directly with the
purchaser. These reciprocal positions have also been included in
Level 1.
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 and swaps.
Level 3 Includes inputs that are not observable
for which there is little, if any, market activity for the asset
or liability being measured. These inputs reflect
managements 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. Instruments in this category primarily include OTC
options.
120
Table of Contents
Quoted Prices
in Active
Markets for
Significant
Identical
Other
Significant
Assets or
Observable
Unobservable
Liabilities
Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
Total
(Millions)
$
680
$
1,223
$
547
$
2,450
13
7
20
$
693
$
1,223
$
554
$
2,470
$
615
$
1,313
$
40
$
1,968
$
615
$
1,313
$
40
$
1,968
121
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Year Ended December 31, 2008
Net Derivatives
Other Assets
(Millions)
$
(14
)
$
10
88
(3
)
486
(51
)
3
(5
)
$
507
$
7
$
$
Note 15.
Financial
Instruments, Derivatives, Guarantees and Concentration of Credit
Risk
122
Table of Contents
2008
2007
Carrying
Carrying
Amount
Fair Value
Amount
Fair Value
(Millions)
$
1,439
$
1,439
$
1,699
$
1,699
133
133
127
127
37
20
(a)
45
20
(a)
2
2
4
4
8
8
76
76
(7,874
)
(6,285
)
(7,890
)
(8,729
)
(38
)
(32
)
(40
)
(34
)
(30
)
(30
)
(10
)
(10
)
458
458
(268
)
(268
)
24
24
(100
)
(100
)
(a)
Excludes certain international investments in companies that are
not publicly traded and therefore it is not practicable to
estimate fair value. (See Note 3.)
(b)
Excludes capital leases. (See Note 11.)
(c)
A portion of these derivatives is included in assets and
liabilities of discontinued operations. (See Note 2.)
123
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124
Table of Contents
125
Table of Contents
2008
2007
(Millions)
$
653
$
882
158
177
86
80
55
49
53
$
946
$
1,247
126
Table of Contents
Investment
Grade(a)
Total
(Millions)
$
2
$
2
127
896
1,558
1,559
$
1,687
2,457
(6
)
$
2,451
Investment
Grade(a)
Total
(Millions)
$
$
1
79
80
600
600
$
679
681
(6
)
$
675
(a)
We determine investment grade primarily using publicly available
credit ratings. We include counterparties with a minimum
Standard & Poors of BBB- or Moodys
Investors Service rating of Baa3 in investment grade.
127
Table of Contents
Note 16.
Contingent
Liabilities and Commitments
128
Table of Contents
State court litigation in California brought on behalf of
certain business and governmental entities that purchased gas
for their use.
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.
A Missouri class action and the cases from other jurisdictions
were transferred to the federal court in Nevada. 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.
On October 29, 2008, the Tennessee appellate court reversed
the state courts 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.
On January 13, 2009, the Missouri state court dismissed a
case for lack of standing. We expect that the decision will be
appealed.
129
Table of Contents
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;
130
Table of Contents
Discontinued petroleum refining facilities; and
Former exploration and production and mining operations.
131
Table of Contents
132
Table of Contents
133
Table of Contents
134
Table of Contents
Note 17.
Accumulated
Other Comprehensive Loss
Income (Loss)
Other
Postretirement
Pension Benefits
Benefits
Foreign
Minimum
Prior
Net
Prior
Net
Cash Flow
Currency
Pension
Service
Actuarial
Service
Actuarial
Hedges
Translation
Liability
Cost
Gain (Loss)
Cost
Gain (Loss)
Total
(Millions)
$
(374
)
$
80
$
(4
)
$
$
$
$
$
(298
)
423
(4
)
(1
)
418
(162
)
(162
)
133
133
394
(4
)
(1
)
389
8
(6
)
(243
)*
(7
)
(8
)
(256
)
(3
)
2
93
3
10
105
5
(4
)
(150
)
(4
)
2
(151
)
20
76
(4
)
(150
)
(4
)
2
(60
)
201
53
68
15
337
(77
)
(26
)
(6
)
(109
)
(303
)**
(303
)
19
2
21
(8
)
(1
)
(9
)
(179
)
53
53
1
9
(63
)
2
2
(157
)
129
(4
)
(97
)
(3
)
11
(121
)
714
(76
)
(565
)
16
(15
)
74
(270
)
213
(8
)
6
(59
)
11
11
1
13
1
15
(5
)
(5
)
455
(76
)
1
(344
)
9
(9
)
36
(2
)
7
5
$
296
$
53
$
$
(3
)
$
(434
)
$
6
$
2
$
(80
)
*
Includes $1 million for the Net Actuarial Loss of an equity
method investee.
**
Includes a $429 million reclassification into earnings of
deferred net hedge gains related to the sale of our power
business. (See Note 2.)
135
Table of Contents
Note 18.
Segment
Disclosures
Exploration & Production depletion,
depreciation and amortization, lease 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.
United States
Other
Total
(Millions)
$
11,924
$
428
$
12,352
10,065
421
10,486
8,905
394
9,299
$
18,419
$
659
$
19,078
16,279
713
16,992
14,487
682
15,169
136
Table of Contents
Midstream
Gas
Exploration &
Gas
Gas &
Marketing
Production
Pipeline
Liquids
Services
Other
Eliminations
Total
(Millions)
$
(215
)
$
1,600
$
5,586
$
5,371
$
10
$
$
12,352
3,336
34
56
1,041
14
(4,481
)
$
3,121
$
1,634
$
5,642
$
6,412
$
24
$
(4,481
)
$
12,352
$
1,260
$
689
$
963
$
3
$
(3
)
$
$
2,912
20
59
58
137
1
1
$
1,240
$
630
$
904
$
3
$
(3
)
$
2,774
(149
)
$
2,625
$
2,563
$
413
$
679
$
$
42
$
$
3,697
$
737
$
321
$
233
$
1
$
18
$
$
1,310
$
(167
)
$
1,576
$
5,142
$
3,924
$
11
$
$
10,486
2,188
34
38
709
15
(2,984
)
$
2,021
$
1,610
$
5,180
$
4,633
$
26
$
(2,984
)
$
10,486
$
756
$
673
$
1,072
$
(337
)
$
(1
)
$
$
2,163
25
51
61
137
$
731
$
622
$
1,011
$
(337
)
$
(1
)
$
2,026
(161
)
$
1,865
$
1,717
$
546
$
610
$
$
27
$
$
2,900
$
535
$
315
$
214
$
7
$
10
$
$
1,081
$
(266
)
$
1,336
$
4,094
$
4,128
$
7
$
$
9,299
1,677
12
65
921
20
(2,695
)
$
1,411
$
1,348
$
4,159
$
5,049
$
27
$
(2,695
)
$
9,299
$
552
$
467
$
675
$
(195
)
$
(13
)
$
$
1,486
22
37
40
99
$
530
$
430
$
635
$
(195
)
$
(13
)
$
1,387
(132
)
(167
)
$
1,088
$
1,496
$
913
$
279
$
1
$
18
$
$
2,707
$
360
$
282
$
203
$
7
$
11
$
$
863
137
Table of Contents
Total Assets
Equity Method Investments
December 31,
December 31,
December 31,
December 31,
December 31,
December 31,
2008
2007
2006
2008
2007
2006
(Millions)
$
10,286
$
8,692
$
7,851
$
87
$
72
$
59
9,149
8,624
8,332
570
483
432
7,024
6,604
5,562
290
321
323
3,064
4,437
5,519
3,532
3,592
3,923
(7,055
)
(7,073
)
(7,187
)
26,000
24,876
24,000
947
876
814
6
185
1,402
$
26,006
$
25,061
$
25,402
$
947
$
876
$
814
(1)
The 2008 increase in Exploration & Productions
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
2008 and 2007 is due primarily 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.
138
Table of Contents
First
Second
Third
Fourth
Quarter
Quarter
Quarter
Quarter
$
3,204
$
3,701
$
3,245
$
2,202
2,353
2,719
2,364
1,720
416
419
369
130
500
437
366
115
.71
.72
.63
.23
.70
.70
.62
.23
$
2,348
$
2,805
$
2,844
$
2,489
1,823
2,161
2,206
1,817
170
243
228
206
134
433
198
225
.28
.40
.38
.35
.28
.40
.38
.34
First
Second
Third
Fourth
Quarter
Quarter
Quarter
Quarter
$
20
$
28
$
22
$
10
$
20
$
19
$
16
$
17
$129 million impairment of certain natural gas producing
properties at Exploration & Production (see
Note 4 of Notes to Consolidated Financial Statements);
$43 million of income including associated interest related
to the partial settlement of the Gulf Liquids litigation at
Midstream (see Notes 4 and 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).
139
Table of Contents
$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).
$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);
$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).
$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).
$156 million mark-to-market loss recognized at Gas
Marketing Services on a legacy derivative natural gas sales
contract that we expect to assign to another party in 2008 under
an asset transfer agreement that we executed in December 2007;
$20 million accrual for litigation contingencies at Gas
Marketing Services (see Note 4);
$19 million in premiums, fees and expenses related to early
debt retirement;
$12 million of income related to a favorable litigation
outcome at Midstream (see Note 4);
$10 million charge related to an impairment of the
Carbonate Trend pipeline at Midstream (see Note 4);
$9 million charge related to the reserve for certain
international receivables at Midstream;
$6 million net loss, including transaction expenses,
related to the sale of our discontinued power business (see
summarized results of discontinued operations at Note 2).
140
Table of Contents
$17 million of expenses related to the sale of our
discontinued power business (see summarized results of
discontinued operations at Note 2);
$12 million of income associated with the payments received
for a terminated firm transportation agreement on Northwest
Pipelines Grays Harbor lateral (see Note 4).
$429 million gain associated with the reclassification of
deferred net hedge gains to earnings related to the sale of our
discontinued power business (see summarized results of
discontinued operations at Note 2);
$111 million impairment of the carrying value of certain
derivative contracts related to the sale of our discontinued
power business (see summarized results of discontinued
operations at Note 2);
$17 million of income associated with a change in estimate
related to a regulatory liability at Northwest Pipeline (see
Note 4);
$15 million impairment of our Hazelton facility included in
discontinued operations (see summarized results of discontinued
operations at Note 2);
$14 million of gains from the sales of cost-based
investments (see Note 3);
$14 million of expenses related to the sale of our
discontinued power business (see summarized results of
discontinued operations at Note 2);
$6 million of income associated with the payments received
for a terminated firm transportation agreement on Northwest
Pipelines Grays Harbor lateral (see Note 4).
$8 million of income due to the reversal of a planned major
maintenance accrual at Midstream.
141
Table of Contents
As of December 31,
2008
2007
(Millions)
$
8,099
$
6,409
806
542
8,905
6,951
(2,353
)
(1,754
)
$
6,552
$
5,197
Excluded from capitalized costs are equipment and facilities in
support of oil and gas production of $726 million and
$505 million, net, for 2008 and 2007, respectively. The
capitalized cost amounts for 2008 and 2007 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 acreage related to
probable/possible reserves acquired through transactions in 2001
and 2008.
For the Year Ended
December 31,
2008
2007
2006
(Millions)
$
543
$
82
$
84
38
38
20
1,699
1,374
1,173
$
2,280
$
1,494
$
1,277
Costs incurred include capitalized and expensed items.
Acquisition costs are as follows: 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 are $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. The 2006 cost is primarily for additional leasehold
and reserve acquisitions in the Fort Worth basin.
142
Table of Contents
Exploration costs 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.
Development costs include costs incurred to gain access to and
prepare development well locations for drilling and to drill and
equip development wells.
For the Year Ended December 31,
2008
2007
2006
(Millions)
$
2,644
$
1,725
$
1,238
405
232
109
3,049
1,957
1,347
555
360
309
169
144
111
27
21
18
724
523
351
1
(1
)
143
349
198
59
1,968
1,245
848
1,081
712
499
(406
)
(273
)
(174
)
$
675
$
439
$
325
Results of operations for producing activities consist of all
related domestic activities within the Exploration &
Production reporting unit and excludes the $148 million
gain on sale of a contractual right to a production payment on
certain future international hydrocarbon production.
Prior period amounts have been adjusted to reflect the
presentation of certain revenues and costs on a net basis. These
adjustments reduced other revenues and reduced other expenses by
the same amount, with no net impact on segment profit. The
reductions were $72 million in 2007 and $77 million in
2006.
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.
143
Table of Contents
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.
2008
2007
2006
(Bcfe)
4,143
3,701
3,382
(220
)
(106
)
(113
)
31
19
41
791
863
669
(406
)
(334
)
(277
)
(1
)
4,339
4,143
3,701
2,456
2,252
1,945
The SEC defines proved oil and gas reserves
(Rule 4-10(a)
of
Regulation S-X)
as the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data
demonstrate with reasonable certainty are recoverable in future
years from known reservoirs under existing economic and
operating conditions. Our 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 limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled or where
it can be demonstrated with certainty that there is continuity
of production from the existing productive formation.
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 prior year.
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).
144
Table of Contents
At December 31,
2008
2007
(Millions)
$
19,127
$
23,937
5,516
5,345
3,772
3,497
3,284
5,416
6,555
9,679
3,382
4,876
$
3,173
$
4,803
2008
2007
2006
(Millions)
$
4,803
$
2,856
$
5,281
(2,091
)
(1,426
)
(1,179
)
(2,548
)
2,019
(4,052
)
1,423
2,163
647
817
738
881
(724
)
(931
)
(1,022
)
55
48
63
(2
)
(395
)
(266
)
(140
)
714
434
790
1,108
(1,108
)
1,468
11
276
121
(1,630
)
1,947
(2,425
)
$
3,173
$
4,803
$
2,856
145
Table of Contents
ADDITIONS | ||||||||||||||||||||
Charged to
|
||||||||||||||||||||
Beginning
|
Cost and
|
Ending
|
||||||||||||||||||
Balance | Expenses | Other | Deductions | Balance | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Year ended December 31, 2008:
|
||||||||||||||||||||
Allowance for doubtful accounts accounts and notes
receivable(a)
|
$ | 27 | $ | 15 | $ | | $ | 2 | (d) | $ | 40 | |||||||||
Deferred tax asset valuation allowance(a)
|
57 | (9 | ) | | 33 | (d) | 15 | |||||||||||||
Price-risk management credit reserves assets(a)
|
1 | 1 | (e) | 4 | (g) | | 6 | |||||||||||||
Price-risk management credit reserves liabilities(b)
|
| (16 | )(e) | 1 | (g) | | (15 | ) | ||||||||||||
Year ended December 31, 2007:
|
||||||||||||||||||||
Allowance for doubtful accounts accounts and notes
receivable(a)
|
15 | 12 | | | 27 | |||||||||||||||
Deferred tax asset valuation allowance(a)
|
36 | 21 | | | 57 | |||||||||||||||
Price-risk management credit reserves assets(a)
|
7 | (6 | )(e) | | | 1 | ||||||||||||||
Processing plant major maintenance accrual
|
8 | | | 8 | (c) | | ||||||||||||||
Year ended December 31, 2006:
|
||||||||||||||||||||
Allowance for doubtful accounts accounts and notes
receivable(a)
|
86 | 4 | (66 | )(f) | 9 | (d) | 15 | |||||||||||||
Deferred tax asset valuation allowance(a)
|
37 | (1 | ) | | | 36 | ||||||||||||||
Price-risk management credit reserves assets(a)
|
15 | (8 | )(e) | | | 7 | ||||||||||||||
Processing plant major maintenance accrual(h)
|
7 | 2 | | 1 | 8 |
(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) | During 2006, $66 million in previously reserved Enron receivables were sold. | |
(g) | Included in accumulated other comprehensive loss . | |
(h) | Included in accrued liabilities in 2006. |
146
Item 9.
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure
Item 9A.
Controls
and Procedures
Item 9B.
Other
Information
147
Table of Contents
150
151
152
153
154
Item 10.
Directors,
Executive Officers and Corporate Governance
Item 11.
Executive
Compensation
Item 12.
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
Item 13.
Certain
Relationships and Related Transactions, and Director
Independence
148
Table of Contents
Item 14.
Principal
Accountant Fees and Services
Item 15.
Exhibits,
Financial Statement Schedules
Page
81
82
83
84
85
146
139
142
Exhibit
3
.1
Restated Certificate of Incorporation, as supplemented (filed on
March 11, 2005 as Exhibit 3.1 to The Williams Companies,
Inc.s Form 10-K) 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
Trust Company, N.A., as Trustee, dated as of January 17, 2001
(filed on March 12, 2001 as Exhibit 4(j) to The Williams
Companies, Inc.s Form 10-K) and incorporated herein by
reference.
4
.3
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
.4
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.
149
Table of Contents
Exhibit
4
.5
Form of Senior Debt Indenture between Williams Holdings of
Delaware, Inc. and Citibank, N.A., as Trustee (filed on October
18, 1995 as Exhibit 4.1 to Williams Holdings of Delaware,
Inc.s Form 10-Q) and incorporated herein by reference.
4
.6
First Supplemental Indenture dated as of July 31, 1999, among
Williams Holdings of Delaware, Inc., Citibank, N.A., as Trustee
(filed on March 28, 2000 as Exhibit 4(o) to The Williams
Companies, Inc.s Form 10-K) and incorporated herein by
reference.
4
.7
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
.8
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
.9
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
.10
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
.11
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
.12
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
.13
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
.14
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
.15
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
.16
Senior Indenture, dated as of November 30, 1995, between
Northwest Pipeline Corporation and Chemical Bank, Trustee with
regard to Northwest Pipelines 7.125% Debentures, due
2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest
Pipelines Form S-3) and incorporated herein by reference.
4
.17
Indenture dated as of June 22, 2006, between Northwest Pipeline
Corporation and JPMorgan Chase Bank, N.A., as Trustee, with
regard to Northwest Pipelines $175 million aggregate
principal amount of 7.00% Senior Notes due 2016 (filed on
June 23, 2006 as Exhibit 4.1 to Northwest Pipelines
Form 8-K)
and incorporated herein by reference.
4
.18
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 Corporations Form 8-K)
(Commission File number 001-07414) and incorporated herein by
reference.
Table of Contents
Exhibit
4
.19
Registration Rights Agreement, dated as of April 5, 2007,
among Northwest Pipeline Corporation and Greenwich Capital
Markets, Inc. and Banc of America Securities LLC, acting on
behalf of themselves and the several initial purchasers listed
on Schedule I thereto (filed on April 6, 2007 as
Exhibit 10.1 to Northwest Pipeline Corporations
Form 8-K)
and incorporated herein by reference.
4
.20
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 GPs
Form 8-K)
and incorporated herein by reference.
4
.21
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 GPs Form 8-K) and
incorporated herein by reference.
4
.22
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 Corporations Form S-3) and
incorporated herein by reference.
4
.23
Senior Indenture dated as of January 16, 1998 between
Transcontinental Gas Pipe Line Corporation and Citibank, N.A.,
as Trustee (filed on September 8, 1997 as Exhibit 4.1 to
Transcontinental Gas Pipe Line Corporations 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 Corporations 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 December 17, 2004 between Transcontinental Gas
Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee
(filed on December 21, 2004 as Exhibit 4.1 to Transcontinental
Gas Pipe Line Corporations Form 8-K) and incorporated
herein by reference.
4
.27
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 Lines
$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 Corporations Form 8-K) and
incorporated herein by reference.
4
.28
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 Corporations Form 8-K) and
incorporated herein by reference.
4
.29
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 Corporations
Form 8-K)
and incorporated herein by reference.
4
.30
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
.31
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.
10
.1*
The Williams Companies Amended and Restated Retirement
Restoration Plan effective January 1, 2008.
10
.2
The Williams Companies, Inc. Stock Plan for Non-Officer
Employees (filed on March 27, 1996 as Exhibit 10(iii)(g) to The
Williams Companies, Inc.s Form 10-K) and incorporated
herein by reference.
Table of Contents
Exhibit
10
.3
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
.4
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
.5
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
.6
Form of 2008 Performance-Based Restricted Stock Unit Agreement
among Williams and certain employees and officers (filed on
February 29, 2008 as Exhibit 99.1 to The Williams Companies,
Inc.s Form 8-K) and incorporated herein by reference.
10
.7
Form of 2008 Restricted Stock Unit Agreement among Williams and
certain employees and officers (filed on February 29, 2008 as
Exhibit 99.2 to The Williams Companies, Inc.s Form 8-K)
and incorporated herein by reference.
10
.8
Form of 2008 Nonqualified Stock Option Agreement among Williams
and certain employees and officers (filed on February 29, 2008
as Exhibit 99.1 to The Williams Companies, Inc.s Form 8-K)
and incorporated herein by reference.
10
.9*
Form of 2008 Restricted Stock Unit Agreement among Williams and
non-management directors.
10
.10
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
.11*
Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive
Plan.
10
.12*
Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive
Plan.
10
.13
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
.14*
Amendment No. 1 to The Williams Companies, Inc. 2007 Incentive
Plan.
10
.15
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
.16*
Amendment No. 1 to The Williams Companies, Inc. Employee Stock
Purchase Plan.
10
.17*
Amendment No. 2 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.
10
.19*
The Williams Companies, Inc. Severance Pay Plan.
10
.20*
Confidential Separation Agreement and Release between The
Williams Companies, Inc. and Michael P. Johnson dated April 2,
2008 (filed on May 1, 2008 as Exhibit 10.4 to The Williams
Companies, Inc.s Form 10-Q) and incorporated herein by
reference.
10
.21
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
.22
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
.23
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.
Table of Contents
Exhibit
10
.24
U.S. $400,000,000 Five Year Credit Agreement dated January 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 January 26, 2005 as Exhibit
10.3 to The Williams Companies, Inc.s Form 8-K) and
incorporated herein by reference.
10
.25
U.S. $100,000,000 Five Year Credit Agreement dated January 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 January 26, 2005 as Exhibit
10.4 to The Williams Companies, Inc.s Form 8-K) and
incorporated herein by reference.
10
.26
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
.27
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
.28
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
.29
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
.30
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
.31
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
.32
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
.33
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
.34
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.
12*
Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements.
14
Code of Ethics (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.
Table of Contents
Exhibit
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.
*
Filed herewith
Table of Contents
(Registrant)
By:
President, Chief Executive Officer
and Chairman of the Board
(Principal Executive Officer)
February 24, 2009
Senior Vice President and Chief
Financial Officer
(Principal Financial Officer)
February 24, 2009
Controller (Principal Accounting
Officer)
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
155
Table of Contents
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
Director
February 24, 2009
*By:
Attorney-in-Fact
February 24, 2009
156
Table of Contents
Exhibit
3
.1
Restated Certificate of Incorporation, as supplemented (filed on
March 11, 2005 as Exhibit 3.1 to The Williams Companies,
Inc.s Form 10-K) 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
Trust Company, N.A., as Trustee, dated as of January 17, 2001
(filed on March 12, 2001 as Exhibit 4(j) to The Williams
Companies, Inc.s Form 10-K) and incorporated herein by
reference.
4
.3
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
.4
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
.5
Form of Senior Debt Indenture between Williams Holdings of
Delaware, Inc. and Citibank, N.A., as Trustee (filed on October
18, 1995 as Exhibit 4.1 to Williams Holdings of Delaware,
Inc.s Form 10-Q) and incorporated herein by reference.
4
.6
First Supplemental Indenture dated as of July 31, 1999, among
Williams Holdings of Delaware, Inc., Citibank, N.A., as Trustee
(filed on March 28, 2000 as Exhibit 4(o) to The Williams
Companies, Inc.s Form 10-K) and incorporated herein by
reference.
4
.7
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
.8
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
.9
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
.10
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
.11
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
.12
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
.13
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
.14
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.
Table of Contents
Exhibit
4
.15
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
.16
Senior Indenture, dated as of November 30, 1995, between
Northwest Pipeline Corporation and Chemical Bank, Trustee with
regard to Northwest Pipelines 7.125% Debentures, due
2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest
Pipelines Form S-3) and incorporated herein by reference.
4
.17
Indenture dated as of June 22, 2006, between Northwest Pipeline
Corporation and JPMorgan Chase Bank, N.A., as Trustee, with
regard to Northwest Pipelines $175 million aggregate
principal amount of 7.00% Senior Notes due 2016 (filed on
June 23, 2006 as Exhibit 4.1 to Northwest Pipelines
Form 8-K)
and incorporated herein by reference.
4
.18
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 Corporations Form 8-K)
(Commission File number 001-07414) and incorporated herein by
reference.
4
.19
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 GPs
Form 8-K)
and incorporated herein by reference.
4
.20
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 GPs Form 8-K) and
incorporated herein by reference.
4
.21
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 Corporations Form S-3) and
incorporated herein by reference.
4
.22
Senior Indenture dated as of January 16, 1998 between
Transcontinental Gas Pipe Line Corporation and Citibank, N.A.,
as Trustee (filed on September 8, 1997 as Exhibit 4.1 to
Transcontinental Gas Pipe Line Corporations Form S-3) and
incorporated herein by reference.
4
.23
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 Corporations Form S-4) and incorporated herein by
reference.
4
.24
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
.25
Indenture dated December 17, 2004 between Transcontinental Gas
Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee
(filed on December 21, 2004 as Exhibit 4.1 to Transcontinental
Gas Pipe Line Corporations Form 8-K) 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 Lines
$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 Corporations 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 Corporations 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 Corporations
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.
Table of Contents
Exhibit
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.
10
.1*
The Williams Companies Amended and Restated Retirement
Restoration Plan effective January 1, 2008.
10
.2
The Williams Companies, Inc. Stock Plan for Non-Officer
Employees (filed on March 27, 1996 as Exhibit 10(iii)(g) to The
Williams Companies, Inc.s Form 10-K) and incorporated
herein by reference.
10
.3
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
.4
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
.5
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
.6
Form of 2008 Performance-Based Restricted Stock Unit Agreement
among Williams and certain employees and officers (filed on
February 29, 2008 as Exhibit 99.1 to The Williams Companies,
Inc.s Form 8-K) and incorporated herein by reference.
10
.7
Form of 2008 Restricted Stock Unit Agreement among Williams and
certain employees and officers (filed on February 29, 2008 as
Exhibit 99.2 to The Williams Companies, Inc.s Form 8-K)
and incorporated herein by reference.
10
.8
Form of 2008 Nonqualified Stock Option Agreement among Williams
and certain employees and officers (filed on February 29, 2008
as Exhibit 99.1 to The Williams Companies, Inc.s Form 8-K)
and incorporated herein by reference.
10
.9*
Form of 2008 Restricted Stock Unit Agreement among Williams and
non-management directors.
10
.10
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
.11*
Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive
Plan.
10
.12*
Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive
Plan.
10
.13
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
.14*
Amendment No. 1 to The Williams Companies, Inc. 2007 Incentive
Plan.
10
.15
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
.16*
Amendment No. 1 to The Williams Companies, Inc. Employee Stock
Purchase Plan.
10
.17*
Amendment No. 2 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.
10
.19*
The Williams Companies, Inc. Severance Pay Plan.
10
.20*
Confidential Separation Agreement and Release between The
Williams Companies, Inc. and Michael P. Johnson dated April 2,
2008 (filed on May 1, 2008 as Exhibit 10.4 to The Williams
Companies, Inc.s Form 10-Q) and incorporated herein by
reference.
10
.21
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.
Table of Contents
Exhibit
10
.22
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
.23
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
.24
U.S. $400,000,000 Five Year Credit Agreement dated January 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 January 26, 2005 as Exhibit
10.3 to The Williams Companies, Inc.s Form 8-K) and
incorporated herein by reference.
10
.25
U.S. $100,000,000 Five Year Credit Agreement dated January 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 January 26, 2005 as Exhibit
10.4 to The Williams Companies, Inc.s Form 8-K) and
incorporated herein by reference.
10
.26
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
.27
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
.28
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
.29
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
.30
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
.31
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
.32
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
.33
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.
Table of Contents
Exhibit
10
.34
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.
12*
Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements.
14
Code of Ethics (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.
*
Filed herewith
2
3
4
5
6
7
8
9
10
11
12
13
Credit Rate For | ||||||||||||||
Credit Rate On | Past Service*** | |||||||||||||
Credit Rate On | Supplemental | On All | ||||||||||||
Supplemental | Retirement | Supplemental | ||||||||||||
Age* on | Retirement | Compensation | Retirement | |||||||||||
Credit Date | Compensation | Above Wage Base** | Compensation | |||||||||||
Prior to 29
|
4.50 | % | + | 1.00 | % | + | 0.30% x Past Service | |||||||
29
|
4.50 | % | + | See **** below | + | 0.30% x Past Service | ||||||||
30 through 39
|
6.00 | % | + | 2.00 | % | + | 0.30% x Past Service | |||||||
40 through 49
|
8.00 | % | + | 3.00 | % | + | 0.30% x Past Service | |||||||
50 and older
|
10.00 | % | + | 5.00 | % | + | 0.30% x Past Service |
Credit Rate On | Credit Rate | |||||||||
Supplemental | On Supplemental | |||||||||
Retirement | Retirement Compensation | |||||||||
Age* on Credit Date | Compensation | Above Wage Base** | ||||||||
Prior to 29
|
4.50 | % | + | 1.00 | % | |||||
29
|
4.50 | % | + | See **** below | ||||||
30 through 39
|
6.00 | % | + | 2.00 | % | |||||
40 through 49
|
8.00 | % | + | 3.00 | % | |||||
50 and older
|
10.00 | % | + | 5.00 | % |
* |
Age means actual age measured in years attained as of the applicable Credit Date.
|
|
** | Wage Base means the taxable wage base under the Federal Insurance Contributions Act applicable for the Plan Year of the applicable Credit Date (Plan Year of Disability for a disabled Participant accruing Compensation Credit pursuant to Section 5.3 of the Pension Plan). | |
*** | Past Service means Benefit Service credited as of March 31, 1998. |
14
**** | For Plan Years beginning on or after January 1, 2002, and before January 1, 2008, the rate is 1.00% on Compensation up to 170 percent of the Wage base and the rate is 1.13% on Compensation greater than 170 percent of the Wage Base. For Plan Years beginning on or after January 1, 2008, the rate is 1.20% on Compensation above the Wage Base. |
15
16
17
Aggregate of Attained | ||||||||||||||||
Age and Credited | ||||||||||||||||
Benefit Service as of | Multiplier Percentage for Attained | |||||||||||||||
March 31, 1998 | Age at Benefit Starting Date | |||||||||||||||
55 62 | 63 | 64 | 65 | |||||||||||||
55 64
|
115 | % | 115 | % | 108 | % | 100 | % | ||||||||
65 69
|
120 | % | 120 | % | 108 | % | 100 | % | ||||||||
70 and over
|
125 | % | 122 | % | 108 | % | 100 | % |
18
19
20
21
22
23
24
25
THE WILLIAMS COMPANIES, INC. | ||||||
|
||||||
|
By:
Title: |
/s/ Stephanie Cipolla
|
26
ESTABLISHMENT OF PLAN
|
1 | |||
|
||||
ARTICLE I
|
2 | |||
Introduction
|
2 | |||
|
||||
ARTICLE II
|
4 | |||
Definitions
|
4 | |||
2.1 Actuarial Equivalent
|
4 | |||
2.2 Base Pay
|
4 | |||
2.3 Basic Supplemental Benefit
|
5 | |||
2.4 Beneficiary
|
5 | |||
2.5 Benefit Starting Date
|
5 | |||
2.6 Board
|
5 | |||
2.7 Change in Control
|
5 | |||
2.8 Code
|
9 | |||
2.9 Code Limitations
|
9 | |||
2.10 Committee
|
9 | |||
2.11 Company
|
9 | |||
2.12 Credit Date
|
9 | |||
2.13 Death Benefit
|
9 | |||
2.14 Disability
|
9 | |||
2.15 Eligible Employee
|
9 | |||
2.16 Employee
|
10 | |||
2.17 Employer
|
10 | |||
2.18 Former Participant
|
10 | |||
2.19 Key Employee
|
10 | |||
2.20 Nonservice Participant
|
10 | |||
2.21 Normalized Pension Benefit
|
10 | |||
2.22 Participant
|
11 | |||
2.23 Pension Plan
|
11 | |||
2.24 Pension Plan Benefit
|
11 | |||
2.25 Plan
|
11 | |||
2.26 Plan Interest Rate
|
11 | |||
2.27 Plan Year
|
12 | |||
2.28 Rule of 55 Participant
|
12 | |||
2.29 Separation from Service
|
12 | |||
2.30 Service Participant
|
13 | |||
2.31 Supplemental Compensation Credit
|
13 | |||
2.32 Supplemental Interest Credit
|
15 | |||
2.33 Supplemental Pension Account
|
15 | |||
2.34 Supplemental Retirement Benefit
|
15 | |||
2.35 Supplemental Retirement Compensation
|
15 | |||
2.36 Supplemental Survivor Pension
|
16 | |||
2.37 Surviving Spouse
|
17 | |||
2.38 Termination of Employment
|
17 |
27
2.39 Transitional Participant
|
17 | |||
2.40 Vested Participant
|
17 | |||
|
||||
ARTICLE III
|
17 | |||
Supplemental Retirement Benefits
|
17 | |||
3.1 Restoration of Credited Service for a Transitional Participant
|
17 | |||
3.2 Cash Balance Supplemental Retirement Benefit for a Vested Participant
|
18 | |||
3.3 Cash Balance Supplemental Early Retirement Benefit
|
18 | |||
3.4 Supplemental Disability Benefit
|
18 | |||
|
||||
ARTICLE IV
|
19 | |||
Vesting and Forfeitures
|
19 | |||
4.1 Vesting
|
19 | |||
4.2 Forfeitures
|
19 | |||
|
||||
ARTICLE V
|
19 | |||
Death Benefit
|
19 | |||
5.1 Cash Balance Supplemental Survivor Pension
|
19 | |||
5.2 Payment of Death Benefit
|
20 | |||
5.3 Non-duplication of Benefits
|
20 | |||
|
||||
ARTICLE VI
|
20 | |||
Administration of the Plan
|
20 | |||
6.1 Administration by Committee
|
20 | |||
6.2 Operation of the Committee
|
20 | |||
6.3 Powers and Duties of the Committee
|
20 | |||
6.4 Required Information
|
22 | |||
6.5 Compensation and Expenses
|
22 | |||
6.6 Indemnification
|
22 | |||
6.7 Claims Procedure
|
23 | |||
|
||||
ARTICLE VII
|
23 | |||
Miscellaneous
|
23 | |||
7.1 Benefits Payable by the Employers
|
23 | |||
7.2 Amendment or Termination
|
24 | |||
7.3 Status of Employment
|
25 | |||
7.4 Payments to Minors and Incompetents
|
25 | |||
7.5 Inalienability of Benefits
|
25 | |||
7.6 Qualified Domestic Relations Orders
|
25 | |||
7.7 Governing Law
|
26 |
28
2
3
THE WILLIAMS COMPANIES, INC.
|
||||
By: | ||||
Steven J. Malcolm | ||||
President and CEO | ||||
4
/s/ Stephanie Cipolla
|
Date: 12/1/08 | ||
|
/s/ Stephanie Cipolla
|
Date: 12/1/08 | ||
|
Article I Definitions
|
1 | |||
|
||||
1.1 Accrued Annual Bonus
|
1 | |||
1.2 Accrued Base Salary
|
1 | |||
1.3 Accrued Obligations
|
2 | |||
1.4 Affiliate
|
2 | |||
1.5 Agreement Date
|
2 | |||
1.6 Agreement Term
|
2 | |||
1.7 Annual Bonus
|
2 | |||
1.8 Article
|
2 | |||
1.9 Base Salary
|
2 | |||
1.10 Beneficial Owner
|
3 | |||
1.11 Beneficiary
|
3 | |||
1.12 Board
|
3 | |||
1.13 Cause
|
3 | |||
1.14 Cause Determination
|
4 | |||
1.15 Change Date
|
4 | |||
1.16 Change in Control
|
4 | |||
1.17 Code
|
5 | |||
1.18 Competitive Business
|
5 | |||
1.19 Confidential Information
|
5 | |||
1.20 Consummation Date
|
6 | |||
1.21 Disability
|
6 | |||
1.22 Disqualifying Disaggregation
|
6 | |||
1.23 Employer
|
6 | |||
1.24 ERISA
|
7 | |||
1.25 Exchange Act
|
7 | |||
1.26 Good Reason
|
7 | |||
1.27 Gross-Up Payment
|
8 | |||
1.28 including
|
8 | |||
1.29 IRS
|
8 | |||
1.30 Legal and Other Expenses
|
8 | |||
1.31 Notice of Consideration
|
8 | |||
1.32 Notice of Termination
|
8 | |||
1.33 Person
|
8 | |||
1.34 Post-Change Period
|
8 | |||
1.35 Potential Parachute Payment
|
8 | |||
1.36 Pro-rata Annual Bonus
|
8 |
i
1.37 Reorganization Transaction
|
9 | |||
1.38 Restricted Shares
|
9 | |||
1.39 SEC
|
9 | |||
1.40 Section
|
9 | |||
1.41 Separation from Service
|
9 | |||
1.42 Stock Options
|
9 | |||
1.43 Subsidiary
|
10 | |||
1.44 Surviving Corporation
|
10 | |||
1.45 Target Annual Bonus
|
10 | |||
1.46 Taxes
|
10 | |||
1.47 Termination Date
|
10 | |||
1.48 Voting Securities
|
10 | |||
1.49 Williams
|
11 | |||
1.50 Williams Incumbent Directors
|
11 | |||
1.51 Williams Parties
|
11 | |||
1.52 Work Product
|
11 | |||
|
||||
Article II Williams Obligations Upon Separation from Service
|
11 | |||
|
||||
2.1 If By Executive for Good Reason or By an
Employer Other Than for Cause, Disability or
Disqualifying Disaggregation
|
11 | |||
2.2 If by the Employer for Cause
|
13 | |||
2.3 If by an Executive Other Than for Good Reason
|
14 | |||
2.4 If by Death or Disability
|
14 | |||
2.5 Waiver and Release
|
15 | |||
2.6 Breach of Covenants
|
15 | |||
|
||||
Article III Certain Additional Payments by Williams
|
15 | |||
|
||||
3.1 Gross-Up Payment
|
15 | |||
3.2 Gross-Up Payment
|
16 | |||
3.3 Limitations on Gross-Up Payments
|
16 | |||
3.4 Additional Gross-up Amounts
|
16 | |||
3.5 Amount Increased or Contested
|
17 | |||
3.6 Refunds
|
19 | |||
|
||||
Article IV Expenses and Interest
|
19 | |||
|
||||
4.1 Legal and Other Expenses
|
19 | |||
4.2 Interest
|
20 | |||
|
||||
Article V No Set-off or Mitigation
|
20 | |||
|
||||
5.1 No Set-off by Williams
|
20 | |||
5.2 No Mitigation
|
20 | |||
|
||||
Article VI Restrictive Covenants
|
21 | |||
|
||||
6.1 Confidential Information
|
21 | |||
6.2 Non-Competition
|
21 |
ii
6.3 Non-Solicitation
|
22 | |||
6.4 Intellectual Property
|
22 | |||
6.5 Non-Disparagement
|
23 | |||
6.6 Reasonableness of Restrictive Covenants
|
24 | |||
6.7 Right to Injunction: Survival of Undertakings
|
24 | |||
|
||||
Article VII Non-Exclusivity of Rights
|
25 | |||
|
||||
7.1 Waiver of Certain Other Rights
|
25 | |||
7.2 Other Rights
|
25 | |||
7.3 No Right to Continued Employment
|
25 | |||
|
||||
Article VIII Claims Procedure
|
26 |
8.1 Filing a Claim
|
26 | |||
8.2 Review of Claim Denial
|
26 | |||
|
||||
Article IX Miscellaneous
|
26 | |||
|
||||
9.1 No Assignability
|
26 | |||
9.2 Successors
|
27 | |||
9.3 Payments to Beneficiary
|
27 | |||
9.4 Non-Alienation of Benefits
|
27 | |||
9.5 Severability
|
27 | |||
9.6 Amendments
|
27 | |||
9.7 Notices
|
28 | |||
9.8 Joint and Several Liability
|
28 | |||
9.9 Counterparts
|
28 | |||
9.10 Governing Law
|
28 | |||
9.11 Captions
|
28 | |||
9.12 Rules of Construction
|
28 | |||
9.13 Number and Gender
|
28 | |||
9.14 Tax Withholding
|
28 | |||
9.15 No Rights Prior to Change Date
|
29 | |||
9.16 Entire Agreement
|
29 |
iii
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[INSERT EXECUTIVE NAME] | ||||||
|
||||||
|
Date: | |||||
|
|
|||||
|
||||||
THE WILLIAMS COMPANIES, INC., acting on behalf of itself and its Subsidiaries and Affiliates | ||||||
|
||||||
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By: | |||||
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|
|||||
|
Title: | |||||
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|
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|
Date: | |||||
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|
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[INSERT EXECUTIVE NAME] | ||||||
|
||||||
|
Date: | |||||
|
|
|||||
|
||||||
THE WILLIAMS COMPANIES, INC. | ||||||
|
||||||
|
By: | |||||
|
|
|||||
|
Title: | |||||
|
|
|||||
|
Date: | |||||
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32
|
||
|
[INSERT EXECUTIVES NAME] |
1.1 | Administrative Committee means the committee appointed to administer this Plan which is comprised of those individuals who are serving on the Administrative Committee on December 31, 2004, as well as any individual who becomes a member of the Administrative Committee pursuant to Section 5.4, until the time that any such individual ceases to be a member of the Administrative Committee pursuant to Section 5.4 of the Plan. The duties of the Administrative Committee are described in Article 5 of the Plan. |
1.2 | Affiliate means any Person that directly or indirectly, through one (1) or more intermediaries, controls, is controlled by or is under common control with the Company. |
1.3 | Aggregate Compensation means Regular Wage Base and any annual cash incentive awards from a Participating Company or Affiliate annual incentive program. |
1.4 | Base Salary means the amount a Participant is entitled to receive as wages or salary on an annualized basis, including any salary deferral contributions made to any defined contribution plan maintained by the Participating Company and any amounts contributed by an Employee to any cafeteria plan, flexible benefits plan or qualified transportation plan maintained by the Participating Company in accordance with Sections 125, 132 and related provisions of the Code, but excluding all special pay, bonus, overtime, incentive compensation, commissions, cost of living pay, housing pay, relocation pay, other taxable fringe benefits and all extraordinary compensation, payable by the Company or any of its Affiliates as consideration for the Participants services, as determined on the date immediately preceding termination of employment, except that in the case of a termination of employment for Good Reason, Base Salary shall be determined as of the date immediately preceding the event which constitutes Good Reason. |
1.5 | Benefits Committee means the committee comprised of those individuals who were serving on the Benefits Committee on December 31, 2004, as well as any individual who becomes a member of the Benefits Committee pursuant to Section 5.3, until the time that any such individual ceases to be a member of the Benefits Committee pursuant to Section 5.3 of the Plan. The purely settlor duties of the Benefits Committee are described in Articles 5 and 6 of the Plan. |
2
1.6 | Board of Directors means the board of directors of the Company. |
1.7 | Cause means the occurrence of any one (1) or more of the following, as determined in the good faith and reasonable judgment of the Administrative Committee: |
1.8 | Change Date means the date on which a Change in Control first occurs. |
1.9 | Change in Control means the occurrence of: (i) a Change in the Ownership of the Company, as defined below; (ii) a Change in Effective Control of the Company, as defined below; or (iii) a Change in the Ownership of a Substantial Portion of the Assets of the Company, as defined below. To qualify as a Change in Control event, the occurrence of the event shall be objectively determinable, strictly ministerial, and shall not involve any discretionary authority by the Plan Administrator. Code Section 318(a) shall be applied to determine stock ownership for purposes of this section. Substantially vested stock underlying a vested option is considered owned by the person who holds the vested option (and the stock underlying an unvested option is not considered owned by the person who holds an unvested option). To qualify as a Change in Control with respect to a Participant, the Change in Control must relate to: (x) the corporation for whom the Participant is performing services at the time of the Change in Control event; (y) the corporation that is liable for the payment of benefits under this Plan (or all corporations which are liable for payment if more than one corporation is liable) but only if either the benefits are attributable to the performance of service by the Participant for such corporation (or corporations) or there is a bona fide business purpose for such corporation (or corporations) to be liable for such payment and, in either case, no significant purpose of making such corporation or corporations liable for such payment is the avoidance of Federal income tax; or (z) a corporation that is a majority shareholder of a corporation identified in subsections (x) or (y) above, or any corporation in a chain of corporations in which each corporation is a majority shareholder of another corporation in the chain, ending in a corporation identified in subsections (x) or (y) above. The provisions of Treas. Reg. § 1.409A-3, as amended, shall govern with respect to the |
3
definition of terms as used therein and in the interpretation of whether a Change in Control has occurred. |
4
1.10 | Code means the Internal Revenue Code of 1986, as amended from time to time. References to a particular section of the Code include references to regulations and rulings thereunder and to successor provisions. |
1.11 | Company means The Williams Companies, Inc., a Delaware corporation and any successor or successors thereto that continue this Plan pursuant to Section 6.1 or otherwise. |
1.12 | Compensation Committee means the Committee of the Board of Directors designated as the Compensation Committee. |
1.13 | Comparable Offer of Employment means an offer of employment for a position with the Company, any of its Affiliates, or any successor of the Company or its Affiliates that provides for a Regular Wage Base equal to or greater than the Participants Regular Wage Base immediately preceding the Participants termination date. A successor of the Company or any of its Affiliates shall include, but shall not be limited to, any entity (or its Affiliate) involved in or in any way connected with a corporate rearrangement, total or partial merger, acquisition, sale of stock, sale of assets or any other transaction. A Comparable Offer of Employment includes, without limitation, a position that requires the Employee to transfer to a different work location (without your consent), but only so long as the Employees commuting distance to the new work location is not increased more than fifty (50) miles beyond the commuting distance to his or her current work location (except for travel reasonably required in the performance of your duties). |
5
1.14 | Effective Date means January 1, 2008, which is the effective date of this amendment and restatement. |
1.15 | Employee means any regular full-time or part-time employee in the service and on the payroll of a Participating Company as a common law employee with the exception of any employee who is excluded either by this Section 1.15 or Section 2.2. An Employee is considered as part-time if he is regularly scheduled to work at least fifty percent of the number of hours in the normal workweek established by a Participating Company. A regular employee receiving benefits under a Participating Companys Short-Term Disability Program or Long-Term Disability Program is an Employee for purposes of this Plan. Employee shall not include: |
6
1.16 | ERISA means the Employee Retirement Income Security Act of 1974, as amended from time to time. References to a particular section of ERISA include references to regulations and rulings thereunder and to successor provisions. |
1.17 | Good Reason means the occurrence, within a pre-determined limited period of time not to exceed two (2) years following the initial existence of one (1) or more of the following conditions arising without the consent of the Participant: |
7
1.18 | Leave of Absence means an absence, with or without compensation, authorized on a non-discriminatory basis by the Company or any of its Affiliates. For the purposes of this Plan, Leave of Absence includes any leave of absence other than a Family and Medical Leave of Absence or Military Leave of Absence. |
1.19 | Participant means an Employee participating in the Plan as provided in Article 2. |
1.20 | Participating Company means the Company and any Affiliate of the Company, which has adopted this Plan in accordance with Section 6.11. |
1.21 | Person means any individual, sole proprietorship, partnership, joint venture, limited liability company, trust, unincorporated organization, association, corporation, institution, public benefit corporate entity or government instrumentality, division, agency, body or department. |
1.22 | Plan means The Williams Companies, Inc. Severance Pay Plan. |
1.23 | Plan Administrator means the Administrative Committee appointed under Article 5. |
1.24 | Plan Year means the twelve (12) month period from January 1 through December 31. |
1.25 | Regular Wage Base means an Employees total weekly salary or wages, including any salary deferral contributions made to any defined contribution plan maintained by the Participating Company and any amounts contributed by an Employee to any cafeteria plan, flexible benefit plan or qualified transportation plan maintained by the Participating Company in accordance with Sections 125, 132 and related provisions of the Code, but excluding any bonuses, overtime, incentive compensation, commissions, cost of living pay, housing pay, relocation pay, other taxable fringe benefits and all other extraordinary compensation. |
8
1.26 | Related Party means an Affiliate or any employee benefit plan (or any related trust) sponsored or maintained by the Company or any of its Affiliates. |
1.27 | Sponsor means The Williams Companies, Inc., a Delaware corporation. | |
1.28 | Years of Service means a Participants length of service with the Participating Company as set by the latest hire date or rehire date of such Participant. For purposes of this Plan, after the first year of service as a Participant, only full, completed years of service will be counted. Service with a predecessor company will not be included unless, and to the extent that, the Plan Administrator determines such service be included and notifies the Participant in writing that such service is included. Notwithstanding anything to the contrary above, effective as of January 1, 2008, with respect to a participant who was outsourced to International Business Machines Corporation (IBM) at some point on or after July 1, 2004, that was subsequently in-sourced back to the Company or any of its Participating Companies with no break in service between his or her outsourced employment with IBM and his or her in-sourcing back to the Company or any Participating Companies, then such Participants latest hire date prior to the outsourcing to IBM shall be used to determine the number of Years of Service and in addition, the time spent at IBM during the outsourcing prior to the direct in-sourcing shall also be included in the determination of the number of Years of Service for such Participant. |
2.1 | Eligibility . Any Employee, who is not excluded pursuant to Section 2.2, shall be entitled to become a Participant in the Plan only when and only if all of the following conditions of subsection (a), (b) or (c) are met: |
9
2.2 | Exclusions . Notwithstanding the provisions of Section 2.1, an Employee will not become a Participant in the Plan if any of the following conditions occur: |
10
3.1 | Severance Pay . Except as provided in Section 3.7, subject to the Participant signing a release of claims prepared by the Company within fifty (50) days of termination date, a Participant will be eligible for severance pay benefits under this Section 3.1 equal to: |
3.2 | Change in Control Severance Pay . Subject to the Participant signing a release of claims prepared by the Company within fifty (50) days of termination of employment, if a Participants employment is terminated for Good Reason or involuntarily within two (2) years after a Change in Control, the Participant will be eligible for severance pay benefits under this Section 3.2 in lieu of any benefits under Section 3.1 with the amount of such benefits equal to the sum of: |
11
3.3 | Notice . Any Participant who is terminated and receives less than two (2) weeks notice from a Participating Company will receive, in addition to the benefits provided in Section 3.1 or 3.2 (whichever applies), severance pay for the lack of notice. Weeks or fractions thereof, will be granted which is equal to the difference between two (2) weeks and the number of days notice received by the Participant. The amount of severance pay will be equal to the number of weeks and/or fractions thereof granted to a Participant under this Section 3.3 times the Participants Regular Wage Base. No payment will be made under this Section 3.3 if total severance pay exceeds the maximum benefit allowed. |
3.4 | Form of Payment . Severance benefits payable to a Participant under Section 3.1 shall be paid in a lump sum no later than sixty (60) days from the date of the Participants termination of employment. |
3.5 | Other Benefit Plans . Participants, regardless of whether they sign the release of claims required to receive severance payments, who are otherwise entitled to receive severance pay and who are eligible to continue participation in certain welfare benefit plans may choose to continue their participation in accordance with this Section 3.5. Continued participation in such welfare benefit plans is subject to the terms and conditions of the applicable plan documents or insurance contracts in effect on the date of the Participants termination from employment. Generally, the Participant has the option to elect the currently maintained Participating Company group medical and dental plan that he is currently enrolled for up to 18 months under the Consolidated Omnibus Budget Reconciliation Act (COBRA) continuation coverage. If the Participant timely and properly elects COBRA coverage, the premiums for COBRA coverage will be limited to the active employee rate for the initial three months of coverage. At the end of this three-month period, the Participant will be required to pay the full cost for medical and/or dental benefits under COBRA for the remainder of the 18-month period. Participation in the Participating Company group medical and dental plan will generally cease on the date the Participant or his dependents become covered under any other medical plan or dental plan. |
3.6 | Paid-Time Off (PTO) Program . A Participant, regardless of whether he signs the release of claims required to receive severance payments, shall be paid a single lump sum payment for applicable PTO hours earned but not taken prior to the Participants employment termination. PTO time will not be considered for purposes of continued coverage under any of the other various employee benefit plans maintained by the Participating Company. |
12
3.7 | Rehired Participants after Receipt of Severance Pay . This Section 3.7 applies to Participants rehired by a Participating Company or any Affiliate after receipt of severance pay under Section 3.1. |
3.8 | Discretionary Benefits . Under no circumstances will any discretionary benefits be paid unless the senior officer of the Company responsible for compensation or benefits, or such senior officers designee, signs a written document describing such benefits. Payment of such discretionary benefits will be made only in accordance with the terms of that document. |
3.9 | No Vesting . Employees have no vested right to any benefits set forth in the Plan until such time as an Employee becomes entitled to receive benefits under Article 2; however, the Participant must timely execute a release in accordance with Section 3.1 or 3.2 (whichever applies) to receive any benefits under this Plan. |
3.10 | Integration with Plant Closing Law(s) . To the extent that a federal, state or local law, including, but not limited to the Worker Adjustment and Retraining Act, requires a Participating Company, as an employer, to provide notice and/or make a payment to an |
13
Employee because of that Employees involuntary termination, or pursuant to a plant closing law, the benefit payable under this Plan, including without limitation benefits payable under Section 3.3, shall be reduced by any Regular Wage Base paid during such notice period and/or by such other required payment. |
4.1 | Claims for Benefits . To obtain payment of any benefits under the Plan, a Participant must comply with such rules and procedures as the Plan Administrator may prescribe. |
4.2 | Claims Procedure . The Plan Administrator shall adopt, and may change from time to time, claims procedures, provided that such claims procedures and changes thereof shall conform to Section 503 of the Employee Retirement Income Security Act of 1974 and the regulations promulgated thereunder. Such claims procedures, as in effect from time to time, shall be deemed to be incorporated herein and made a part hereof. |
5.1 | Fiduciaries . Under certain circumstances, the Administrative Committee may be determined by a court of law to be a fiduciary with respect to a particular action under the Plan; provided that any claims administrator will be a named fiduciary with respect to claims and appeals related to benefit determinations. |
5.2 | Allocation of Responsibilities . |
5.3 | Provisions Concerning the Benefits Committee . |
14
5.4 | Provisions Concerning the Administrative Committee . |
15
16
5.5 | Delegation of Responsibilities; Bonding . |
5.6 | No Joint Fiduciary Responsibilities . This Plan is intended to allocate to the Administrative Committee the individual responsibility for the prudent execution of the functions assigned to it, and none of such responsibilities or any other responsibility shall be shared by any other entity unless such sharing is provided for by a specific provision of the Plan. Whenever one fiduciary is required herein to follow the directions of another fiduciary, the two fiduciaries shall not be deemed to have been assigned a shared responsibility, but the responsibility of a fiduciary receiving such directions shall be to follow them insofar as such instructions are on their face proper under applicable law. |
5.7 | Fiduciary Capacity . Any person or group of persons may serve in more than one fiduciary capacity with respect to the Plan. |
5.8 | Right to Receive and Release Necessary Information . The Administrative Committee may release or obtain any information necessary for the application, implementation and determination of this Plan or other Plans without consent or notice to any person. This |
17
information may be released to or obtained from any insurance company, organization or person. Any individual claiming benefits under this Plan shall release to the Administrative Committee such information as the Administrative Committee, in its sole and absolute discretion, determines to be necessary to implement this provision. |
6.2 | Duration . The Plan shall continue indefinitely unless terminated as provided in subsection 6.3 hereof. |
6.3 | Amendment and Termination . |
18
6.4 | Management Rights . Participation in the Plan shall not lessen or otherwise affect the responsibility of an Employee to perform fully his duties in a satisfactory and workmanlike manner. This Plan shall not be deemed to constitute a contract between a Participating Company and any Employee or other person whether or not in the employ of the Participating Company, nor shall anything herein contained be deemed to give any Employee or other person whether or not in the employ of a Participating Company any right to be retained in the employ of any Participating Company, or to interfere with the right of any Participating Company to discharge any Employee at any time and to treat him without any regard to the effect which such treatment might have upon him as an Employee covered by the Plan. |
6.5 | Funding . The Plan shall constitute an unfunded and unsecured obligation of the Participating Companies payable from the general funds of such Participating Companies. |
6.6 | Withholding of Taxes . Each Participating Company may withhold from any amounts payable under the Plan all federal, state, city and/or other taxes as shall be legally required. |
6.7 | Participants Responsibility . Each Participant (or personal representative of a deceased Participants estate) shall be responsible for providing the Administrative Committee with his current address. Any notices required or permitted to be given hereunder shall be deemed given if directed to such address and mailed by regular United States mail. The Administrative Committee shall not have any obligation or duty to locate a Participant. |
6.8 | Indemnification . Each Participating Company shall indemnify and hold harmless each member of the Board of Directors, each member of the Benefits Committee, each member of the Administrative Committee and each officer and employee of a Participating Company to whom are delegated duties, responsibilities, and authority with respect to this Plan against all claims, liabilities, fines and penalties, and all expenses reasonably incurred by or imposed upon him (including, but not limited to reasonable attorney fees) which arise as a result of his actions or failure to act in connection with the operation and administration of this Plan to the extent lawfully allowable and to the extent that such claim, liability, fine, penalty, or expense is not paid for by liability insurance purchased or paid for by a Participating Company. Notwithstanding the foregoing, a Participating Company shall not indemnify any person for any such amount incurred through any settlement or compromise |
19
of any action unless the Participating Company consents in writing to such settlement or compromise. |
6.9 | Governing Law . The Plan shall be governed by and construed in accordance with applicable Federal laws, including ERISA, governing employee benefit plans and in accordance with the laws of the State of Oklahoma where such laws are not in conflict with the aforementioned federal laws. |
6.10 | Right of Recovery . If any Participating Company makes payment(s) in excess of the amount required under the Plan, the Administrative Committee shall have the right to recover the excess payment(s) from any person who received the excess payment(s). Such recovery shall be returned by the Administrative Committee to such Participating Company. |
6.11 | Adoption by Participating Company . Any Affiliate may adopt or withdraw from this Plan. The adoption resolution may contain such specific changes and variations in this Plans terms and provisions applicable to the employees of the adopting Participating Company as may be acceptable to the Administrative Committee. |
6.12 | Code Section 409A . It is intended that this Plan meet the requirements of the short-term deferral exception from Section 409A of the Code and it is recognized that it may be necessary to modify this Plan to reflect guidance under Section 409A of the Code issued by the Internal Revenue Service. The Compensation Committee and the Benefits Committee shall have discretion in determining: (i) whether any modification of the Plan is desirable or appropriate; and (ii) the terms of any such modification. |
THE WILLIAMS COMPANIES, INC.
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By: | s/ Stephanie Cipolla | |||
Title: Vice President Human Resources | ||||
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Executive:
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Michael P. Johnson | |||
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Tulsa, OK | |||
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Company:
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The Williams Companies, Inc. | |||
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Attn: Vice President, Human Resources | |||
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One William Center | |||
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P. O. Box 2400 | |||
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Tulsa, Oklahoma 74102 |
8
THE WILLIAMS COMPANIES, INC. | ||||||
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By:
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Title:
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WITNESS: | |||||
Michael P. Johnson |
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WITNESS: | |
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Michael P. Johnson
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Consultant:
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Michael P. Johnson | |||
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Tulsa, OK | |||
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Company:
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The Williams Companies, Inc. | |||
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Attn: Vice President, Human Resources | |||
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One William Center | |||
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P. O. Box 2400 | |||
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Tulsa, Oklahoma 74102 |
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THE WILLIAMS COMPANIES, INC. | ||||||
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By:
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Title:
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WITNESS: | |
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Michael P. Johnson
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18
Years Ended December 31, | ||||||||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
(Dollars in millions) | ||||||||||||||||||||
Earnings:
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||||||||||||||||||||
Income from continuing operations before income
taxes and cumulative effect of change in accounting
principles
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$ | 2,047 | $ | 1,371 | $ | 558 | $ | 774 | $ | 299 | ||||||||||
Minority interest in income of consolidated subsidiaries
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174 | 90 | 40 | 26 | 21 | |||||||||||||||
Less: Equity earnings, excluding proportionate share
from 50% owned investees and unconsolidated
majority-owned investee
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(61 | ) | (60 | ) | (99 | ) | (66 | ) | (50 | ) | ||||||||||
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Income from continuing operations before income taxes
and cumulative effect of change in accounting principles,
minority interest in income of consolidated
subsidiaries and equity earnings
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2,160 | 1,401 | 499 | 734 | 270 | |||||||||||||||
Add:
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Fixed charges:
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Interest accrued, including proportionate share
from 50% owned investees and unconsolidated
majority-owned investee (a)
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675 | 709 | 694 | 680 | 822 | |||||||||||||||
Rental expense representative of interest factor
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21 | 22 | 16 | 19 | 18 | |||||||||||||||
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Total fixed charges
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696 | 731 | 710 | 699 | 840 | |||||||||||||||
Distributed income of equity-method investees,
excluding proportionate share from 50% owned
investees and unconsolidated majority-owned investee
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53 | 48 | 113 | 108 | 61 | |||||||||||||||
Less:
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Capitalized interest
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(59 | ) | (32 | ) | (17 | ) | (7 | ) | (7 | ) | ||||||||||
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Total earnings as adjusted
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$ | 2,850 | $ | 2,148 | $ | 1,305 | $ | 1,534 | $ | 1,164 | ||||||||||
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Fixed charges
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$ | 696 | $ | 731 | $ | 710 | $ | 699 | $ | 840 | ||||||||||
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Ratio of earnings to fixed charges
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4.09 | 2.94 | 1.84 | 2.19 | 1.39 | |||||||||||||||
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(a) | Does not include interest related to income taxes, including interest related to FIN 48 liabilities, which is included in provision for income taxes on our Consolidated Statement of Income. See Note 5 of Notes to Consolidated Financial Statements. |
ENTITY | JURISDICTION | |
ACCROVEN SRL
|
Barbados | |
Alliance Canada Marketing L.P.
|
Alberta | |
Alliance Canada Marketing LTD
|
Alberta | |
Apco Argentina, Inc.
|
Cayman Islands | |
Apco Argentina, S.A.
|
Argentina | |
Apco Properties Ltd.
|
Cayman Islands | |
Arctic Fox Assets, Inc.
|
Delaware | |
Aspen Products Pipeline LLC
|
Delaware | |
Aux Sable Liquid Products Inc.
|
Delaware | |
Aux Sable Liquid Products LP
|
Alberta | |
Bargath Inc.
|
Colorado | |
Barrett Fuels Corporation
|
Delaware | |
Barrett Resources International Corporation
|
Delaware | |
Baton Rouge Fractionators LLC
|
Delaware | |
Baton Rouge Pipeline LLC
|
Delaware | |
Beech Grove Processing Company
|
Tennessee | |
Bison Royalty LLC
|
Delaware | |
Black Marlin Pipeline Company
|
Texas | |
Carbon County UCG, Inc.
|
Delaware | |
Carbonate Trend Pipeline LLC
|
Delaware | |
Cardinal Operating Company, LLC
|
Delaware | |
Cardinal Pipeline Company, LLC
|
North Carolina | |
Castle Associates, L.P.
|
Delaware | |
ChoiceSeat, L.L.C.
|
Delaware | |
Diamond Elk, LLC
|
Colorado | |
Discovery Gas Transmission LLC
|
Delaware | |
Discovery Producer Services LLC
|
Delaware | |
Distributed Power Solutions L.L.C.
|
Delaware | |
Eagle Gas Services, Inc.
|
Ohio | |
ESPAGAS USA, Inc.
|
Delaware | |
F T & T, Inc.
|
Delaware | |
Fishhawk Ranch, Inc.
|
Florida | |
FleetOne Inc.
|
Delaware | |
Fort Union Gas Gathering, L.L.C.
|
Delaware | |
Garrison, L.L.C.
|
Delaware | |
Goebel Gathering Company, L.L.C.
|
Delaware | |
Gulf Liquids Holdings LLC
|
Delaware | |
Gulf Liquids New River Project LLC
|
Delaware | |
Gulf Star Deepwater Services, LLC
|
Delaware | |
Gulfstream Management & Operating Services, L.L.C.
|
Delaware | |
Gulfstream Natural Gas System, L.L.C.
|
Delaware |
ENTITY
JURISDICTION
Delaware
Tennessee
Delaware
Delaware
Delaware
Alaska
Delaware
Delaware
Delaware
Delaware
Delaware
Utah
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oklahoma
North Carolina
Delaware
Colorado
Delaware
Delaware
Venezuela
Oklahoma
Delaware
Delaware
Delaware
Dutch BV
Delaware
Texas
South Africa
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
ENTITY
JURISDICTION
Tennessee
Delaware
Austria
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Brunswick
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
Delaware
Alaska
New Brunswick
Delaware
Texas
Delaware
Delaware
Delaware
New Brunswick
United Kingdom
New Brunswick
England
United Kingdom
Delaware
Delaware
Delaware
Delaware
Delaware
Alaska
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
ENTITY
JURISDICTION
Delaware
Delaware
Delaware
Cayman Islands
Delaware
Austria
Delaware
Delaware
Delaware
Austria
Delaware
Delaware
Bermuda
Delaware
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Cayman Islands
Nevada
Delaware
Cayman Islands
Cayman Islands
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Alberta
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
ENTITY
JURISDICTION
Spain
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oklahoma
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Cayman Islands
Cayman Islands
/s/ Ernst & Young LLP |
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||||
By: | /s/ C. H. (Scott) Rees III, P.E. | |||
C.H. (Scott) Rees III, P.E. | ||||
Chairman and Chief Executive Officer |
MILLER AND LENTS, LTD.
|
||||
By: | /s/ Stephen M. Hamburg | |||
Stephen M. Hamburg | ||||
Vice President | ||||
/s/ Steven J. Malcolm | /s/ Donald R. Chappel | |
Steven J. Malcolm
Chairman of the Board President and Chief Executive Officer (Principal Executive Officer) |
Donald R. Chappel
Senior Vice President and Chief Financial Officer (Principal Financial Officer) (Principal Accounting Officer) |
/s/ Joseph R. Cleveland | /s/ Kathleen B. Cooper | |
Joseph R. Cleveland | Kathleen B. Cooper | |
Director | Director | |
/s/Irl F. Engelhardt | /s/ William R. Granberry | |
Irl F. Engelhardt | William R. Granberry | |
Director | Director | |
/s/ William E. Green | /s/ Juanita H. Hinshaw | |
William E. Green | Juanita H. Hinshaw | |
Director | Director | |
/s/ W. R. Howell | /s/ Charles M. Lillis | |
W. R. Howell | Charles M. Lillis | |
Director | Director | |
/s/ George A. Lorch | /s/ William G. Lowrie | |
George A. Lorch | William G. Lowrie | |
Director | Director | |
/s/ Frank T. MacInnis | /s/ Janice D. Stoney | |
Frank T. MacInnnis
Director |
Janice D. Stoney
Director |
THE WILLIAMS COMPANIES, INC.
|
|||||
By: | /s/ James J. Bender | ||||
James J. Bender | |||||
ATTEST: | Senior Vice President | ||||
/s/ La Fleur C. Browne
|
|||||
La Fleur C. Browne | |||||
Secretary | |||||
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; | ||
(c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
(d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
/s/ Steven J. Malcolm | ||||
Steven J. Malcolm | ||||
President and Chief Executive Officer
(Principal Executive Officer) |
||||
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; | ||
(c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
(d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
/s/ Donald R. Chappel | ||||
Donald R. Chappel | ||||
Senior Vice President
and Chief Financial Officer (Principal Financial Officer) |
||||