UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DCD.C. 20549
Form 10-K
| | | |
| (Mark One) | | |
þ | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | | For the fiscal year ended December 31, 20062008 |
or |
o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | | For the transition period from to |
Commission file number 1-4174
The Williams Companies, Inc.
(Exact name of Registrant as Specified in Its Charter)
| | | |
Delaware
| | 73-0569878 |
| (State or Other Jurisdiction of | | (IRS Employer |
Incorporation or Organization) | | 73-0569878
(IRS Employer
Identification No.) |
| | | |
One Williams Center, Tulsa, Oklahoma
| | 74172 |
| (Address of Principal Executive Offices) | | 74172
(Zip Code) |
918-573-2000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
| | | |
| | | Name of Each Exchange
|
Title of Each Class | | on Which Registered |
| |
| Common Stock, $1.00 par value | | New York Stock Exchange and
NYSE Arca Equities Exchange |
| | |
| | |
| | |
| Preferred Stock Purchase Rights | | New York Stock Exchange and
NYSE Arca Equities Exchange |
Securities registered pursuant to Section 12(g) of the Act:
5.50% Junior Subordinated Convertible Debentures due 2033
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ Noo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ Noo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K. oþ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer.smaller reporting company. See definitionthe definitions of “large accelerated filer,” “accelerated filerfiler” and large accelerated filer”“smaller reporting company” inRule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o | | | | | | |
Large accelerated filerþ | | Accelerated filero | | Non-accelerated filer o
(Do not check if a smaller reporting company) | | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act). Yes o No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second quarter was approximately $13,912,313,182.$23,344,993,927.
The number of shares outstanding of the registrant’s common stock outstanding at February 22, 200719, 2009 was 597,861,925.579,213,365.
DOCUMENTS INCORPORATED BY REFERENCE
| | |
Document
| | Parts Into Which Incorporated
|
|
Proxy Statement for the Annual Meeting of Stockholders to be held May 17, 2007 (Proxy Statement) | | Part III |
Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s 2009 Annual Meeting of Stockholders to be held on May 21, 2009, are incorporated into Part III, as specifically set forth in Part III.
THE WILLIAMS COMPANIES, INC.
FORM 10-K
TABLE OF CONTENTS
i
DEFINITIONS
We use the following oil and gas measurements in this report:
Bcfe — means one billion cubic feet of gas equivalent determined using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.
Bcf/d — means one billion cubic feet per day.
British Thermal Unit or BTU — means a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit.
BBtud — means one billion BTUs per day.
Dekatherms or Dth or Dt — means a unit of energy equal to one million BTUs.
Mbbls/d — means one thousand barrels per day.
Mcfe — means one thousand cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.
Mdt/d — means one thousand dekatherms per day.
MMcf — means one million cubic feet.
MMcf/d — means one million cubic feet per day.
MMcfe — means one million cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.
MMdt — means one million dekatherms or approximately one trillion BTUs.
MMdt/d — means one million dekatherms per dayday.
.TBtu — means one trillion BTUs.
ii
PART I
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise requires, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to Williams as the “Company.”
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, proxy statements and other documents electronically with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (Exchange Act). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth100 F Street, N.W.N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website athttp://www.sec.gov.
Our Internet website ishttp://www.williams.com.We make available free of charge on or through our Internet website our annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics, Board committee chartersCommittee Charters and Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, at Williams, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
GENERAL
We are a natural gas company originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. We were founded in 1908 when two Williams brothers began a construction company in Fort Smith, Arkansas. Today, we primarily find, produce, gather, process and transport natural gas. Our operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, the Eastern Seaboard, and the province of Alberta in Canada.
We continue to useOur principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is918-573-2000.
In 2008, we used Economic Value Added® (EVA®)1 as the basis for disciplined decision making around the use of capital. EVA® is a tool that considers both financial earnings and a cost of capital in measuring performance. It is based on the idea that earning profits from an economic perspective requires that a company cover not only all of its operating expenses but also all of its capital costs. The two main components of EVA® are net operating profit after taxes and a charge for the opportunity cost of capital. We derive these amounts by making various adjustments to our reported results and financial position, and by applying a cost of capital. We look for opportunities to improve EVA® because we believe there is a strong correlation between EVA® improvement and creation of shareholder value.
Today, we primarily find, produce, gather, process and transport natural gas. We also manage a wholesale power business. Our operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern Seaboard.
In 2006 we focused on continued disciplined growth. During 2006 we:
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| • | Continued to improve both EVA® and segment profit; |
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| • | Invested in our natural gas businesses in a way that improves EVA®, meets customer needs, and enhances our competitive position; |
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| • | Continued to increase natural gas production in a responsible manner; |
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| • | Accelerated additional asset transactions between us and Williams Partners L.P., our master limited partnership; |
1 Economic Value Added® (EVA®) is a registered trademark of Stern, Stewart & Co.
1
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| • | Increased the scale of our gathering and processing business in key growth basins; |
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| • | Filed new rates to enable our Gas Pipeline segment to remain competitive and value-creating, and completed a capacity replacement project; |
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| • | Executed power contracts that reduce risk while adding new business and strengthening future cash flow potential. |
Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is918-573-2000.
2006 HIGHLIGHTS
In November 2005, we initiated an offer to convert our 5.5 percent junior subordinated convertible debentures into our common stock. In January 2006, we converted approximately $220.2 million of the debentures in exchange for 20.2 million shares of common stock, a $25.8 million cash premium, and $1.5 million of accrued interest.
In April 2006, Transcontinental Gas Pipe Line Corporation (Transco) issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Transco completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.
In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.
In May 2006, we replaced our $1.275 billion secured revolving credit facility with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and financial covenants as the secured facility, but contains certain additional restrictions. (See Note 11 of Notes to Consolidated Financial Statements.)
In May 2006, our Board of Directors approved a regular quarterly dividend of 9 cents per share of common stock, which reflects an increase of 20 percent compared with the 7.5 cents per share paid in each of the three prior quarters.
In June 2006, Northwest Pipeline Corporation (Northwest Pipeline) issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Northwest Pipeline Corporation completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.
In June 2006, we reached anagreement-in-principle to settleclass-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000, and July 22, 2002, for a total payment of $290 million to plaintiffs. We funded our $145 million portion of the settlement withcash-on-hand in November 2006, with the balance funded through insurance proceeds. We recorded a pre-tax charge for approximately $161 million in second-quarter 2006. This settlement did not have a material effect on our liquidity position. (See Note 15 of Notes to Consolidated Financial Statements.)
In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. successfully closed a $150 million private debt offering of senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.
2
On July 31, 2006, and August 1, 2006, we received a verdict in civil litigation related to a contractual dispute surrounding certain natural gas processing facilities known as Gulf Liquids. We recorded a pre-tax charge for approximately $88 million in second quarter 2006 related to this loss contingency. (See Note 15 of Notes to Consolidated Financial Statements.)
Northwest Pipeline and Transco have each filed a general rate case with the Federal Energy Regulatory Commission (FERC). Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007. The new transportation and storage rates for both pipelines will be effective, subject to refund, in the first quarter of 2007.
In December 2006, Northwest Pipeline completed and placed into service its capacity replacement project in the state of Washington. The project involved abandoning 268 miles of26-inch pipeline and replacing it with approximately 80 miles of36-inch pipeline constructed in four sections along the same pipeline corridor. Additionally, Northwest Pipeline modified five existing compressor stations which created additional net horsepower.
Our property insurance coverage levels and premiums were revised during the second quarter of 2006. In general, our coverage levels have decreased while our premiums have increased. These changes reflect general trends in our industry due to hurricane-related damages in recent years.
FINANCIAL INFORMATION ABOUT SEGMENTS
See “Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 1718” of our Notes to Consolidated Financial Statements for information with respect to each segment’s revenues, profits or losses and total assets. See Note 9 for information with respect to property, plant and equipment for each segment.
1 Economic Value Added® (EVA®) is a registered trademark of Stern, Stewart & Co.
1
BUSINESS SEGMENTS
Substantially all our operations are conducted through our subsidiaries. To achieve organizational and operating efficiencies, our activities are primarily operated through the following business segments:
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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.Company (RMT). |
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| | • | Gas Pipeline — includes our interstate natural gas pipelines and pipeline joint venture investments organized under our wholly owned subsidiary, Williams Gas Pipeline Company, LLC.LLC (WGP). Gas Pipeline also includes Williams Pipeline Partners L.P. (WMZ), our master limited partnership formed in 2007. |
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| | • | 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. |
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| | • | PowerGas Marketing Services — manages our wholesale power and natural gas commodity businessesrisk through purchases, sales and other related transactions, under our wholly owned subsidiary Williams Power Company,Gas Marketing, Inc. and its subsidiaries. |
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| | • | Other — primarily consists of corporate operations. Other also includes our interest in Longhorn Partners Pipeline, L.P. (Longhorn). |
This report is organized to reflect this structure.
Detailed discussion of each of our business segments follows.
3
Exploration & Production
Our Exploration & Production segment which is comprised of several wholly owned and partially owned subsidiaries, including Williams Production Company LLC and Williams Production RMT Company (RMT), produces, develops, and manages natural gas reserves primarily located in the Rocky Mountain (primarily New Mexico, Wyoming and Colorado) and Mid-Continent (Oklahoma and Texas) regions of the United States. We specialize in natural gas production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Arkoma, Green River and Fort Worth basins. Over 99 percent of Exploration & Production’s domestic reserves are natural gas. Our Exploration & Production segment also has international oil and gas interests, which include a 69 percent equity interest in Apco Argentina Inc. (Apco Argentina), an oil and gas exploration and production company with operations in Argentina, and a four4 percent equity interest in Petrowayu S.A., a Venezuelan corporation that is the operator of a 100 percent interest in the La Concepcion block located in Westernwestern Venezuela.
Exploration & Production’s primary strategy is to utilize its expertise in the development of tight-sands, shale, and coal bed methane reserves. Exploration & Production’s current proved undeveloped and probable reserves provide us with strong capital investment opportunities for several years into the future. Exploration & Production’s goal is to drill its existing proved undeveloped reserves, which comprise over 47is comprised of approximately 43 percent of proved reserves, and to drill in areas of probable reserves adding to our proved reserves. In addition, Exploration & Production provides a significant amount of equity production that is gatheredand/or processed by our Midstream facilities in the San Juan basin.
Information for our Exploration & Production segment relates only to domestic activity unless otherwise noted. We use the terms “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest.
2
Gas reserves and wells
The following table summarizes our U.S. natural gas reserves as of December 31 (using market prices aton December 31 held constant) for the year indicated:
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Bcfe) | |
| |
| Proved developed natural gas reserves | | | 1,945 | | | | 1,643 | | | | 1,348 | |
| Proved undeveloped natural gas reserves | | | 1,756 | | | | 1,739 | | | | 1,638 | |
| | | | | | | | | | | | | |
| Total proved natural gas reserves | | | 3,701 | | | | 3,382 | | | | 2,986 | |
| | | | | | | | | | | | | |
The following table summarizes our proved natural gas reserves by basin as of December 31, 2006:
| | | | |
| | Percentage of
| |
Basin
| | Proved Reserves | |
|
Piceance | | | 67% | |
San Juan | | | 17% | |
Powder River | | | 10% | |
Other | | | 6% | |
| | | | |
| | | 100% | |
| | | | |
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (Bcfe) | |
| |
| Proved developed natural gas reserves | | | 2,456 | | | | 2,252 | | | | 1,945 | |
| Proved undeveloped natural gas reserves | | | 1,883 | | | | 1,891 | | | | 1,756 | |
| | | | | | | | | | | | | |
| Total proved natural gas reserves | | | 4,339 | | | | 4,143 | | | | 3,701 | |
| | | | | | | | | | | | | |
No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2006.2008. We have not filed on a recurring basis estimates of our total proved net oil and gas reserves with any U.S. regulatory authority or agency other than the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC, although Exploration & Production has not yet filedbeen required to file any information with respect to its estimated total reserves at December 31, 2006,2008 with the DOE. Certain estimates filed with the DOE may not necessarily be directly comparable to those reported here due to special DOE reporting requirements, such as the requirement to report gross operated reserves only. TheIn 2007 and 2006, the underlying estimated reserves for the DOE did not differ by more than five5 percent from the underlying estimated reserves utilized in preparing the estimated reserves reported to the SEC.
4
Approximately 9899 percent of our year-end 20062008 United States proved reserves estimates were audited in each separate basin by Netherland, Sewell & Associates, Inc. (NSAI). When compared on awell-by-well basis, some of our estimates are greater and some are less than the estimates of NSAI. However, in the opinion of NSAI, the estimates of our proved reserves are in the aggregate reasonable by basin and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. NSAI is satisfied with our methods and procedures in preparing the December 31, 20062008 reserve estimates and saw nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, as prepared by us. ReservesReserve estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust, which comprise another approximately two1 percent of our total U.S. proved reserves, were prepared by Miller and Lents, LTD.
The SEC has revised its oil and gas reporting requirements effective for fiscal years ending on or after December 31, 2009, with early adoption prohibited. These changes include:
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| • | Expanding the definition of oil and gas reserves and providing clarification of certain concepts and technologies used in the reserve estimation process. |
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| • | Allowing optional disclosure of probable and possible reserves and permitting optional disclosure of price sensitivity analysis. |
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| • | Modifying prices used to estimate reserves for SEC disclosure purposes to a12-month average price instead of asingle-day,period-end price. |
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| • | 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
Oil and gas properties and reserves by basin
Following is a discussionThe table below summarizes 2008 activity and reserves for each of our oil and gas properties for our significant areas.areas, with further discussion following the table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Wells
| | | Wells
| | | Wells
| | | Wells
| | | Wellhead
| | | Proved
| | | % of Total
| |
| | | Drilled
| | | Drilled
| | | Producing
| | | Producing
| | | Production
| | | Reserves
| | | Proved
| |
| | | (Gross) | | | (Operated) | | | (Gross) | | | (Net) | | | (Net Bcfe) | | | (Bcfe) | | | Reserves | |
| |
| Piceance | | | 687 | | | | 646 | | | | 3,163 | | | | 2,894 | | | | 238 | | | | 3,095 | | | | 71 | % |
| San Juan | | | 95 | | | | 37 | | | | 3,129 | | | | 852 | | | | 55 | | | | 523 | | | | 12 | % |
| Powder River | | | 703 | | | | 366 | | | | 5,407 | | | | 2,465 | | | | 84 | | | | 390 | | | | 9 | % |
| Mid-Continent | | | 82 | | | | 76 | | | | 672 | | | | 434 | | | | 25 | | | | 224 | | | | 5 | % |
| Other | | | 220 | | | | 0 | | | | 611 | | | | 21 | | | | 4 | | | | 107 | | | | 3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 1,787 | | | | 1,125 | | | | 12,982 | | | | 6,666 | | | | 406 | | | | 4,339 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Piceance basin
The Piceance basin is located in northwestern Colorado. In 2006, we drilled 494 gross wells of which we operate 477,Colorado and owned working interests in a total of 1,889 gross producing wells at year-end. We produced a net of approximately 152 Bcfe of natural gas from the Piceance basin during 2006. Our estimated proved reserves in this basin at year-end 2006 were 2,469 Bcfe. The Piceance basin is our largest area of concentrated development comprising approximately 67 percentdevelopment. During 2008 we operated an average of our proved reserves at26 drilling rigs in the basin. As of December 31, 2006.2008, 15 of these rigs were the new high efficiency rigs designed to drill up to 22 wells from one location. This area has approximately 1,5001,770 undrilled proved locations in inventory. Within this basin we are also the ownerown and operator of aoperate natural gas gathering facilities including some 300 miles of gathering lines and associated field compression. Approximately 85 percent of the gas gathered is our own equity production. The gathering system also includes 7 processing system. In March 2005 we entered into a contractplants and associated treating facilities with Helmerich & Payne for the operation of 10 new FlexRig® drilling rigs, each for a term of three years. By December 2006, all 10 of these rigs were operatingan eighth plant that came on-line in the Piceance basin. We also have 15 rigs operating in the Piceance basin under contract with other vendors,February 2009, for a total capacity of 25 rigs operating in1.25 Bcfd. During 2008, these plants recovered approximately 69 million gallons of natural gas liquids (NGLs) which were marketed separately from the Piceance basin by December 2006.residue natural gas.
San Juan basin
The San Juan basin is located in northwest New Mexico and southwest Colorado. In 2006, we participated in the drilling of 214 gross wells, of which we operate 56 and owned working interests in a total of 2,864 gross producing wells at year-end. We produced a net of approximately 56 Bcfe of natural gas from the San Juan basin during 2006. Our estimated proved reserves in the San Juan basin at year-end 2006 were 614 Bcfe.
Powder River basin
The Powder River basin is located in northeast Wyoming. In 2006, we drilled 858 gross wells of which we operate 449, and owned working interests in a total of 4,454 gross producing wells at year-end. We produced a net of approximately 52 Bcfe of natural gas from the Powder River basin during 2006. Our estimated proved reserves in this basin at year-end 2006 were 372 Bcfe. The Powder River basin comprises approximately 10 percent of our proved reserves at December 31, 2006. The Powder River basin includes large areas with multiple coal seam potential, targeting thick coal bed methane formations at shallow depths. We have a significant inventory of undrilled locations, providing long-term drilling opportunities.
Mid-Continent properties
The Mid-Continent properties are located in the southeastern Oklahoma portion of the Arkoma basin and the Barnett Shale in the Fort Worth basin of Texas. In 2006, we drilled 112 gross wells,
Other properties
Other properties are primarily comprised of which we operate 61 and owned working interests in a total of 475 gross producing wells at year-end. We produced a net of approximately 11 Bcfe of natural gas from the Mid-ContinentGreen River basin in 2006. Our estimated proved reserves in the Arkomasouthwestern Wyoming. Also included is exploration activity and Fort Worth basins at year-end 2006 were 167 Bcfe.other miscellaneous activity.
5
The following table summarizes our leased acreage as of December 31, 2006:2008:
| | | | | | | | | | | | | | | | | |
| | | Gross Acres | | Net Acres | | | Gross Acres | | Net Acres | |
| |
| Developed | | | 803,772 | | | | 423,025 | | | | 981,853 | | | | 512,896 | |
| Undeveloped | | | 1,220,422 | | | | 623,538 | | | | 1,269,350 | | | | 661,568 | |
4
At December 31, 2006, we owned working interests in 9,965 gross wells producing hydrocarbons (4,890 net).
Operating statistics
We focus on lower-risk development drilling. Our development drilling success rate was approximately 99 percent in 2006, 2005each of 2008, 2007 and 2004.2006. The following tables summarizetable summarizes domestic drilling activity by number and type of well for the periods indicated:
| | | | | | | | | | | | | | | | | |
Number of Wells | | Gross Wells | | Net Wells | | | Gross Wells | | Net Wells | |
| |
| Development: | | | | | | | | | | | | | | | | |
| Drilled | | | | | | | | | | | | | | | | |
| 2008 | | | | 1,783 | | | | 1,050 | |
| 2007 | | | | 1,590 | | | | 904 | |
| 2006 | | | 1,783 | | | | 954 | | | | 1,783 | | | | 954 | |
| 2005 | | | 1,627 | | | | 867 | | |
| 2004 | | | 1,395 | | | | 710 | | |
| Successful | | | | | | | | | | | | | | | | |
| 2008 | | | | 1,782 | | | | 1,050 | |
| 2007 | | | | 1,581 | | | | 899 | |
| 2006 | | | 1,770 | | | | 948 | | | | 1,770 | | | | 948 | |
| 2005 | | | 1,615 | | | | 859 | | |
| 2004 | | | 1,384 | | | | 706 | | |
Substantially all our natural gas production is currently being soldWe also successfully drilled four exploratory wells in 2008. In addition, two exploratory wells drilled in prior years were determined to Power at prevailing market prices. Power then resells the majority of our production to unrelated third parties. be unsuccessful in 2008.
Because we currently have a low-risk drilling program in proven basins, the main component of risk that we manage is price risk. We have recentlyExploration & Production natural gas hedges for 2009 domestic natural gas production consist of NYMEX fixed price contracts of106 MMcf/d (whole year) and approximately490 MMcf/d in regional collars (whole year). Our natural gas production hedges in 2008 consisted of70 MMcf/d in NYMEX fixed price hedges and434 MMcf/d in regional collars. A collar is an option contract that sets a gas price floor and ceiling for a certain volume of natural gas. Hedging decisions are made considering the overall Williams commodity risk exposure and are not executed independently by Exploration & Production; there are expected future gas purchases for other Williams entities that when taken as a net position may offset price risk related to Exploration & Production’s expected future gas sales. In February 2007, we entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Margin requirements, if any, under this new facility are dependent on the level of hedging with the banks and on natural gas reserves value. Exploration & Production natural gas hedges for 2007 consist of derivative contracts with Power that hedge 172 BBtud in fixed price hedges (whole year) and approximately 270 BBtud in NYMEX and regional collars (whole year) for projected 2007 domestic natural gas production. Power then enters into offsetting derivative contracts with unrelated third parties. Our natural gas production hedges in 2006 consisted of 299 BBtud in fixed price hedges and 64 BBtud in NYMEX collars and an additional 50 BBtud in regional collars. A collar is a financial instrument that sets a gas price floor and ceiling for a certain volume of natural gas. Hedging decisions are made consideringIn June 2008, we amended this agreement to extend the overall Williams commodity risk exposure and are not executed independently by Exploration & Production; there are gas purchase hedging contracts executed on behalf of other Williams entities which taken as a net position may counteract Exploration & Production gas sales hedging derivatives.facility through year end 2013.
The following table summarizes our domestic sales and cost information for the years indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
| Total net production sold (in Bcfe) | | | 274.4 | | | | 223.5 | | | | 189.4 | | | | 400.4 | | | | 333.1 | | | | 274.4 | |
| Average production costs including production taxes per thousand cubic feet of gas equivalent (Mcfe) produced | | $ | 1.02 | | | $ | .92 | | | $ | .88 | | |
| Average production costs including production taxes per (Mcfe) produced | | | $ | 1.26 | | | $ | 0.98 | | | $ | 1.02 | |
| Average sales price per Mcfe | | $ | 5.24 | | | $ | 6.41 | | | $ | 4.48 | | | $ | 6.39 | | | $ | 4.92 | | | $ | 5.24 | |
| Realized impact of hedging contracts (Loss) | | $ | (0.73 | ) | | $ | (1.61 | ) | | $ | (1.32 | ) | |
| Realized gain (loss) on hedging contracts | | | $ | 0.09 | | | $ | 0.16 | | | $ | (0.73 | ) |
Acquisitions & divestitures
In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for $148 million. As a result of the contract termination, we have no further interests associated with the crude oil concession, which is located in Peru. We obtained these interests through our acquisition of Barrett Resources Corporation in 2001.
In May 2008, we acquired certain undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin for $285 million. In July 2008, a third party exercised its contractual option to purchase, on the same terms and conditions, an interest in a portion of the acquired assets for $71 million. We received this $71 million in October 2008.
In September 2008, we increased our position in the Fort Worth basin by acquiring certain undeveloped leasehold acreage and producing properties for $147 million subject to post-closing adjustments. This acquisition is
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consistent with our growth strategy of leveraging our horizontal drilling expertise by acquiring and developing low-risk properties in the Barnett Shale formation.
Through other transactions totaling approximately $111 million, Exploration & Production expanded its acreage position and purchased producing properties in the Fort Worth basin in north-central Texas through transactions totaling approximately $64 million.and also expanded its acreage position in the Highlands area of the Piceance basin and in the Paradox basin.
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Other information
In 1993, Exploration & Production conveyed a net profits interest in certain of its properties to the Williams Coal Seam Gas Royalty Trust. Substantially all of the production attributable to the properties conveyed to the trust was from the Fruitland coal formation and constituted coal seam gas. We subsequently sold trust units to the public in an underwritten public offering and retained 3,568,791 trust units then representing 36.8 percent of outstanding trust units. We have previously sold trust units on the open market, with our last sales in June 2005. As of February 1, 2007,2009, we own 789,291 trust units. We sold no additional trust units during 2006.
International exploration and production interests
We also have investments in international oil and gas interests. If combined with our domestic proved reserves, our international interests would make up 4.2approximately 3 percent of our total proved reserves.
Gas Pipeline
We own and operate, through Williams Gas Pipeline Company, LLC and its subsidiaries, a combined total of approximately 14,40014,000 miles of pipelines with a total annual throughput of approximately 2,5002,700 trillion British Thermal Units of natural gas andpeak-day delivery capacity of approximately 12 MMdt of gas. Gas Pipeline consists of Transcontinental Gas Pipe Line CorporationCompany, LLC (Transco) and Northwest Pipeline Corporation.GP (Northwest Pipeline). Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream Natural Gas System, L.L.C. Gas Pipeline also includes WMZ.
Transcontinental Gas Pipe Line Corporation (Transco)Transco
Transco is an interstate natural gas transportation company that owns and operates a10,500-mile 10,100-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania, and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 11 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., New York, New Jersey, and Pennsylvania.
Pipeline system and customers
At December 31, 2006,2008, Transco’s system had a mainline delivery capacity of approximately 4.7 MMdt of natural gas per day from its production areas to its primary markets. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 3.53.8 MMdt of natural gas per day for a system-wide delivery capacity total of approximately 8.28.5 MMdt of natural gas per day. Transco’s system includes 4445 compressor stations, fivefour underground storage fields, twoand a liquefied natural gas (LNG) storage facilities.facility. Compression facilities at a sea level-rated capacity total approximately 1.5 million horsepower.
Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. One customer accounted for approximately 11 percent and another customer accounted for approximately 10 percent of Transco’s total revenues in 2006.2008. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers storage services and interruptible transportation services under short-term agreements.
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Transco has natural gas storage capacity in fivefour underground storage fields located on or near its pipeline system or market areas and operates threetwo of these storage fields. Transco also has storage capacity in an LNG storage facility and operates the facility. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 216204 billion cubic feet of gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, LLC, an LNGOctober 2008, the FERC approved Transco’s request to abandon its Hester storage facility, with 4 billion cubic feet of storage capacity.which is not in operation. Hester is not included in the capacity described above. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
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Transco expansion projects
Leidy to Long Island Expansion Project
The Leidy to Long Island Expansion Project will involve an expansion of Transco’s existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The project will provide 100 Mdt/d of incremental firm transportation capacity,pipeline projects listed below are future pipeline projects for which has been fully subscribed by one shipper for a 20-year primary term. The project facilities will include pipeline looping in Pennsylvania, pipeline looping, replacement and a natural gas compressor facility in New Jersey and appurtenant facilities in New York. Transco expects that over three-quarters of the project expenditures will occur in 2007. Transco filed an application for FERC authorization of the project in December 2005, which the FERC approved by order issued on May 18, 2006. On October 20, 2006, Transco filed an application to amend the FERC authorizations to reflect Transco’s ownership of certain appurtenant facilities as part of the project and to adjust the cost of facilities and rates, which the FERC approved on January 11, 2007. The estimated capital cost of the project is approximately $141 million. The target in-service date for the project is November 1, 2007.we have customer commitments.
Potomac Expansion Project
The Potomac Expansion Project will involve an expansion of Transco’s existing natural gas transmission system from receipt points in North Carolina to delivery points in the greater Baltimore and Washington, D.C. metropolitan areas. The project will provide 165 Mdt/d of incremental firm transportation capacity, which has been fully subscribed by shippers under long-term firm arrangements. The estimated capital cost of the project is approximately $74 million. On July 17, 2006, Transco filed an application for FERC approval of the project. The target in-service date for the project is November 1, 2007.
Sentinel Expansion Project
The Sentinel Expansion Project will involveinvolves an expansion of Transco’sour existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley Interconnectioninterconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The project will provide 142 Mdt/d of incremental firm transportation capacity, which has been fully subscribed by the shippers under long-term firm arrangements. The project facilities will include pipeline looping in Pennsylvania and New Jersey and minor compressor station modifications. The estimated capital cost of the project excluding any customer meter station upgrades is estimated to be up to approximately $140$200 million. In orderPhase I was placed into service in December 2008. Phase II is expected to accommodate certain shippers,be placed into service by November 2009.
Mobile Bay South Expansion Project
The Mobile Bay South Expansion Project involves the addition of compression at Transco’s Station 85 in Choctaw County, Alabama to allow Transco to provide firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. The capital cost of the project is planningestimated to be up to approximately $37 million. Transco plans to place the incremental firm transportation capacityproject into service by May 2010.
85 North Expansion Project
The 85 North Expansion Project involves an expansion of our existing natural gas transmission system from Station 85 in Choctaw County, Alabama to various delivery points as far north as North Carolina. The capital cost of the project is estimated to be $248 million. Transco plans to place the project into service in two phases, the first phase commencing on November 1, 2008 for 67 Mdt/d of servicein July 2010 and the second phase commencing on November 1, 2009 for an additional 75 Mdt/d of service. The FERC has granted our request for a pre-application environmental review of the project, soliciting early input from citizens, governmental entities and other interested parties. Transco expects to file a formal application with the FERC in the second quarter of 2007.May 2011.
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Operating statistics
The following table summarizes transportation data for the Transco system for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (In trillion British
| | | (In trillion British
| |
| | | Thermal Units) | | | Thermal Units) | |
| |
| Market-area deliveries: | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-haul transportation | | | 795 | | | | 755 | | | | 782 | | | | 753 | | | | 839 | | | | 795 | |
| Market-area transportation | | | 817 | | | | 853 | | | | 817 | | | | 969 | | | | 875 | | | | 817 | |
| | | | | | | | | | | | | | | |
| Total market-area deliveries | | | 1,612 | | | | 1,608 | | | | 1,599 | | | | 1,722 | | | | 1,714 | | | | 1,612 | |
| Production-area transportation | | | 247 | | | | 278 | | | | 317 | | | | 188 | | | | 190 | | | | 247 | |
| | | | | | | | | | | | | | | |
| Total system deliveries | | | 1,859 | | | | 1,886 | | | | 1,916 | | | | 1,910 | | | | 1,904 | | | | 1,859 | |
| | | | | | | | | | | | | | | |
| Average Daily Transportation Volumes | | | 5.1 | | | | 5.2 | | | | 5.2 | | | | 5.2 | | | | 5.2 | | | | 5.1 | |
| Average Daily Firm Reserved Capacity | | | 6.6 | | | | 6.6 | | | | 6.6 | | | | 6.8 | | | | 6.6 | | | | 6.6 | |
Transco’s facilities are divided into eight rate zones. Five are located in the production area, and three are located in the market area. Long-haul transportation involves gas that Transco receives in one of the production-area zones and delivers to a market-area zone. Market-area transportation involves gas that Transco both receives and
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delivers within the market-area zones. Production-area transportation involves gas that Transco both receives and delivers within the production-area zones.
Northwest Pipeline Corporation (Northwest Pipeline)
Northwest Pipeline is an interstate natural gas transportation company that owns and operates a natural gas pipeline system extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in California, Arizona, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington directly or indirectly through interconnections with other pipelines.
Pipeline system and customers
At December 31, 2006,2008, Northwest Pipeline’s system, having long-term firm transportation agreements withincluding peaking capacityservice of approximately 3.4 MMdt3.6 Bcf of natural gas per day, was composed of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 473,000 horsepower.
In 2003, we experienced two breaks in a segment of one of our natural gas pipelines in western Washington. In response to these breaks, we received Corrective Action Orders from the Office of Pipeline Safety, elected to idle the pipeline segment until its integrity could be assured, and began the process of replacing the capacity served by the pipeline segment.
In September 2005 we received a FERC certificate authorizing us to construct and operate the “Capacity Replacement Project.” This project entailed the abandonment of approximately 268 miles of the existing26-inch pipeline, and the construction of approximately 80 miles of new36-inch pipeline and an additional 10,760 net horsepower of compression at two existing compressor stations. As of December 2006, all of the facilities were placed in service, and abandonment of the26-inch pipeline was completed.
The rate case we filed on June 30, 2006 seeks to recover, among other things, the capitalized costs relating to the Capacity Replacement Project.
In 2006,2008, Northwest Pipeline served a total of 141136 transportation and storage customers. TransportationWe transport and store natural gas for a broad mix of customers, includeincluding local natural gas distribution companies, municipalities, interstatemunicipal utilities, direct industrial users, electric power generators and intrastate pipelines,natural gas marketers and direct industrial users.producers. The two largest customerscustomer of Northwest Pipeline in 20062008 accounted for approximately 19.9 percent and 10.920.7 percent of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2006.2008. Northwest Pipeline’s firm transportation agreementsand storage contracts are
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generally long-term agreementscontracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.
As a part of its transportation services, Northwest Pipeline utilizes underground storage facilities in Utah and Washington enabling it to balance daily receipts and deliveries. Northwest Pipeline also owns and operates an LNG storage facility in Washington that provides service for customers during a few days of extreme demands. These storage facilities have an aggregate firm delivery capacity of approximately 600 million cubic feet700 MMcf of gas per day.
Northwest Pipeline expansion projects
The pipeline projects listed below were completed during 2008 or are future pipeline projects for which we have customer commitments.
Parachute LateralColorado Hub Connection Project
Northwest Pipeline has proposed installing a new27-mile,24-inch diameter lateral to connect the Meeker/White River Hub near Meeker, Colorado to its mainline near Sand Springs, Colorado. This project is referred to as the Colorado Hub Connection (CHC Project). It is estimated that the construction of the CHC Project will cost up to $60 million with service targeted to commence in November 2009. Northwest Pipeline will combine the lateral capacity with 341 MDth per day of existing mainline capacity from various receipt points for delivery to Ignacio, Colorado, including approximately 98 MDth per day of capacity that was sold on a short-term basis. Approximately 243 MDth per day of this capacity is held by Pan-Alberta Gas under a contract that terminates on October 31, 2012.
In January 2006, weaddition to providing greater opportunity for contract extensions for the short-term firm and Pan-Alberta capacity, the CHC Project provides direct access to additional natural gas supplies at the Meeker/White River Hub for Northwest Pipeline’s on-system and off-system markets. Northwest Pipeline has entered into precedent agreements with terms ranging between eight and fifteen years at maximum rates for all of the short-term firm and Pan-Alberta capacity resulting in the successful re-contracting of the capacity out to 2018 and beyond. In September 2008, Northwest Pipeline filed an application for FERC certification and is awaiting necessary regulatory approvals. If Northwest Pipeline does not proceed with the FERCCHC Project, Northwest
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Pipeline will seek recovery of any shortfall in annual capacity reservation revenues from our remaining customers in a future rate proceeding. Northwest Pipeline does expect to construct a38-mile lateral that would provide additional transportationcollect maximum rates for the new CHC Project capacity fromcommitments and seek approval to recover the Parachute area toCHC Project costs in any future rate case filed with the Greasewood area in northwest Colorado. The planned lateral would increase capacity by 450 Mdt/d through a30-inch diameter line and is estimated to cost $86 million. We anticipate beginning service on the expansion in March 2007.FERC.
Greasewood Lateral ProjectSundance Trail Expansion
In March 2006, we executedFebruary 2008, Northwest Pipeline initiated an open season for the proposed Sundance Trail Expansion project that resulted in the execution of an agreement for 150 MDth per day of firm transportation service from the Meeker/White River Hub in Colorado for delivery to the Opal Hub in Wyoming. The project will include construction of approximately 16 miles of30-inch loop between Northwest Pipeline’s existing Green River and Muddy Creek compressor stations in Wyoming as well as an upgrade to Northwest Pipeline’s existing Vernal compressor station, with a shipper for 200 Mdt/dservice targeted to commence in November 2010. The total project is estimated to cost up to $65 million, including the cost of replacing existing compression at the Vernal compressor station which will enhance the efficiency of Northwest Pipeline’s system. The Sundance Trail Expansion will utilize available capacity on a proposed newthe CHC lateral and the existing Piceance lateral in conjunction with available and expanded mainline capacity. The Sundance Trail Expansion remains subject to be constructed fromcertain conditions, including receiving the vicinity of Greasewood, Colorado,necessary regulatory approvals. Northwest Pipeline expects to our mainlinecollect maximum system near Sands Springs, Colorado. On February 20, 2007, following a meeting with representatives ofrates, and will seek approval to roll-in the shipper, we decided to postpone applyingSundance Trail Expansion costs in any future rate case filed with the FERC for a certificate to construct the proposed Greasewood Lateral Project. We will be continuing to work with potential shippers to determine whether to proceed with the project at a future date.FERC.
Operating statistics
The following table summarizes volume and capacity data for the Northwest Pipeline system for the periods indicated:
| | | | | | | | | | | |
| | | | | | | | | | | | 2008 | | 2007 | | 2006 | |
| | | 2006 | | 2005 | | 2004 | | | (In trillion British
| |
| | | (In trillion British Thermal Units) | | | Thermal Units) | |
| |
| Total Transportation Volume | | | 676 | | | | 673 | | | | 650 | | | | 781 | | | | 757 | | | | 676 | |
| Average Daily Transportation Volumes | | | 1.9 | | | | 1.8 | | | | 1.8 | | | | 2.1 | | | | 2.1 | | | | 1.8 | |
| Average Daily Reserved Capacity Under Long-Term Base Firm Contracts, excluding peak capacity | | | 2.5 | | | | 2.5 | | | | 2.5 | | | | 2.5 | | | | 2.5 | | | | 2.5 | |
| Average Daily Reserved Capacity Under Short-Term Firm Contracts(1) | | | .9 | | | | .8 | | | | .6 | | | | .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, because it does not involve the construction of additional mainline capacity.basis. |
Gulfstream Natural Gas System, L.L.C. (Gulfstream)
Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. In December 2001, Gulfstream filed an application with the FERC to allow Gulfstream to complete the construction of its approved facilities in phases. In May 2002, the first phase of the project was placed into service at a cost of approximately $1.5 billion. The second phase of the project was placed into service on February 1, 2005. The total capital cost of both phases of the project is approximately $1.7 billion. At December 31, 2006, our equity investment in Gulfstream was $387 million. Gas Pipeline and Spectra Energy, (formerly known as Duke Energy), through their respective subsidiaries, each holdholds a 50 percent ownership interest in Gulfstream and provideprovides operating services for Gulfstream. At December 31, 2008, our equity investment in Gulfstream was $525 million.
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Gulfstream expansion projects
Gulfstream has entered into a precedent agreement and a related firm transportationplaced the Phase III expansion project in service agreement pursuant to which, subject to the receipt of all necessary regulatory approvals and other conditions precedent therein, we intend to extendon September 1, 2008. The project extended the pipeline system into South Florida and fully subscribesubscribed the remaining 345 Mdt/d of firm capacity on the existing pipeline system on a long-term basis. The estimated capital cost of this project is anticipated to be approximately $135 million.$118 million, with Gas Pipeline’s share being 50 percent of such costs. Service under the Gulfstream also has executed a precedent agreement and a related firm transportation service agreement pursuant to which, subject toPhase IV expansion project began during the receiptfourth quarter of all necessary regulatory approvals and other conditions precedent therein, we intend to construct and2008. The project is fully subscribesubscribed on a long-term basis and is the first incremental expansion of Gulfstream’s mainline capacity, increasing the current mainline capacity of 1.1 MMdt/d to 1.255 MMdt/d. The project will include the construction of additional pipeline in Florida and the installation of new compression in Alabama and Florida.capacity. The estimated capital cost of this expansion is anticipated$192 million, with Gas Pipeline’s share being 50 percent of such costs.
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WMZ
WMZ was formed to be approximately $117 million. No significant increaseown and operate natural gas transportation and storage assets. We currently own an approximate 45.7 percent limited partnership interest and a 2 percent general partner interest in operations personnelWMZ. WMZ provides us with lower cost of capital that is expected to enable growth of our Gas Pipeline business. WMZ also creates a vehicle to monetize our qualifying assets. Such transactions, which are subject to approval by the boards of directors of Williams and WMZ’s general partner, allow us to retain control of the assets through our ownership interest in WMZ. A subsidiary of ours, Williams Pipeline GP LLC, serves as the general partner of WMZ. The initial asset of WMZ is a result of these two projects.35 percent interest in Northwest Pipeline.
Midstream Gas & Liquids
Our Midstream segment, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in the major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, Venezuela and western Canada. Midstream’s primary businesses — natural gas gathering, treating, and processing; natural gas liquids (NGL)NGL fractionation, storage and transportation; and oil transportation — fall within the middle of the process of taking natural gas and crude oil from the wellhead to the consumer. NGLs, ethylene and propylene are extracted/produced at our plants, including our Canadian and Gulf Coast olefins plants. These products are used primarily for the manufacture of plastics,petrochemicals, home heating fuels and refinery feedstock.
Although mostSome of our gas servicesassets are performed for a volumetric-based fee, a portion ofowned through our gas processing contracts are commodity-based and include two distinct types of commodity exposure. The first type includes “Keep Whole” processing contracts whereby we own the NGLs extracted and replace the lost heating value with natural gas. Under these contracts, we are exposed to the spread between NGLs and natural gas prices. The second type consists of “Percent of Liquids” contracts whereby we receive a portion of the extracted liquids with no direct exposure to the price of natural gas. Under these contracts, we are only exposed to NGL price movements.
Our Canadian and Gulf Liquids olefin facilities have commodity exposure. In Canada, we are exposed to the spread between the price for natural gas and the olefinic products we produce. In the Gulf Coast, our feedstock for the ethane cracker is ethane and propane; as a result, we are exposed to the price spread between ethane and propane and ethylene and propylene. In the Gulf Coast, we also purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result we are exposed to the price spread between those commodities.interest in WPZ.
Key variables for our business will continue to be:
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| | • | retainingRetaining and attracting customers by continuing to provide reliable services; |
| |
| | • | revenueRevenue growth associated with additional infrastructure either completed or currently under construction; |
| |
| | • | disciplinedDisciplined growth in our core service areas and new step-out areas; |
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| | • | pricesPrices impacting our commodity-based processing and olefin activities. |
Domestic gathering, processing and processingtreating
WeOur domestic gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing and treating plants remove water vapor, carbon dioxide and other contaminants and our processing plants extract the NGLs. NGL products include:
| | |
| • | Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics; |
|
| • | Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials and molded plastic parts; |
|
| • | Normal butane, iso-butane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock. |
Although a significant portion of our gas processing services are performed for a volumetric-based fee, a portion of our gas processing agreements are commodity-based and include two distinct types of commodity exposure. The first type includes “keep whole” processing agreements whereby we own the rights to the value from NGLs recovered at our plants and have the obligation to replace the lost heating value with natural gas. Under these agreements, we are exposed to the spread between NGL prices and natural gas prices. The second type consists of “percent of liquids” agreements whereby we receive a portion of the extracted liquids with no direct exposure to the price of natural gas. Under these agreements, we are only exposed to NGL price movements. NGLs we retain in
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connection with these types of processing agreements are referred to as our equity NGL production. Our gathering and processing agreements have terms ranging fromand/ormonth-to-month operateto the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements.
Our domestic gas gathering and processing customers are generally natural gas producers who have provedand/or producing natural gas fields in the areas surrounding our infrastructure. During 2008, these operations gathered and processed gas for approximately 230 gas gathering and processing customers. Our top six gathering and processing customers accounted for about 50 percent of our domestic gathering and processing revenue.
In addition to our natural gas assets, primarily within the western states of Wyoming, Coloradowe own and New Mexico,operate three deepwater crude oil pipelines and the onshore and offshore shelf anda deepwater areasfloating production platform in and around the Gulf Coast states of Texas, Louisiana, MississippiMexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a substantial portion of our marketing revenues are recognized from purchase and Alabama. These assets consistsale arrangements whereby we purchase oil from producers at the receipt points of approximately 8,200 milesour crude oil pipelines for an index-based price and sell the oil back to the producers at delivery points at the same index-based price. Our offshore floating production platform provides centralized services to deepwater producers such as compression, separation, production handling, water removal and pipeline landings. Revenue sources have historically included a combination of gathering pipelines, nine processing plants (one partially owned)fixed-fee, volumetric-based fee and five natural gas treating plantscost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a combined daily inlet capacityunits of nearly 6.2 billion cubic feet per day. Some of these assets are owned through our interest in Williams Partners L.P. (see Williams Partners L.P. section below).production basis.
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Geographically, our Midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of our offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Also, our gathering and processing facilities in the San Juan basinBasin handle about 8587 percent of our Exploration & Production group’s wellhead production in this basin. Both our San Juan Basin and Southwest Wyoming systems deliver residue gas volumes into Northwest Pipeline’s interstate system.
In addition to these natural gas assets, we own and operate three crude oil pipelines totaling approximately 270 miles with a capacity of more than 300,000 barrels per day. This includes our Mountaineer, Alpine and BANJO crude oil pipeline systems in the deepwater Gulf of Mexico.
The BANJO oil pipeline and Seahawk gas pipeline run parallel and deliver production across two producer-owned spar-type floating production systems from the Kerr-McGee-operated Boomvang and Nansen field areas in the western Gulf of Mexico. These pipelines were placed in service on January 28, 2002.
Our 18 inch oil pipeline, Alpine, which became operational on December 14, 2003, is our second western gulf crude oil pipeline. The pipeline extends 96 miles from Garden Banks Block 668 in the central Gulf of Mexico to our shallow-water platform at Galveston Area Block A244. From this platform, the oil is delivered onshore through ExxonMobil’s Hoover Offshore Oil Pipeline System under a joint tariff agreement. This production is coming from the Gunnison field, which is located in 3,150 feet of water and operated by Kerr-McGee.
Our Devils Tower floating production system and associated pipelines were placed in service on May 5, 2004. Initially built to serve Dominion Exploration & Production’s Devils Tower field, the floating production system is located in Mississippi Canyon Block 773, approximately 150 miles south-southwest of Mobile, Alabama. During the fourth quarter of 2005, the platform’s service expanded to include tie-backs of production from the Triton and Goldfinger fields in addition to the host Devils Tower field. Located in 5,610 feet of water, it is the world’s deepest dry tree spar. The platform, which is operated by Dominion on our behalf, is capable of producing 60 MMcf/d of natural gas and 60 Mbbls/d of oil.
The Devils Tower project includes gas and oil pipelines. The102-mile Canyon Chief gas pipeline consists of18-inch diameter pipe. The118-mile Mountaineer oil pipeline is a combination of 18- and20-inch diameter pipe. The gas is delivered into Transco’s pipeline, and processed at our Mobile Bay plant to recover the NGLs. The oil is transported to ChevronTexaco’s Empire Terminal in Plaquemines Parish, Louisiana. These associated pipelines are significantly oversized relative to the Devils Tower spar top-side capacity.
Included in the natural gas assets listed above are the assets of Discovery Producer Services LLC and its subsidiary Discovery Gas Transmission Services LLC (Discovery). We own a partial interest in Discovery and operate its facilities. Discovery’s assets include a cryogenic natural gas processing plant near Larose, Louisiana, a natural gas liquids fractionator plant near Paradis, Louisiana and an offshore natural gas gathering and transportation system.third party interstate systems.
Gulf Coast petrochemicalWest Region domestic gathering, processing and olefinstreating
We own a 5/12 interestand/or operate domestic gas gathering, processing and treating assets within the western states of Wyoming, Colorado and New Mexico.
In the Rocky Mountain area, our assets include:
| | |
| • | 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 over1,800 MMcf/d and NGL processing capacity of nearly 100 Mbbls/d. |
In the Four Corners area, our assets include:
| | |
| • | Approximately 3,800 miles of gathering pipelines serving the San Juan Basin in New Mexico and Colorado; |
|
| • | Ignacio, Kutz and Lybrook processing plants with a combined daily inlet capacity of765 MMcf/d and NGL processing capacity of approximately 40 Mbbls/d; |
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| • | Milagro and Esperanza natural gas treating plants, which remove carbon dioxide but do not extract NGLs, with a combined daily inlet capacity of750 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. |
As we enter the Piceance Basin in and are the operator for an ethane cracker at Geismar, Louisiana, with a total production capacity of 1.3 billion pounds per year of ethylene. We also own an ethane pipeline system in Louisiana. Our Gulf Liquids New River LLC (Gulf Liquids) business consists of a propylene splitter and its related pipeline system.Colorado, our initial infrastructure includes:
| | |
| • | Parachute Lateral, a38-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 |
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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 & Production’s existing Parachute area processing plants to a major NGL transportation pipeline system. |
CanadaWest region expansion projects
Our Canadian operationstwo major expansion projects include an olefin liquids extraction plant located near Ft. McMurray, Albertathe new Willow Creek facility and an olefin fractionation facility near Edmonton, Alberta. Our facilities extract olefinic liquids fromadditional capacity at our Echo Springs facility.
| | |
| • | The Willow Creek processing plant is a450 MMcf/d cryogenic natural gas processing plant in western Colorado’s Piceance Basin, where Exploration & Production has its most significant volume of natural gas production, reserves and development activity. The plant is designed to recover 25 Mbbls/d of NGLs and the plant’s inlet processing capacity is expected to be full atstart-up expected in late 2009. |
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| • | 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 approximately350 MMcf/d of processing capacity and 30 Mbbls/d of NGL production capacity, nearly doubling Echo Spring’s 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. |
Gulf region domestic gathering, processing and treating
We ownand/or operate domestic gas gathering and processing assets and crude oil pipelines primarily within the off-gas produced from third party oil sands bitumen upgradingonshore and then fractionate, treat, store, terminaloffshore shelf and selldeepwater areas in and around the propane, propylene, butaneGulf Coast states of Texas, Louisiana, Mississippi and condensate recovered from this process.Alabama. We continue to be the only olefins fractionator in Western Canada and the only treater-processor of oil sands upgrader off-gas. These operations extract valuable petrochemical feedstocks from upgrader off-gas streams allowing the upgraders to burn cleaner natural gas streamsown:
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| • | Over 700 miles of onshore and offshore natural gas gathering pipelines, including: |
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| • | The115-mile deepwater Seahawk gas pipeline in the western Gulf of Mexico, flowing into our Markham processing plant and serving the Boomvang and Nansen field areas; |
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| • | The139-mile Canyon Chief gas pipeline, now including the new37-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; |
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| • | Mobile Bay, Markham, and Cameron Meadows processing plants with a combined daily inlet capacity of nearly1,500 MMcf/d and NGL handling capacity of 65 Mbbls/d; |
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| • | 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 of500 MMcf/d; |
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| • | Three deepwater crude oil pipelines with a combined length of 300 miles and capacity of 300 Mbbls/d including: |
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| • | BANJO pipeline running parallel to the Seahawk gas pipeline delivering production from two producer-owned spar-type floating production systems; and delivering production to our shallow-water platform at Galveston Area Block A244 (GA-A244) and then onshore through ExxonMobil’s Hoover Offshore Oil Pipeline System (HOOPS); |
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| • | 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; |
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| • | Mountaineer oil pipeline which connects to similar production sources as our Canyon Chief pipeline and, now including the new Blind Faith extension, ultimately delivering production to ChevronTexaco’s Empire Terminal in Plaquemines Parish, Louisiana; |
| | |
| • | Devils Tower 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 world’s deepest dry tree |
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and reduce overall air emissions. The extraction plant has processing capacity in excess of 100 MMcf/d with the ability to recover in excess of 15 Mbbls/d of NGL products.
| | |
| | spars. The platform, which is operated by ENI Petroleum on our behalf, is capable of handling210 MMcf/d of natural gas and 60 Mbbls/d of oil. |
Venezuela
Our Venezuelan investments involve gas compression and gas processing and natural gas liquids fractionation operations. We own controlling interests and operate three gas compressor facilities which provide roughly 70 percent of the gas injections in eastern Venezuela. These facilities help stabilize the reservoir and enhance the recovery of crude oil by re-injecting natural gas at high pressures. We also own a 49.25 percent interest in two 400 MMcf/d natural gas liquids extraction plants, a 50,000 barrels per day natural gas liquids fractionation plant and associated storage and refrigeration facilities.
Other
We own interests inand/or operate NGL fractionation and storage assets. These assets include two partially owned NGL fractionation facilities near Conway, Kansas and Baton Rouge, Louisiana that have a combined capacity in excess of 167,000 barrels per day. We also own approximately 20 million barrels of NGL storage capacity in central Kansas. Some of these assets are owned through our interest in Williams Partners L.P.
Williams Partners L.P.
Williams Partners L.P. (Williams Partners) was formed to engage in the business of gathering, transporting and processing natural gas and fractionating and storing NGLs. We own approximately 22.5 percent of Williams Partners. Williams Partners provides us with an acquisition currency that is expected to enable growth of our Midstream business. Williams Partners also creates a vehicle to monetize our qualifying assets. Such transactions, which are subject to approval by both our and Williams Partners’ general partner’s board of directors, allow us to retain control of the assets through our ownership interest in Williams Partners.
During 2006, Williams Partners L.P. acquired Williams Four Corners, LLC which includes a3,500-mile natural gas gathering system in the San Juan Basin in New Mexico and Colorado with capacity of nearly 2 billion cubic feet per day; the Ignacio natural gas processing plant in Colorado and the Kutz and Lybrook natural gas processing plants in New Mexico, which have a combined processing capacity of 760 million cubic feet per day; and the Milagro and Esperanza natural gas treating plants in New Mexico, which are designed to remove carbon dioxide from up to 750 million cubic feet of natural gas per day.
In addition, Williams Partners owns a 40 percent equity investment in the Discovery gathering, transportation, processing and NGL fractionation system; the Carbonate Trend sour gas gathering pipeline; three integrated NGL storage facilities near Conway, Kansas; and a 50 percent interest in an NGL fractionator near Conway, Kansas.
Expansion projects
Gathering and processing
In May 2006, we entered into an agreement to develop new pipeline capacity for transporting natural gas liquids from production areas in southwestern Wyoming to central Kansas. The other party to the agreement reimbursed us for the development costs we incurred to date for the proposed pipeline and initially will own 99 percent of the pipeline, known as Overland Pass Pipeline Company, LLC. We retained a 1 percent interest and have the option to increase our ownership to 50 percent and become the operator within two years of the pipeline becoming operational.Start-up is planned for early 2008. Additionally, we have agreed to dedicate our equity NGL volumes from our two Wyoming plants for transport under a long-term shipping agreement. The terms represent significant savings compared with the existing tariff and other alternatives considered.
We are constructing a fifth cryogenic processing train at our existing gas plant in Opal, Wyoming, which is scheduled forstart-up in the first quarter of 2007. TheGulf region expansion is designed to boost the plant’s processing capacity by more than 30 percent to 1.45 billion cubic feet per day. Opal also will be able to recover a total of approximately 67,000 barrels per day of natural gas liquids.
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Gathering and processing — deepwater projects
The deepwater Gulf continues to be an attractive growth area for our Midstream business. Since 1997, we have invested almost $1over $1.5 billion in new midstream assets in the Gulf of Mexico. These facilities provide both onshore and offshore services through pipelines, platforms and processing plants. The new facilities could also attract incremental gas volumes to Transco’s pipeline system in the southeastern United States.
Chevron and Kerr-McGee are dedicating to us the transport of production from theirOur current and future ownership in a defined area surrounding the Blind Faith discoverymajor expansion projects in the deepwater Gulf of Mexico. To accommodate production from the Blind Faith acreage and the surrounding blocks, we have agreed to extend our Canyon Chief and Mountaineer pipelines to the producer-owned floating production facility. We expect to have the extensions ready for service in second quarter 2008. The approximately $200 million project will facilitate a37-mile extension of each pipeline. The agreement also creates opportunities for us to move natural gas from the Blind Faith discovery through our Mobile Bay, Alabama, processing plant and our Transco and Gulfstream interstate pipeline systems. Recovered natural gas liquids from Blind Faith also could be fractionated at our facilities in Baton Rouge or Paradis, Louisana.region include:
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| • | In the deepwater of the Gulf of Mexico, we completed construction of37-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; |
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| • | 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. |
Customers and operationsVenezuela
Our domesticVenezuelan investments involve gas gatheringcompression and an equity interest in a gas processing customers are generallyand NGL fractionation operation. We own controlling interests and operate three gas compressor facilities which provide roughly 65 percent of the gas injections in eastern Venezuela. These facilities help stabilize the reservoir and enhance the recovery of crude oil by re-injecting natural gas producers who have provedand/or producing naturalat high pressures. The three gas fields in the areas surrounding our infrastructure. During 2006, these operations gathered and processed gas for approximately 220 gas gathering and processing customers. Our top three gathering and processing customers accounted for about 44 percentcompressor facilities, owned within two of our domestic gatheringVenezuelan subsidiaries, had a net book value of $324 million at December 31, 2008 and processing revenue. Our gatheringare held as security on $177 million of non-recourse debt at December 31, 2008. We own controlling interests of 70% and processing agreements are generally long-term agreements.
In addition to our gathering and processing operations, we market NGLs and petrochemical products to a wide range of users66.67% in the energy and petrochemical industries. We provide these products to third parties from the production at our domestic facilities. The majority of domestic sales are based on supply contracts of less than one year in duration. The production from our Canadian facilities is marketed in Canada and in the United States.two subsidiaries.
Our Venezuelan assets were constructed and are currently operated for the exclusive benefit of the Venezuelan state-owned oil company, Petróleos de Venezuela S.A. Theunder long-term contracts. These significant contracts have a remaining term between 119 and 1512 years and our revenues are based on a combination of fixed capital payments, throughput volumes and, in the case of one of the gas compression facilities, a minimum throughput guarantee. The Venezuelan government has continuedcontinues its public criticism of U.S. economic and political policy, has implemented unilateral changes to existing energy related contracts, and continues to publicly declare that additional energy contracts will be unilaterally amended andhas expropriated privately held assets willwithin the energy and telecommunications sector. The continued threat of nationalization of certain energy-related assets in Venezuela could have a material negative impact on our results of operations. The economic situation resulting from lower commodity prices could jeopardize the Venezuelan oil industry and may further exacerbate political tension in Venezuela. We may not receive adequate compensation, or any compensation, if our assets in Venezuela are nationalized.
We also own a 49.25 percent interest in Accroven SRL which includes two400 MMcf/d NGL extraction plants, a 50 Mbbls/d NGL fractionation plant and associated storage and refrigeration facilities. Our equity investment had a book value of $69 million at December 31, 2008.
Olefins
In the Gulf of Mexico region, we own a10/12 interest in and are the operator of an ethane cracker at Geismar, Louisiana, with a total production capacity of 1.3 billion pounds of ethylene and 90 million pounds of propylene per year. Our feedstock for the ethane cracker is ethane and propane; as a result, we are exposed to the price spread between ethane and propane, and ethylene and propylene. We also own ethane and propane pipeline systems and a refinery grade propylene splitter with a production capacity of approximately 500 million pounds per year of propylene and its related pipeline system in Louisiana. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result we are exposed to the price spread between those commodities.
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Our Canadian operations include an olefin liquids extraction plant located near Ft. McMurray, Alberta and an olefin fractionation facility near Edmonton, Alberta. Our facilities extract olefinic liquids from the off-gas produced by a third party oil sands bitumen upgrading process. Our arrangement with the third-party upgrade is a “keep whole” type where we remove a mix of NGLs and olefins from the off-gas and return the equivalent heating value back to the third party in the form of natural gas. We then fractionate, treat, store, terminal and sell the propane, propylene, butane, butylenes and condensate recovered from this process. Our commodity price exposure is the spread between the price for natural gas and the NGL and olefin products we produce. We continue to be expropriated, indicatingthe only olefins fractionator in western Canada and the only treater/processor of oil sands upgrader off-gas. These operations extract petrochemical feedstocks from upgrader off-gas streams allowing the upgraders to burn cleaner natural gas streams and reduce overall air emissions. The extraction plant has processing capacity in excess of100 MMcf/d with the ability to recover in excess of 15 Mbbls/d of olefin and NGL products.
NGL and olefin marketing services
In addition to our gathering, processing and olefin production operations, we market NGLs and olefin products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets equity NGLs from the production at our domestic processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery Producer Services L.L.C. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. The majority of domestic sales are based on supply contracts of one year or less in duration. The production from our Canadian facilities is marketed in Canada and in the United States.
Other
We own interests inand/or operate NGL fractionation and storage assets. These assets include two partially owned NGL fractionation facilities: one near Conway, Kansas and the other in Baton Rouge, Louisiana that have a levelcombined capacity in excess of political risk still remains.167 Mbbls/d. We also own approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.
We own an equity interest in and operate the facilities of Discovery Producer Services LLC and its subsidiary Discovery Gas Transmission Services LLC (collectively, Discovery) through our interest in WPZ. Discovery’s assets include a600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a32 Mbbl/NGL fractionator plant near Paradis, Louisiana and an offshore natural gas gathering and transportation system in the Gulf of Mexico.
We also own a 14.6 percent equity interest in Aux Sable Liquid Products and its Channahon, Illinois gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 87 Mbbls/d of extracted liquids into NGL products.
Operating statistics
The following table summarizes our significant operating statistics for Midstream:
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| |
| Volumes(1): | | | | | | | | | | | | |
| Domestic Gathering (trillion British Thermal Units) | | | 1,181 | | | | 1,253 | | | | 1,252 | |
| Domestic Natural Gas Liquid Production (Mbbls/d)(2) | | | 152 | | | | 144 | | | | 155 | |
| Crude Oil Gathering (Mbbls/d)(2) | | | 86 | | | | 88 | | | | 83 | |
| Processing Volumes (trillion British Termal Units) | | | 833 | | | | 721 | | | | 768 | |
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| |
| Volumes(1): | | | | | | | | | | | | |
| Domestic gathering (TBtu) | | | 1,013 | | | | 1,045 | | | | 1,181 | |
| Plant inlet natural gas (TBtu) | | | 1,311 | | | | 1,275 | | | | 1,222 | |
| Domestic NGL production (Mbbls/d)(2) | | | 154 | | | | 163 | | | | 152 | |
| Domestic NGL equity sales (Mbbls/d)(2) | | | 80 | | | | 92 | | | | 88 | |
| Crude oil gathering (Mbbls/d)(2) | | | 70 | | | | 80 | | | | 86 | |
| Canadian NGL equity sales (Mbbls/d)(2) | | | 7 | | | | 9 | | | | 8 | |
| Olefin (ethylene and propylene) sales (millions of pounds) | | | 1,605 | | | | 1,401 | | | | 988 | |
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| (1) | | Excludes volumes associated with partially owned assets that are not consolidated for financial reporting purposes. |
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| (2) | | Annual Average Mbbls/dd. |
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PowerWPZ
Our Power business buys, sells, storesWPZ was formed in 2005 to engage in gathering, transporting, processing and transports energy and energy-related commodities, primarily power and natural gas. Power’s focus is not only on its objective of maximizing expected cash flows, but also on executing new contracts to hedge its portfolio and providing services that support ourtreating natural gas businesses across Williams. Our contracts include physical forward purchases and sales, various financial instrumentsfractionating and structured transactions. Our financial instruments include exchange-traded futures, as well as exchange-tradedstoring NGLs. We currently own approximately a 23.6 percent limited partnership interest including the interests of the general partner, Williams Partners GP LLC, which is wholly owned by us, andover-the-counter options and swaps. Structured incentive distribution rights. WPZ provides us with an alternative source of equity capital. WPZ also creates a vehicle to monetize our qualifying assets. Such transactions, include tolling contracts, full requirements contracts, tolling resales and heat rate options.
Tolling contracts represent the most significant portion of our portfolio. Under the tolling contracts, we have the right to request a plant owner to convert our fuel (usually natural gas) to electricity in exchange for a fixed fee. We have the right to request approximately 7,700 megawatts of electricity under six tolling agreements. The table below lists the locations and available capacity of each of our tolling agreements. These capacity numberswhich are subject to change,approval by the boards of directors of both Williams and our contractual rightsWPZ’s general partner, allow us to capacity may not reflect actual availability at the plants.
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Location
| | Megawatts | |
|
California | | | 4,141 | |
Alabama | | | 844 | |
Louisiana | | | 758 | |
New Jersey | | | 766 | |
Pennsylvania | | | 664 | |
Michigan | | | 545 | |
| | | | |
Total
| | | 7,718 | |
| | | | |
We use portionsretain control of the electricity produced underassets through our ownership interest in WPZ and operation of the tolling agreements to supply obligations under various arrangements such as power sales, tolling resales,assets. WPZ’s asset portfolio includes Williams Four Corners LLC, certain ownership interests in Wamsutter LLC, a 60 percent interest in Discovery, three integrated NGL storage facilities near Conway, Kansas, a 50 percent interest in an NGL fractionator near Conway, Kansas and full requirements contracts. Under full requirements contracts, we supply the electricity required by our counterparties to serve their customers. Through full requirements contracts, we supply approximately 600 to 1,500 megawattsCarbonate Trend sour gas gathering pipeline off the coast of electricity to our customers in Georgia and approximately 515 to 600 megawatts of electricity to our customers in Pennsylvania. The amount of electricity we supply under these contracts varies year to year but is expected to grow annually. Each year, the amount of electricity we supply is subject to a growth cap.
Through tolling resale agreements, we enter into transactions that mirror, to varying degrees, some or all of our rights under our underlying tolling arrangements, which remain in place with our tolling counterparties. We have resold part of our rights (1,934 to 3,875 megawatts) under the California tolling arrangement to two counterparties for periods through 2011. These volumes include amounts sold under contracts executed in 2007.
We also own two natural gas-fired electric generating plants located near Bloomfield, New Mexico (60 megawatts, Milagro facility) and in Hazleton, Pennsylvania (147 megawatts).
In 2006, we managed natural gas throughout North America with total physical volumes averaging 2.3 billion cubic feet per day. We use approximately 10 percent of this natural gas to fuel electric generating plants we own or in which we have contractual rights. We sell approximately 70 percent of this natural gas to customers including local distribution companies, utilities, producers, industrials and other gas marketers. With the remaining 20 percent, we procure gas supply for our Midstream operations.
In 2004, we substantially exited our crude oil and refined products activities.
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Operating statistics
The following table summarizes marketing and trading gross sales volumes, including sales volumes to other segments, for the periods indicated:
| | | | | | | | | | | | | |
| | | Year Ending December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
| |
| Marketing and trading physical volumes: | | | | | | | | | | | | |
| Power (thousand megawatt hours) | | | 53,866 | | | | 66,779 | | | | 93,998 | |
| Natural gas (billion cubic feet per day) | | | 2.1 | | | | 2.1 | | | | 2.3 | |
| Petroleum products (thousand barrels per day) | | | — | | | | — | | | | 50 | |
In 2006, Power managed 2.3 billion cubic feet per day of natural gas. The natural gas volumes managed include the following (in billion cubic feet per day):
| | | | |
| | 2006 | |
|
Sales to third parties | | | 1.7 | |
Sales to other segments | | | .4 | |
For use in tolling agreements and by owned generation | | | .2 | |
| | | | |
Total natural gas managed | | | 2.3 | |
| | | | |
As of December 31, 2006, Power had approximately 350 customers compared with approximately 300 customers at the end of 2005.Alabama.
OtherGas Marketing Services
At December 31, 2004, we owned approximately 94.7 percent ofGas Marketing Services (Gas Marketing) primarily supports our natural gas businesses by providing marketing and risk management services, which includes marketing and hedging the Class B Interestsgas produced by Exploration & Production, and 21.3 percent of the Common Interests in Longhorn Partners Pipeline LP (Longhorn), which owned a refined petroleum products pipeline from Houston, Texasprocuring fuel and shrink gas and hedging natural gas liquids sales for Midstream. Gas Marketing also provides similar services to El Paso, Texas. The Class B Interests are preferred interests but subordinate to other preferred interests,third parties, such as producers. In addition, Gas Marketing manages various natural gas-related contracts such as transportation, storage, related hedges and the Common Interests are subordinate to both.proprietary trading positions, including certain legacy natural gas contracts and positions.
During the first quarterGas Marketing’s 2008 natural gas purchase volumes include 1.4Bcf/d of 2005, Longhorn became fully operational as deliveries commenced through both the Odessagas produced by Exploration & Production and El Paso terminals. However, the pipeline’s throughput fell significantly short of management expectations. The primary driver behind this volume shortfallanother 1.0 Bcf/d from third party/other sources. This natural gas was the narrowing of the refined product pricing differentials between the Gulf Coastin turn marketed and El Paso markets. During the second quarter of 2005, Longhorn management indicated the shortfall was likelysold to continuethird parties (2.0 Bcf/d) and that the original business model was no longer feasible.to Midstream (.4 Bcf/d).
Our Exploration & Production and Midstream segments may execute commodity hedges with Gas Marketing. In turn, Gas Marketing may execute offsetting derivative contracts with unrelated third parties.
As a result of theother-than-temporary decline in fair value identified in the second quarter sale of 2005, we impaired the Common Interests by $16.2 million and the Class B shares by $32.7 million. After these adjustments, the book valuea substantial portion of our investmentPower business in Longhorn (as of June 30, 2005) totaled $51.6 million, comprised of $25.0 million of Common Interests and $26.6 million of Class B shares.
During the third quarter of 2005, we provided $10 million of a $50 million fully collateralized bridge loan to fund operations of Longhorn until an economically feasible operational alternative was developed. In the fourth quarter of 2005, management of Longhorn concluded that its best alternative would be to sell2007, Gas Marketing is also responsible for certain remaining legacy natural gas contracts and positions. During 2008, we substantially reduced the Longhorn assets. Accordingly, they directed a financial advisor to solicit offers from several entities. After reviewing the terms and conditions of bids received, our management determined that a full impairment of our investment in the Class B and Common Interests was appropriate. This decision resulted in a December 31, 2005 write-down of the remaining $38.1 million in book value which had been further reduced by additional equity losses during the third and fourth quarters.
The management of Longhorn completed an installment sale of the pipeline during the third quarter of 2006, and as a result we received full payment of the $10 million secured bridge loan that we provided to Longhorn during 2005. It is uncertain whether we will ever receive any payments related to our Class B Interests or our Common
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Interests, however any such amounts related to these fully impaired interests will only be recognized as income when received.
We continue to receive payments associated with the 2005 transfer of the First Amended and Restated Pipeline Operating Services Agreement to a third party. The sale of the pipeline did not impact these ongoing payments which are recognized as income when received.overall legacy positions remaining.
Additional business segment informationBusiness Segment Information
Our ongoing business segments are accounted for as continuing operations in the accompanying financial statements and notes to financial statements included in Part II.
Operations related to certain assets in “Discontinued Operations” sold in 2003 and 2004 have been reclassified from their traditional business segment to “Discontinued Operations” in the accompanying financial statements and notes to financial statements included in Part II.
Our corporate parent company performsWe perform certain management, legal, financial, tax, consultative,consultation, information technology, administrative and other services for our subsidiaries.
Our corporate parent company’s principal sources of cash are from external financings, dividends and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, interest payments from subsidiaries on cash advances and, if needed, external financings, sales of master limited partnership units to the public, and net proceeds from asset sales. The amount of dividends available to us from subsidiaries largely depends upon each subsidiary’s earnings and operating capital requirements. The terms of certain of our subsidiaries’ borrowing arrangements limit the transfer of funds to our corporate parent.us.
We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. In support of our energy commodity activities, primarily conducted through Power,Gas Marketing Services, our counterparties require us to provide various forms of credit support such as margin, adequate assurance amounts and pre-payments for gas supplies. Our pipeline systems are all regulated in various ways resulting in the financial return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays.
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REGULATORY MATTERS
Exploration & Production. Our Exploration & Production business is subject to various federal, state and local laws and regulations on taxation and payment of royalties, and the development, production and marketing of oil and gas, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Such laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our reserves.
Gas Pipeline. Gas Pipeline’s interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, its accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, and the Pipeline Safety Improvement Act of 2002, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with theirgas marketing affiliates.employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit theirgas marketing affiliates.functions.
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Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are:
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| | • | costsCosts of providing service, including depreciation expense; |
| |
| | • | allowedAllowed rate of return, including the equity component of the capital structure and related income taxes; and |
| |
| | • | volumeVolume throughput assumptions. |
The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the demand and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.
Midstream.Midstream Gas & Liquids. For our Midstream segment, onshore gathering is subject to regulation by states in which we operate and offshore gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Of the states where Midstream gathers gas, currently only Texas actively regulates gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement. Although offshore gathering facilities located offshore are not subject to the NGA, (although offshore transmission pipelines may be), some controversy exists asare subject to howthe NGA, and in recent years the FERC should determine whetherhas taken a broad view of offshore facilities function as gathering. These issues are currently before the FERC.transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most gathering facilities offshore are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and non-owner shippers.”
Midstream also owns interests in and operates two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery Gas Transmission LLC provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the CommissionFERC before any changes can go into effect. Currently,In 2007, Black Marlin hasfiled and settled a major rate change application pending before the Commission to increase itsFERC, resulting in increased rates for service. In November 2007, Discovery filed a settlement in lieu of a rate change filing, which the FERC approved effective January 1, 2008, for all parties, except one protestor, Exxon Mobil Gas
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and Power Marketing Company. Among other things, the settlement increases Discovery’s rates for service, although most volumes flowing before the settlement became effective are not affected by the rate change due to life of lease rates and commitments.
Our remaining Midstream Canadian assets are regulated by the Alberta Energy & UtilitiesResources Conservation Board (AEUB)(ERCB) and Alberta Environment. The regulatory system for the Alberta oil and gas industry incorporates a large measure of self-regulation, providing that licensed operators are held responsible for ensuring that their operations are conducted in accordance with all provincial regulatory requirements. For situations in which non-compliance with the applicable regulations is at issue, the AEUBERCB and Alberta Environment have implemented an enforcement process with escalating consequences.
Power.Gas Marketing Services. Our PowerGas Marketing business is subject to a variety of laws and regulations at the local, state and federal levels, including the FERC and the Commodity Futures Trading Commission regulation.regulations. In addition, electricity and natural gas markets in California and elsewhere continue to be subject to numerous and wide-ranging federal and state regulatory proceedings and investigations. We are also subject to various federal and state actions and investigations regarding, among other things, market structure, behavior of market participants, market prices, and reporting to trade publications. We may be liable for refunds and other damages and penalties as a result of ongoing actions and investigations. The outcome of these matters could affect our creditworthiness and ability to perform contractual obligations as well as other market participants’ creditworthiness and ability to perform contractual obligations to us.
See Note 1516 of our Notes to Consolidated Financial Statements for further details on our regulatory matters.
ENVIRONMENTAL MATTERS
Our generation facilities, processing facilities, natural gas pipelines, and exploration and production operations are subject to federal environmental laws and regulations as well as the state and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful
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discharge of oil, gas or other pollutants into the air, soil, or water, as well as liability for clean up costs. Materials could be released into the environment in several ways including, but not limited to:
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| | • | fromFrom a well or drilling equipment at a drill site; |
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| | • | leakageLeakage from gathering systems, pipelines, processing or treating facilities, transportation facilities and storage tanks; |
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| | • | damageDamage to oil and gas wells resulting from accidents during normal operations; and |
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| | • | blowouts,Blowouts, cratering and explosions. |
Because the requirements imposed by environmental laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, we may be liable for environmental damage caused by former operators of our properties.
We believe compliance with environmental laws and regulations will not have a material adverse effect on capital expenditures, earnings or competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, imposing limitations on generation facility availability, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses (which we believe would be granted).expenses.
For a discussion of specific environmental issues, see “Environmental” under Management’s Discussion and Analysis of Financial Condition and Results of Operations and “Environmental Matters” in Note 1516 of our Notes to Consolidated Financial Statements.
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COMPETITION
Exploration & Production. Our Exploration & Production segment competes with other oil and gas concerns, including major and independent oil and gas companies in the development, production and marketing of natural gas. We compete in areas such as acquisition of oil and gas properties and obtaining necessary equipment, supplies and services. We also compete in recruiting and retaining skilled employees.
Gas Pipeline. Our Gas Pipeline segment faces increased competition as a result of various actions taken by the FERC and several states in which we operate to strengthen market forces in theThe natural gas pipeline industry. In a number of key markets, interstate pipelines are now facingindustry has undergone significant change over the past two decades. A highly-liquid competitive pressures from other major pipeline systems, enabling local distribution companies and end users to choose a supplier or switch suppliers based on the short-term price ofcommodity market in natural gas and the cost of transportation. We expect competitionincreasingly competitive markets for natural gas transportationservices, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity.
Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Pipeline operators are increasingly challenged to continueaccommodate the flexibility demanded by customers and allowed under tariffs, but the changes implemented at the state level have not required renegotiation of LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.
States are in the process of developing new energy plans that may require utilities to intensify in future years dueencourage energy saving measures and diversify their energy supplies to include renewable sources. This could lower the growth of gas demand.
These factors have increased customer access to other pipelines, rates, competitiveness among pipelines, customers’ desire to have more than one transporter, shorter contract terms, regulatory developments, and development of LNG facilities particularly in our market areas.the risk that customers will reduce their contractual commitments for pipeline capacity. Future utilization of pipeline capacity will also depend on competition from LNG imported into markets and new pipelines from the Rockies and other pipelinesnew producing areas, many of which are utilizing master limited partnership structures with a lower cost of capital, and LNG facilities, use of alternative fuels, the general levelon growth of natural gas demand, and weather conditions.demand.
Suppliers of natural gas are able to compete for any gas markets capable of being served by pipelines using nondiscriminatory transportation services provided by the pipeline companies. As the regulated environment has matured, many pipeline companies have faced reduced levels of subscribed capacity as contractual terms expire and customers opt to reduce firm capacity under contract in favor of alternative sources of transmission and related services. This situation, known in the industry as “capacity turnback,” is forcing the pipeline companies to evaluate the consequences of major demand reductions in traditional long-term contracts. It could also result in significant shifts in system utilization, and possible realignment of cost structure for remaining customers because all interstate natural gas pipeline companies continue to be authorized to charge maximum rates approved by the FERC on a cost of service basis.Midstream Gas Pipeline does not anticipate any significant financial impact from “capacity turnback.” We anticipate that we will be able to remarket most future capacity subject to future capacity turnback, although competition may cause some of the remarketed capacity to be sold at lower rates or for shorter terms.
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Midstream.& Liquids. In our Midstream segment, we face regional competition with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, master limited partnerships (MLP), producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, timeliness of well connections,services to be provided, pressure obligations and contract structure. We also compete in recruiting and retaining skilled employees. In 2005, we formed Williams PartnersWPZ to help compete against other master limited partnerships for midstream projects. By virtue of the master limited partnership structure, Williams PartnersWPZ provides us with an alternative and low-cost source of equity capital. We expect the alternative, low-cost capital will allow Williams Partners to compete with other MLPs when pursuing acquisition opportunities of gathering and processing assets.
Power.Gas Marketing Services. In our PowerGas Marketing Services segment, we compete directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities, and natural gas producers. We also compete with brokerage houses, energy hedge funds and other energy-based companies offering similar services.
EMPLOYEES
At February 1, 2007,2009, we had approximately 4,3134,704 full-time employees including 972924 at the corporate level, 584798 at Exploration & Production, 1,6941,726 at Gas Pipeline, 9281,232 at Midstream Gas & Liquids, and 13524 at Power.Gas Marketing Services. None of our employees are represented by unions or covered by collective bargaining agreements.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
See Note 1718 of our Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to the United States and all foreign countries. Also see Note 1718 of our Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, other than financial instruments, long-term customer relationships of a financial institution, mortgage and other servicing rights and deferred policy acquisition costs, located in the United States and all foreign countries.
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FORWARD-LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make thosethese forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report whichthat address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:
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| | • | amountsAmounts and nature of future capital expenditures; |
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| | • | expansionExpansion and growth of our business and operations; |
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| | • | business strategy;Financial condition and liquidity; |
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| | |
| | • | estimatesBusiness strategy; |
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| • | Estimates of proved gas and oil reserves; |
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| | • | reserveReserve potential; |
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| | • | developmentDevelopment drilling potential; |
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| | • | cashCash flow from operations or results of operations; |
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| | • | seasonalitySeasonality of certain business segments; |
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| | • | power, naturalNatural gas and natural gas liquidsNGL prices and demand. |
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document.report. Many of the factors that will determine these results are beyond our ability to control or project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:
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| | • | availabilityAvailability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and estimatingdeveloping future natural gas reserves), market demand, volatility of prices, and increasedthe availability and costs of capital; |
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| | • | inflation,Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions;conditions (including the recent economic slowdown and the disruption of global credit markets and the impact of these events on our customers and suppliers); |
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| | • | theThe strength and financial resources of our competitors; |
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| | • | developmentDevelopment of alternative energy sources; |
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| | • | theThe impact of operational and development hazards; |
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| | • | costsCosts of, changes in, or the results of laws, government regulations including(including proposed climate change legislation,legislation), environmental liabilities, litigation, and rate proceedings; |
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| • | Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans; |
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| | • | changesChanges in the current geopolitical situation; |
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| | • | risksRisks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and our lackthe availability and cost of investment grade credit ratings;credit; |
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| | • | riskRisks associated with future weather conditionsconditions; |
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| • | Acts of terrorism and acts of terrorism. |
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| • | Additional risks described in our filings with the SEC. |
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in additionsaddition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors includeare described in the following:following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.
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Risks Inherent to our Industry and Business
The long-term financial condition of our natural gas transmissiontransportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access, demand for those supplies in our traditional markets, and the prices of and market demand for natural gas.
The development of the additional natural gas reserves that are essential for our gas transmissiontransportation and midstream businesses to thrive requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline systems. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transmissiontransportation and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transmissiontransportation and processing facilities.
Production from existing wells and natural gas supply basins with access to our pipeline will also naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on our pipeline and cash flows associated with the transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas. In addition, if natural gas prices in some cases,the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply areas, or if natural gas supplies are diverted to
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serve other markets, the overall volume of natural gas transported and stored on our system would decline, which could have a material adverse effect on our business, financial condition and results of operations. In addition, new LNG import facilities built near our markets could result in less demand for our gathering and transmissiontransportation facilities.
Significant prolonged changes in natural gas prices could affect supply and demand and cause a termination of our transportation and storage contracts or a reduction in throughput on our system.
Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our Gas Pipelines’ systems. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on our Gas Pipelines’ systems. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Significant capital expenditures are required to replace our reserves.
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and debt and equity issuances. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt, issue debt or equity securities or access other methods of financing on an economic basis to meet our capital expenditure budget. As a result, our capital expenditure plans may have to be adjusted.
Failure to replace reserves may negatively affect our business.
The growth of our Exploration & Production business depends upon our ability to find, develop or acquire additional natural gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may not be able to find, develop or acquire additional reserves on an economic basis. If natural gas prices increase, our costs for additional reserves would also increase, conversely if natural gas prices decrease, it could make it more difficult to fund the replacement of our reserves.
Exploration and development drilling may not result in commercially productive reserves.
Our past success rate for drilling projects should not be considered a predictor of future commercial success. We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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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; |
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| • | Unexpected drilling conditions or problems; |
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| • | Regulations and regulatory approvals; |
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| • | Changes or anticipated changes in energy prices; and |
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| • | Compliance with environmental and other governmental requirements. |
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Estimating reserves and future net revenues involves uncertainties. Negative revisions to reserve estimates, and oil and gas price declinesprices or assumptions as to future natural gas prices may lead to decreased earnings, losses or impairment of oil and gas assets.assets, including related goodwill.
Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Reserves that are “proved reserves” are those estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions, but should not be considered as a guarantee of results for future drilling projects.
The process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this report represent estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct over time.correct.
Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. LowerChanges to oil and gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.
If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. TheThese revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also be sufficient to trigger impairment losses on certain properties which would result in a further non-cash charge to earnings. The revisions could also possibly affect the evaluation of Exploration & Production’s goodwill for impairment purposes. At December 31, 2008, we had approximately $1 billion of goodwill on our balance sheet.
Our past success rate for drilling projects and the historic performanceCertain of our exploration and production business is no predictor of future performance.services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
Our past successnatural gas transportation and midstream businesses provide some services pursuant to long-term, fixed price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services provided by our interstate gas pipelines are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for drilling projects in 2006 shouldthat service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be considered a predictor of future performance.produced by inflation or other factors relating to the specific facilities being used to perform the services.
PerformanceWe depend on certain key customers for a significant portion of our exploration and productionrevenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.
Our Gas Pipelines rely on a limited number of customers for a significant portion of their revenues. The loss of even a portion of our contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, is affected in part by factors beyond our control (any of which could cause thefinancial condition, results of this business to decrease materially), such as:operations and cash flows.
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| • | regulations and regulatory approvals; |
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| • | availability of capital for drilling projects which may be affected by other risk factors discussed in this report; |
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| • | cost-effective availability of drilling rigs and necessary equipment; |
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally our customers are rated investment grade, are otherwise considered credit worthy, are required to make pre-payments, or provide security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. While
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we monitor these situations carefully and attempt to take appropriate measures to protect ourselves, it is possible that we may have to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our operating results and financial condition.
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| • | availability of skilled labor; |
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| • | availability of cost-effective transportation for products; |
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| • | market risks (including price risks and competition) discussed in this report. |
The failure of new sources of natural gas production or liquid natural gas (LNG) import terminals to be successfully developed in North America could increase natural gas prices and reduce the demand for our services.
New sources of natural gas production in the United States and Canada, particularly in areas of shale development are expected to become an increasingly significant component of future natural gas supplies in North America. Additionally, increases in LNG supplies are expected to be imported through new LNG import terminals, particularly in the Gulf Coast region. If these additional sources of supply are not developed, natural gas prices could increase and cause consumers of natural gas to turn to alternative energy sources, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our drilling, production, gathering, processing, storage and transporting activities involve numerous risks that might result in accidents, and other operating risks and hazards.
Our operations are subject to all the risks and hazards typically associated with the development and exploration for, and the production and transportation of oil and gas. These operating risks include, but are not limited to:
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| | • | Fires, blowouts, cratering and explosions; |
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| | • | uncontrollable flowsUncontrollable releases of oil, natural gas or well fluids; |
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| | • | fires; |
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| • | formations with abnormal pressures; |
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| • | pollutionPollution and other environmental risks; |
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| | • | natural disasters.Natural disasters; |
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| • | Aging infrastructure; |
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| • | Damage inadvertently caused by third party activity, such as operation of construction equipment; and |
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| • | Terrorist attacks or threatened attacks on our facilities or those of other energy companies. |
In addition, there are inherent in our gas gathering, processing and transporting properties a variety of hazards and operating risks, such as leaks, spills, explosions and mechanical problems that could cause substantial financial losses. In addition, theseThese risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our pipelines in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of our pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could materially impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations.operations and cash flows.
CostsWe do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the ability of environmental liabilities and complying with existing and future environmental regulations could exceedthe insurers we do use to satisfy our current expectations.claims.
Our operations are subject to extensive environmental regulation pursuant to a variety of federal, provincial, state and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, extraction, transportation, treatment and disposal of hazardous substances and wastes, in connection with spills, releases and emissions of various substances into the environment, and in connection with the operation, maintenance, abandonment and reclamation of our facilities.
Compliance with environmental laws requires significant expenditures, including for clean up costs and damages arising out of contaminated properties. In addition, the possible failure to comply with environmental laws and regulations might result in the imposition of fines and penalties. We are generally responsible fornot fully insured against all liabilities associated with therisks inherent to our business, including environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown.accidents that might occur. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. Although we do not expect thatmaintain business interruption insurance in the coststype and amount to cover all possible risks of complyingloss. We currently maintain excess liability insurance with current environmental laws will have a material adverse effect onlimits of $610 million per occurrence and in the
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aggregate annually and a deductible of $2 million per occurrence. This insurance covers us and our financial conditionaffiliates for legal and contractual liabilities arising out of bodily injury, personal injury or resultsproperty damage, including resulting loss of operations, no assurance can be givenuse to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations. Pollution liability coverage excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that the costsresult in acidic deposition, and testing, monitoring,clean-up, containment, treatment or removal of complying with environmental lawspollutants from property owned, occupied by, rented to, used by or in the future will not have such an effect.care, custody or control of us or our affiliates.
We make assumptionsdo not insure onshore underground pipelines for physical damage, except at river crossings and develop expectations about possible expenditures relatedat certain locations such as compressor stations. We maintain coverage of $300 million per occurrence for physical damage to environmental conditions based on current lawsonshore assets and regulationsresulting business interruption caused by terrorist acts. We also maintain coverage of $100 million per occurrence for physical damage to offshore assets caused by terrorist acts, except for our Devils Tower spar where we maintain terrorism limits of $300 million per occurrence for property damage and current interpretations$105 million per occurrence for resulting business interruption. Also, all of those lawsour insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptionsfinancial condition. We may change. Our regulatory rate structure and our contracts with customers might not necessarily allow us to recover capital costs we incur to comply with the new environmental regulations. Also, we might not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and hurricanes Katrina, Rita, Gustav and Ike have impacted the availability of certain types of coverage at reasonable rates, and we may elect to self insure a portion of our asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or maintain from timetypes of insurance we would otherwise have obtained prior to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvalsthese market changes or ifthat the insurance coverage we do obtain will not contain large deductibles or fail to obtaincover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and comply with them, the operationcash flows.
In addition, certain insurance companies that provide coverage to us, including American International Group, Inc., have experienced negative developments that could impair their ability to pay any of our facilitiespotential claims. As a result, we could be prevented or becomeexposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.
Execution of our capital projects subjects us to construction risks, increases in labor and materials costs and other risks that may adversely affect financial results.
A significant portion of our growth in the gas pipeline and midstream business areas is accomplished through the construction of new pipelines, processing and storage facilities, as well as the expansion of existing facilities. Construction of these facilities is subject to additionalvarious regulatory, development and operational risks, including:
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| • | The ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; |
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| • | The availability of skilled labor, equipment, and materials to complete expansion projects; |
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| • | 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; |
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| • | Impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; |
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| • | 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 |
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| • | The ability to access capital markets to fund construction projects. |
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect results of operations, financial position or cash flows.
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Our costs resultingand funding obligations for our defined benefit pension plans and costs for our other post-retirement benefit plans are affected by factors beyond our control.
We have defined benefit pension plans covering substantially all of our U.S. employees and other post-retirement benefit plans covering certain eligible participants. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors we control, including changes to pension plan benefits as well as factors outside of our control, such as asset returns, interest rates and changes in potentially materialpension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse consequences toeffect on our financial condition. The amount of expenses recorded for our defined benefit pension plans and other post-retirement benefit plans is also dependent on changes in several factors, including market interest rates and the returns on plan assets. Significant changes in any of these factors may adversely impact our future results of operations.
Our operating results for certain segmentsTwo of our subsidiaries act as the respective general partners of two different publicly-traded limited partnerships, Williams Partners L.P. and Williams Pipeline Partners L.P. As such, those subsidiaries’ operations may involve a greater risk of liability than ordinary business might fluctuate on a seasonal and quarterly basis.operations.
Revenues from certain segmentsOne of our subsidiaries acts as the general partner of WPZ and another subsidiary of ours acts as the general partner of WMZ. Each of these subsidiaries that act as the general partner of a publicly-traded limited partnership may be deemed to have undertaken fiduciary obligations with respect to the limited partnership of which it serves as the general partner and to the limited partners of such limited partnership. Activities determined to involve fiduciary obligations to other persons or entities typically involve a higher standard of conduct than ordinary business including gas transmissionoperations and the saletherefore may involve a greater risk of electric power, can have seasonal characteristics. In many partsliability, particularly when a conflict of interests is found to exist. Our control of the country, demandgeneral partners of two different publicly traded partnerships may increase the possibility of claims of breach of fiduciary duties, including claims brought due to conflicts of interest (including conflicts of interest that may arise (i) between the two publicly-traded partnerships as well as (ii) between a publicly-traded partnership, on the one hand, and its general partner and that general partner’s affiliates, including us, on the other hand). Any liability resulting from such claims could be material.
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms, and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (FASB) or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity.
Our risk measurement and hedging activities might not be effective and could increase the volatility of our results.
Although we have systems in place that use various methodologies to quantify commodity price risk associated with our businesses, these systems might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified.
In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within
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guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under SFAS No. 133, “Accounting for power peaksDerivative Instruments and Hedging Activities,” (SFAS 133) to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under Statement of Financial Accounting Standards (SFAS) 133, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to the Company has occurred during the summer months, withapplicable period.
The impact of changes in market prices also peaking at that time. In other areas, demand for power peaks during the winter. In addition, demand for natural gas and other fuels peaks duringon the winter. As a result,average gas prices received by us may be reduced based on the level of our overall operating results inhedging strategies. These hedging arrangements may limit our potential gains if the future might fluctuate substantially on a seasonal basis. Demandmarket prices for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our power sale agreements and natural gas transmission arrangements relativewere to demand created by unusual weather patterns. Additionally, changes inrise substantially over the price established by the hedge. In addition, our hedging arrangements expose us to the risk of natural gas could benefit one of our business units, but disadvantage another. For example, our Exploration & Production business may benefit from higher natural gas prices, and Power, which uses gas as a fuel source, may not.financial loss in certain circumstances, including instances in which:
Risks Related to the Current Geopolitical Situation
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| • | Production is less than expected; |
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| • | The hedging instrument is not perfectly effective in mitigating the risk being hedged; and |
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| • | The counterparties to our hedging arrangements fail to honor their financial commitments. |
Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.
We currently own and might acquireand/or dispose of material energy-related investments and projects outside the United States. The economic and political conditions in certain countries where we have interests or in which we might explore development, acquisition or investment opportunities present risks of delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain non-recourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments. Recent events in certain South American countries, particularly the proposedcontinued threat of nationalization of certain energy-related assets in Venezuela, could have a material negative impact on our results of operations. We may not receive adequate compensation, or any compensation, if our assets in Venezuela are nationalized.
Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. Foreign currency risk can also arise when the revenues received by our foreign subsidiaries areWe may or may not in U.S. dollars. In such cases, a strengthening of the U.S. dollar or a weakening of the foreign currency could reduce the amount of
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cash and income we receive from these foreign subsidiaries. We have put contracts in place designed to mitigate our most significant foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.
Our operating results for certain segments of our business might fluctuate on a seasonal and quarterly basis.
Revenues from certain segments of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary
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significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns. Additionally, changes in the price of natural gas could benefit one of our business units, but disadvantage another. For example, our Exploration & Production business may benefit from higher natural gas prices, and Midstream, which uses gas as a feedstock, may not.
Risks Related to Strategy and Financing
Our debt agreements impose restrictions on us that may adversely affect our ability to operate our business.
Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, repurchase equity and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.
Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.
Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Our lackEvents in the global credit markets created a shortage in the availability of investment gradecredit and have led to credit market volatility.
In 2008, global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. While we cannot predict the occurrence of future disruptions or the duration of the current volatility in the credit markets, we believe cash on hand and cash provided by operating activities, as well as availability under our existing financing agreements will provide us with adequate liquidity. However, our ability to borrow under our existing financing agreements, including our bank credit facilities, could be negatively impacted if one or more of our lenders fail to honor its contractual obligation to lend to us. Continuing volatility or additional disruptions, including the bankruptcy or restructuring of certain financial institutions, may adversely affect the availability of credit already arranged and the availability and cost of credit in the future.
The continuation of recent economic conditions, including disruptions in the global credit markets, could adversely affect our results of operations.
The slowdown in the economy and the significant disruptions and volatility in global credit markets have the potential to negatively impact our businesses in many ways. Included among these potential negative impacts are reduced demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings increases(either due to tighter rating standards or the negative impacts described above), which could result in reducing our access to credit markets, raising the cost of such access or requiring us to provide additional collateral to our counterparties.
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A downgrade of our current credit ratings could impact our liquidity, access to capital and our costs of doing business, in certain ways and attainment of an investment grade ratingmaintaining current credit ratings is within the control of independent third parties.
Because we do not have an investment grade credit rating, our transactions in each of our businesses require greater credit assurances, both to be given from, and received by, us to satisfy credit support requirements. In addition, we are more vulnerable to the impact of market disruptions or a furtherA downgrade of our credit rating that might further increase our cost of borrowing or further impairand would require us to post additional collateral with third parties, negatively impacting our available liquidity. Our ability to access capital markets.markets would also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:
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| | • | economicEconomic downturns; |
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| | • | deterioratingDeteriorating capital market conditions generally;conditions; |
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| | • | decliningDeclining market prices for electricitynatural gas, natural gas liquids and natural gas;other commodities; |
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| | • | terroristTerrorist attacks or threatened attacks on our facilities or those of other energy companies; and |
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| | • | theThe overall health of the energy industry, including the bankruptcy or insolvency of other companies. |
Credit rating agencies perform independent analysis when assigning credit ratings. Given the significant changes in capital marketsThe analysis includes a number of criteria including, but not limited to, business composition, market and the energy industry over the last few years, creditoperational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for attaining investment gradeindustry sectors and various debt ratings and may make changes to those criteria from time to time. Our goal iscorporate family credit rating and the credit ratings of Transco and Northwest Pipeline were raised to attain investment grade ratios. However, there is no guaranteein 2007 by Standard & Poor’s, Moody’s Corporation, and Fitch Ratings, Ltd., and our senior unsecured debt ratings were raised to investment grade by Moody’s and Fitch. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.
Long-term power generation purchase contracts without corresponding long-term purchase sale contracts might expose us to fluctuations in the wholesale power markets and negatively affectratios or that our results of operations.
We have entered into agreements with certain power generation facilities to purchase all or a substantial portion of their generation capacity. These facilities operate as “merchant” facilities, many without corresponding long-term power sales agreements, and therefore are exposed to market fluctuations. Without the benefit of such
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long-term power sales agreements, we cannot be sure that wesenior unsecured debt rating will be ableraised to sell any orinvestment grade by all of the power generated by these facilities at commercially attractive rates or that these power generation relationships will be profitable.
We sell all or a portion of the energy, capacity and other products from certain generation facilities to wholesale power markets, including energy markets operated by independent system operators, or ISOs, or regional transmission organizations, or RTOs, as well as wholesale purchasers. We are not subject to traditional cost-based regulation, therefore we sell electric generation capacity, power and ancillary services to wholesale purchasers at prices determined by the market. As a result, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations depend upon current and forward market prices for power.credit rating agencies.
Prices for electricity, natural gas liquids, natural gas and other commodities are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses.
Our revenues, operating results, future rate of growth and the value of certain segments of our power and gas businesses depend primarily upon the prices we receive for electricity, natural gas liquids,NGLs, natural gas, or other commodities, and the differences between prices of these commodities. Price volatility can impact both the amount we receive for our products and services and the volume of products and services we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In particular, market prices for power, generation capacity and ancillary services tend to fluctuate substantially. Unlike other commodities, electricity can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, market prices for electricity are subject to significant volatility from supply and demand imbalances, especially in the day-ahead and spot markets.
The markets for electricity,NGLs, natural gas liquids, and natural gasother commodities are likely to continue to be volatile. Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including:
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| | • | worldwideWorldwide and domestic supplies of and demand for electricity, natural gas, NGLs, petroleum, and related commodities; |
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| | • | turmoilTurmoil in the Middle East and other producing regions; |
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| | • | terroristThe activities of the Organization of Petroleum Exporting Countries; |
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| • | Terrorist attacks on production or transportation assets; |
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| | • | weatherWeather conditions; |
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| | • | theThe level of consumer demand; |
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| | • | the development of federal and state power markets, including actions of ISOs and RTOs; |
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| • | theThe price and availability of other types of fuels; |
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| | • | theThe availability of pipeline capacity; |
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| | • | supplySupply disruptions, including plant outages and transmissiontransportation disruptions; |
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| | • | theThe price and level of foreign imports; |
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| | • | domesticDomestic and foreign governmental regulations and taxes; |
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| | • | volatilityVolatility in the natural gas markets; |
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| | • | theThe overall economic environment; |
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| | • | theThe credit of participants in the markets where products are bought and sold.sold; and |
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| • | The adoption of regulations or legislation relating to climate change. |
We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.
Our portfolio of derivative and other energy contracts consistsmay consist of wholesale contracts to buy and sell commodities, including contracts for electricity, natural gas, natural gas liquidsNGLs and other commodities that are
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settled by the delivery of the commodity or cash throughout the United States. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our businesses, we often extend credit to our counterparties. Despite performing credit analysis prior to extending credit, we are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a financing transaction fails to perform and any collateral that secures our counterparty’s obligation is inadequate, we will suffer a loss. A general downturn in the economy and tightening of global credit markets could cause more of our counterparties to fail to perform than we have expected.
If we are unable to perform under our energy agreements, we could be required to pay damages. These damages generally would be based on the difference between the market price to acquire replacement energy or energy services and the relevant contract price. Depending on price volatility in the wholesale energy markets, such damages could be significant.
Risks Related to Regulations that Affect our Industry
Our natural gas sales, transmission, and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our results of operations.
Our interstate natural gas sales, transmission,transportation, and storage operations conducted through our Gas Pipelines business are subject to the FERC’s rules and regulations in accordance with the Natural Gas Act of 1938NGA and the Natural Gas Policy Act of 1978. The FERC’s regulatory authority extends to:
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| | • | transportationTransportation and sale for resale of natural gas in interstate commerce; |
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| | • | ratesRates, operating terms and charges;conditions of service, including initiation and discontinuation of services; |
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| | • | construction; |
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| • | acquisition, extension or abandonmentCertification and construction of services ornew facilities; |
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| | • | accountsAcquisition, extension, disposition or abandonment of facilities; |
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| • | Accounts and records; |
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| | • | depreciationDepreciation and amortization policies; |
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| | • | operating termsRelationships with marketing functions within Williams involved in certain aspects of the natural gas business; and conditions |
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| • | Market manipulation in connection with interstate sales, purchases or transportation of service.natural gas. |
Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business. Regulatory decisions could also affect our costs for compression, processing and dehydration of natural gas, which could have a negative effect on our results of operations.
The FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing
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competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmissiontransportation provider based on considerations other than location.
Costs of environmental liabilities and complying with existing and future environmental regulations, including those related to greenhouse gas emissions, could exceed our current expectations.
Our operations are subject to extensive environmental regulation pursuant to a variety of federal, provincial, state and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, extraction, transportation, treatment and disposal of hazardous substances and wastes, in connection with spills, releases and emissions of various substances into the environment, and in connection with the operation, maintenance, abandonment and reclamation of our facilities.
Compliance with environmental laws requires significant expenditures, including for clean up costs and damages arising out of contaminated properties. In addition, the possible failure to comply with environmental laws and regulations might result in the imposition of fines and penalties. We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our financial condition or results of operations, no assurance can be given that the costs of complying with environmental laws in the future will not have such an effect.
Legislative and regulatory responses related to climate change create financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. Increased public awareness and concern may result in more state, regionaland/or federal requirements to reduce or mitigate the emission of greenhouse gases. Numerous states have announced or adopted programs to stabilize and reduce greenhouse gases and similar federal legislation has been introduced in both houses of Congress. Our pipeline, exploration and production and gas processing facilities may be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws. If we are unable to recover or pass through all costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively impact our cost of and access to capital.
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change. Our regulatory rate structure and our contracts with customers might not necessarily allow us to recover capital costs we incur to comply with the new environmental regulations. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our results of operations.
Competition in the markets in which we operate may adversely affect our results of operations.
We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Other companies with which we compete may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their facilities than we can. In addition, current or potential competitors may make strategic acquisitions or have greater
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financial resources than we do, which could affect our ability to make investments or acquisitions. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our businesses and results of operations.
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Expiration of firmWe may not be able to maintain or replace expiring natural gas transportation agreements.and storage contracts at favorable rates or on a long-term basis.
A substantial portionOur primary exposure to market risk for our Gas Pipelines occurs at the time the terms of the operating revenuestheir existing transportation and storage contracts expire and are subject to termination. Although none of our Gas PipelinesPipelines’ material contracts are generated through firm transportation agreements that expire periodically and must be renegotiated and extended or replaced. We cannot give any assurance as to whether anyterminable in 2009, upon expiration of these agreements will be extended or replaced or that the terms we may not be able to extend contracts with existing customers to obtain replacement contracts at favorable rates or on a long-term basis. The extension or replacement of any renegotiated agreements will be as favorable as the existing agreements. Upon the expirationcontracts depends on a number of these agreements, should customers turn back or substantially reduce their commitments, we could experience a negative effectfactors beyond our control, including:
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| • | The level of existing and new competition to deliver natural gas to our markets; |
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| • | The growth in demand for natural gas in our markets; |
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| • | Whether the market will continue to support long-term firm contracts; |
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| • | Whether our business strategy continues to be successful; |
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| • | The level of competition for natural gas supplies in the production basins serving us; and |
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| • | The effects of state regulation on customer contracting practices. |
Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations.operations and cash flows.
OurIf third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues might decrease if we are unable to gain adequate, reliable and affordable access to transmission and distribution assets due to regulation by the FERC and regional authorities of wholesale market transactions for electricity and natural gas.could be adversely affected.
We depend on transmission and distribution facilities owned and operated by utilitiesupon third-party pipelines and other energy companiesfacilities that provide delivery options to deliver the electricity and from our natural gas pipeline and storage facilities. Because we buy and sell indo not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become unavailable due to repairs, damage to the wholesale market. If transmission is disrupted, iffacility, lack of capacity, is inadequate, or ifincreased credit requirements or rates ofcharged by such utilitiespipelines or energy companies are increased,facilities or for any other reason, our ability to selloperate efficiently and deliver products mightcontinue shipping natural gas to end-use markets could be hindered. The FERC has issued power transmissionrestricted, thereby reducing our revenues. Further, although there are laws and regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions, for electricity, some companies may fail to provide fair and equal access to their transmissiontransportation systems or may not provide sufficient transmissiontransportation capacity to enablefor other companies to transmit electric power.
In addition, the independent system operators who oversee the transmission systemsmarket participants. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in regional power markets, such as California,volumes transported on our pipeline or stored at our facilities could have in the past been authorized to impose, and might continue to impose, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms might adversely impact the profitability ofa material adverse effect on our wholesale power marketing and trading. Given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by regulators, ISOs, RTOs or other marker operators, we can offer no assurance that we will be able to operate profitably in all wholesale power markets or that ourbusiness, financial condition, results of operations will not be adversely affected by the actions of these parties.and cash flows.
Our businesses are subject to complex government regulations. The operation of our businesses might be adversely affected by changes in these regulations or in their interpretation or implementation.implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us, our facilities or our facilities,customers, and future changes in laws and regulations might have a detrimental effect on our business. OverSpecifically, the past few years, certain restructured energy markets have experienced supply problemsColorado Oil & Gas Conservation Commission has enacted new rules effective in April 2009 which will increase our costs of permitting and price volatility. In some of these markets, proposals have been made by governmental agenciesenvironmental compliance and other interested parties to re-regulate areas of these markets which have previously been deregulated. Various forms of market controls and limitations including price caps and bid caps have already been implemented and new controls and market restructuring proposals are in various stages of development, consideration and implementation. We cannot assure you that changes in market structure and regulation will not adverselymay affect our businessability to meet our anticipated drilling schedule and therefore may have a material effect on our results of operations. We also cannot assure you that other proposals to re-regulate will not be made or that legislative or other attention to these restructured energy markets will not cause the deregulation process to be delayed or reversed or otherwise adversely affect our business and results of operations.
The outcome of pending rate cases to set the rates we can charge customers on certain of our pipelines might result in rates that do not provide an adequate return on the capital we have invested in those pipelines.
We have filed rate cases with the FERC to request changes to the rates we charge on Northwest Pipeline and Transco. Although we have a pending settlement of our Northwest Pipeline rate case, we must still obtain approval of the settlement. Therefore, the outcome of both rate cases remains uncertain. There is a risk that rates set by the FERC will be lower than is necessary to provide us with an adequate return on the capital we have invested in these
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assets. There is also the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.
Legal and regulatory proceedings and investigations relating to the energy industry and capital markets have adversely affected our business and may continue to do so.
Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations
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and court proceedings in which we are a named defendant. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations and court proceedings are ongoing and continue to adversely affect our business as a whole. We might see these adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us arising out of our ongoing and discontinued operations including environmental matters, disputes over gas measurement, royalty payments, shareholder class action suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
Risks Related to Accounting Standards
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
Accounting irregularities discovered in the past few years across various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically.
In addition, the Financial Accounting Standards Board (FASB) or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity.
Risks Related to Market Volatility and Risk Measurement and Hedging Activities
Our risk measurement and hedging activities might not be effective and could increase the volatility of our results.
We manage our commodity price risk for our unregulated businesses as a whole. Although we have systems in place that use various methodologies to quantify risk, these systems might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified.
In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered into contracts to hedge certain risks associated with our assets and operations, including our long-term tolling agreements. In these hedging activities, we have used fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in theover-the-counter markets or on exchanges, as well as long-term structured transactions when feasible. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective
29
in hedging commodity price volatility risks would not hedge the tolling contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results and could also result in reported cash flows in future years not reflecting the realization of increases in the fair value of derivatives that have already been reflected in our income statements. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify as hedges under SFAS 133, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to the Company has occurred during the applicable period. During the period from 2002 to 2004 when our Power business was for sale, most changes in the fair value of derivatives used in our Power business were reflected in our earnings as net forward unrealizedmark-to-market gains. As a result, in future periods if the cash benefits associated with those hedges are actually realized, the value will not be reflected as earnings on our income statement, having already been recorded as earnings in prior years.
The impact of changes in market prices for natural gas on the average gas prices received by us may be reduced based on the level of our hedging strategies. These hedging arrangements may limit our potential gains if the market prices for natural gas were to rise substantially over the price established by the hedge. In addition, our hedging arrangements expose us to the risk of financial loss in certain circumstances, including instances in which:
| | |
| • | production is less than expected; |
|
| • | a change in the difference between published price indexes established by pipelines in which our hedged production is delivered and the reference price established in the hedging arrangements is such that we are required to make payments to our counterparties; |
|
| • | the counterparties to our hedging arrangements fail to honor their financial commitments. |
Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology
Institutional knowledge residing with current employees nearing retirement eligibility might not be adequately preserved.
In certain segments of our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.
Failure of theor disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
Some studies indicate a high failure rate of outsourcing relationships. Although we have taken steps to build a cooperative and mutually beneficial relationship with our outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business.
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Our ability The expiration of such agreements or the transition of services between providers could lead to receive services from outsourcing provider locations outsidesimilar losses of the United States might be impacted by cultural differences, political instability,institutional knowledge or unanticipated regulatory requirements in jurisdictions outside the United States.disruptions.
Certain of our accounting, information technology, application development, and helpdeskhelp desk services are currently provided by an outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which our outsourcing providers may provide services to us present similar risks of business operations located outside of the United States previously discussed, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.
Our current information technology infrastructure is aging and may adversely affect our ability to conduct our business.
Limited capital spending for information technology infrastructure during2001-2003 resulted in an aging server environment that may be less efficient, may require more personnel and capital resources to maintain and upgrade than more current systems, and may not be adequate for our current business needs. While efforts are ongoing to update the environment, the current age and condition of equipment could result in loss of internal and external communications, loss of data, inability to access data when needed, excessive software downtime (including downtime for critical software applications), and other disruptions that could have a material adverse impact on our business and results of operations.
Risks Related to Weather, other Natural Phenomena and Business Disruption
Our assets and operations can be adversely affected by weather and other natural phenomena.
Our assets and operations, including those located offshore, can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we may be unable to obtain insurance on commercially reasonable terms, if at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.
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In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading to either increased investment or decreased revenues.
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to generate, produce, process, transmit, transport or distribute electricity, natural gas, or natural gas liquids.liquids or other commodities. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.
| |
| Item 1B. | Unresolved Staff Comments |
None.
We own property in 3231 states plus the District of Columbia in the United States and in Argentina, Canada and Venezuela.
Power’sGas Marketing’s primary assets are its term contracts, related systems and technological support. In addition, affiliates of Power own the Hazelton and Milagro generating facilities described above. In our Gas Pipeline and Midstream segments, we generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant torights-of-way, easements, permits, licenses or consents on and across properties owned by others. In our Exploration & Production segment, the majority of our ownership interest in exploration and production properties is held as working interests in oil and gas leaseholds.
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| |
| Item 3. | Legal Proceedings |
The information called for by this item is provided in Note 1516 of the Notes to Consolidated Financial Statements of this report, which information is incorporated by reference into this item.
| |
| Item 4. | Submission of Matters to a Vote of Security Holders |
None.
Executive Officers of the Registrant
The name, age, period of service, and title of each of our executive officers as of February 22, 2007,1, 2009, are listed below.
| | |
| Alan S. Armstrong | | Senior Vice President, Midstream |
| | Age: 4446 |
|
| | 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 50Age: 52 |
|
| | Position held since December 2002. |
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| | |
| | 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. since June 1997. NRG Energy, Inc. filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003. |
| |
| Donald R. Chappel | | Senior Vice President and Chief Financial Officer |
| | Age: 5557 |
|
| | Position held since April 2003. |
| |
| | Prior to joining us, Mr. Chappel during 2000 founded and served as chief executive officer of a development business in Chicago, Illinois through April 2003, when he joined us. Mr. Chappel joined Waste Management, Inc. in 1987 and held various financial, administrative and operational leadership positions, including twice servingpositions. Mr. Chappel serves as chief financial officer, during 1997a director of Williams Partners GP LLC, the general partner of Williams Partners L.P., and 1998as 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 most recently during 1999 through February 2000.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: 4749 |
|
| | Position held since December 1998. |
| |
| | Mr. Hill was vice presidentVice President of the exploration and production unitExploration & Production business from 1993 to 1998 as well as Senior Vice President Petroleum Services from 1998 to 2003. |
|
William E. Hobbs | | Senior Vice President, Power |
| | Age: 47 |
| | Position held since October 2002. |
|
| | From February 2000 to October 2002, Mr. Hobbs was President and Chief Executive Officer of Williams Energy Marketing & Trading. From 1997 to February 2000, he servedHill serves as a Vice Presidentdirector of various Williams subsidiaries. |
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| | |
Michael P. Johnson, Sr. | | Senior Vice President and Chief Administrative Officer |
| | Age: 59 |
| | Position held since May 2004. |
|
| | Mr. Johnson was named our Senior Vice President of Human Resources and Administration in April 1999. Prior to joining us in December 1998, he held officer level positions, such as Vice President of Human Resources, Vice President for Corporate People Strategies, and Vice President Human Resource Services, for Amoco Corporation from 1991 to 1998.Apco Argentina Inc. |
| |
| Steven J. Malcolm | | Chairman of the Board, Chief Executive Officer and President |
| | Age: 5860 |
|
| | Position held since September 2001. |
| |
| | From May 2001 to September 2001, Mr. Malcolm was elected Chief Executive Officer of Williams in January 2002 and Chairman of the Board in May 2002. He was elected President and Chief Operating Officer in September 2001. Prior to that, he was our Executive Vice President from May 2001,of the Company. He was President and Chief Executive Officer of our subsidiary Williams Energy Services, LLC sincefrom December 1998 to May 2001 and the Senior Vice President and General Manager of our subsidiary, Williams Field Services Company sincefrom November 1994.1994 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: 5153 |
|
| | 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. |
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PART II
| |
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is listed on the New York Stock Exchange and NYSE Arca Equities Exchanges under the symbol “WMB.” At the close of business on February 22, 2007,19, 2009, we had approximately 11,87510,323 holders of record of our common stock. The high and low closing sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
Quarter | | High | | Low | | Dividend | | High | | Low | | Dividend | | | High | | Low | | Dividend | | High | | Low | | Dividend | |
| |
| 1st | | $ | 25.12 | | | $ | 19.49 | | | $ | .075 | | | $ | 19.29 | | | $ | 15.29 | | | $ | .05 | | | $ | 36.99 | | | $ | 30.96 | | | $ | .10 | | | $ | 28.94 | | | $ | 25.32 | | | $ | .09 | |
| 2nd | | $ | 23.36 | | | $ | 20.33 | | | $ | .09 | | | $ | 19.21 | | | $ | 16.29 | | | $ | .05 | | | $ | 40.31 | | | $ | 33.65 | | | $ | .11 | | | $ | 32.43 | | | $ | 28.20 | | | $ | .10 | |
| 3rd | | $ | 25.23 | | | $ | 22.51 | | | $ | .09 | | | $ | 25.05 | | | $ | 19.16 | | | $ | .075 | | | $ | 39.90 | | | $ | 21.85 | | | $ | .11 | | | $ | 34.72 | | | $ | 30.08 | | | $ | .10 | |
| 4th | | $ | 27.95 | | | $ | 22.95 | | | $ | .09 | | | $ | 25.40 | | | $ | 19.97 | | | $ | .075 | | | $ | 22.50 | | | $ | 12.13 | | | $ | .11 | | | $ | 37.16 | | | $ | 33.68 | | | $ | .10 | |
Some of our subsidiaries’ borrowing arrangements limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends. However, until January 20, 2005, the credit agreements underlying our two unsecured revolving credit facilities totaling $500 million prohibited us from paying quarterly cash dividends on our common stock in excess of $0.05 per share. On January 20, 2005, these facilities were terminated and replaced with two new facilities. As part of the transaction, the dividend restriction, along with most of the other restrictive covenants, was removed from the new credit agreements.
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Performance Graph
Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index and the Bloomberg U.S. Pipeline Index for the period of five fiscal years commencing January 1, 2002.2004. The Bloomberg U.S. Pipeline Index is composed of Crosstex Energy, Inc., El Paso Equitable Resources, Questar,Corporation, Enbridge Inc., Kinder Morgan TransCanada,Management, LLC, National Fuel Gas Company, Oneok, Inc., Promigas S.A. E.S.P., Spectra Energy EnbridgeCorp, TransCanada Corporation, and Williams.The Williams Companies, Inc. The graph below assumes an investment of $100 at the beginning of the period.
Cumulative Total Shareholder Return
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2001 | | | 2002 | | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2007 | | | 2008 |
| The Williams Companies, Inc. | | | | 100.0 | | | | | 11.1 | | | | | 40.6 | | | | | 67.7 | | | | | 97.5 | | | | | 111.5 | | | | | 100.0 | | | | | 166.9 | | | | | 240.2 | | | | | 274.7 | | | | | 380.9 | | | | | 156.8 | |
| S&P 500 Index | | | | 100.0 | | | | | 77.9 | | | | | 100.2 | | | | | 111.1 | | | | | 116.6 | | | | | 135.0 | | | | | 100.0 | | | | | 110.9 | | | | | 116.3 | | | | | 134.7 | | | | | 142.1 | | | | | 89.5 | |
| Bloomberg U.S. Pipelines Index | | | | 100.0 | | | | | 30.7 | | | | | 50.4 | | | | | 64.1 | | | | | 82.8 | | | | | 93.7 | | | | | 100.0 | | | | | 130.9 | | | | | 173.3 | | | | | 200.9 | | | | | 238.2 | | | | | 145.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
3536
| |
| Item 6. | Selected Financial Data |
The following financial data asat December 31, 2008 and 2007, and for each of the three years in the period ended December 31, 2008, should be read in conjunction with Part II, Item 7,Management’s Discussion and Analysis of Financial Condition and Results of Operationsand Part II, Item 8,Financial Statements and Supplementary Dataof thisForm 10-K. The following financial data at December 31, 2006 and 2005, and for the three years ended December 31, 2006, are an integral part of,2005 and 2004, should be read in conjunction with the consolidated financial statements and related notes. All other amounts haveinformation included in Exhibit 99.1 of ourForm 8-K as filed on October 12, 2007, except for the adjustments described in footnote (1) below. The following financial data at December 31, 2004, has been prepared from our financialaccounting records. Certain amounts below have been restated or reclassified. See Note 1 of Notes to Consolidated Financial Statements in Part II Item 8 for discussion of changes in 2006, 2005 and 2004. Information concerning significant trends in the financial condition and results of operations is contained inManagement’s Discussion & Analysis of Financial Condition and Results of Operationsof this report.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | | | 2008 | | 2007 | | 2006 | | 2005 | | 2004 | |
| | | (Millions, except per-share amounts) | | | (Millions, except per-share amounts) | |
| |
| Revenues(1) | | $ | 11,812.9 | | | $ | 12,583.6 | | | $ | 12,461.3 | | | $ | 16,651.0 | | | $ | 3,434.5 | | | $ | 12,352 | | | $ | 10,486 | | | $ | 9,299 | | | $ | 9,690 | | | $ | 8,343 | |
| Income (loss) from continuing operations(2) | | | 332.8 | | | | 317.4 | | | | 93.2 | | | | (57.5 | ) | | | (618.4 | ) | |
| Income from continuing operations(2) | | | | 1,334 | | | | 847 | | | | 347 | | | | 473 | | | | 149 | |
| Income (loss) from discontinued operations(3) | | | (24.3 | ) | | | (2.1 | ) | | | 70.5 | | | | 326.6 | | | | (136.3 | ) | | | 84 | | | | 143 | | | | (38 | ) | | | (157 | ) | | | 15 | |
| Cumulative effect of change in accounting principles(4) | | | — | | | | (1.7 | ) | | | — | | | | (761.3 | ) | | | — | | | | — | | | | — | | | | — | | | | (2 | ) | | | — | |
| Diluted earnings (loss) per common share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations | | | .55 | | | | .53 | | | | .18 | | | | (.17 | ) | | | (1.37 | ) | |
| Income from continuing operations | | | | 2.26 | | | | 1.40 | | | | .57 | | | | .79 | | | | .28 | |
| Income (loss) from discontinued operations | | | (.04 | ) | | | — | | | | .13 | | | | .63 | | | | (.26 | ) | | | .14 | | | | .23 | | | | (.06 | ) | | | (.26 | ) | | | .03 | |
| Cumulative effect of change in accounting principles | | | — | | | | — | | | | — | | | | (1.47 | ) | | | — | | |
| Total assets at December 31 | | | 25,402.4 | | | | 29,442.6 | | | | 23,993.0 | | | | 27,021.8 | | | | 34,988.5 | | | | 26,006 | | | | 25,061 | | | | 25,402 | | | | 29,443 | | | | 23,993 | |
| Short-term notes payable and long-term debt due within one year at December 31 | | | 392.1 | | | | 122.6 | | | | 250.1 | | | | 938.5 | | | | 2,077.1 | | | | 196 | | | | 143 | | | | 392 | | | | 123 | | | | 250 | |
| Long-term debt at December 31 | | | 7,622.0 | | | | 7,590.5 | | | | 7,711.9 | | | | 11,039.8 | | | | 11,075.7 | | | | 7,683 | | | | 7,757 | | | | 7,622 | | | | 7,591 | | | | 7,712 | |
| Stockholders’ equity at December 31 | | | 6,073.2 | | | | 5,427.5 | | | | 4,955.9 | | | | 4,102.1 | | | | 5,049.0 | | | | 8,440 | | | | 6,375 | | | | 6,073 | | | | 5,427 | | | | 4,956 | |
| Cash dividends per common share | | | .345 | | | | .25 | | | | .08 | | | | .04 | | | | .42 | | |
| Cash dividends declared per common share | | | | .43 | | | | .39 | | | | .345 | | | | .25 | | | | .08 | |
| | |
| (1) | | As partPrior period amounts reported for Exploration & Production have been adjusted to reflect the presentation of our adoption of Emerging Issues Task Force IssueNo. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” (EITF02-3), we concluded thatcertain revenues and costs of sales from nonderivative contracts and certain physically settled derivative contracts should generally be reported on a grossnet basis. Prior toThese adjustments reducedrevenuesand reducedcosts and operating expensesby the adoptionsame amount, with no net impact on January 1, 2003, these revenuessegment profit. The reductions were presented net of costs. As permitted by EITF02-3, prior year amounts have not been restated. Additionally,revenueswithin our Power segment$72 million in 2003 includes approximately $1172007, $77 million related to the correction of the accounting treatment previously applied to certain third-party derivative contracts during 2002in 2006, $91 million in 2005 and 2001.$65 million in 2004. |
| |
| (2) | | See Note 4 of Notes to Consolidated Financial Statements for discussion of asset sales, impairments, and other accruals in 2006,2008, 2007, and 2006. Income from continuing operations for 2005 includes an $82 million charge for litigation contingencies and 2004.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 2006, 20052008, 2007, and 20042006 income (loss) from discontinued operations. Results for the years 2003 and 2002 also include amounts related to theThe discontinued operations of certain gas processingresults for 2005 includes our former power business while 2004 includes the power business, the Canadian straddle plants, and natural gas liquid operations in Canada, a soda ash mining operation, our interestthe Alaska refining, retail, and investment in Williams Energy Partners, a bio-energy operation, certain natural gas production properties, Texas Gas Transmission Corporation, refining and marketing operations in the midsouth, retail travel centers in the midsouth, Central natural gas pipeline,Mid-Americapipeline Seminole pipeline and Kern River pipeline.operations. |
| |
| (4) | | The 2005cumulative effect of change in accounting principlesis due to the implementation of Financial Accounting Standards Board (FASB) Interpretation (FIN)No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations — an Interpretation of FASB Statement No. 143.” The 2003 cumulative effect of change in accounting principles includes a $762.5 million charge related to the adoption of EITF02-3, slightly offset by $1.2 million related to the adoption of Statement of Financial Accounting Standards (SFAS)statement No. 143 “Accounting for Asset Retirement Obligations.(SFAS No. 143).” The $762.5 million charge primarily consisted of the then fair value of power tolling, load serving, gas transportation and gas storage contracts. These contracts are not derivatives and, therefore, are no longer reported at fair value. |
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| |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
General
We are primarily a natural gas company, engaged in finding, producing, gathering, processing, and transporting natural gas. We also manage a wholesale power business. Our operations are located principally in the United States and are organized into the following reporting segments: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids (Midstream), and Power.Gas Marketing Services. (See Note 1 of Notes to Consolidated Financial Statements and Part I Item 1 for further discussion of reportingthese segments.)
Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, discussion and analysis of results of operations, and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II Item 8 of this document.
Overview of 20062008
Our plan for 20062008 was focused on continued disciplined growth. Objectives and highlights of this plan included:
| | | | |
| Objectives | | | Highlights |
Continuing to improve both EVA® and segment profit. | | | 20062008 segment profit increased $185.8of $2.9 billion, an increase of $749 million to $1,468.3 million, whichfrom 2007, contributed to improving our EVA®. |
Investing in our natural gas businesses in a way that improves EVA®, meets customer needs, and enhances our competitive position. | | | Total capital expenditures were approximately $2.5 billion, of which approximately $1.4 billion was invested in Exploration & Production. |
Continuing to increase natural gas production in a responsible and efficient manner.reserves. | | | We invested $2.5 billion in capital expenditures in Exploration & Production, increased itsincreasing average daily domestic production by approximately 21%20 percent over last year and also added 597while adding 602 billion cubic feet equivalent in net reserves. Total year-end 2008 proved domestic natural gas reserves during 2006. Additionally, we received 2006 industry awards including Hydrocarbon Producer of the Year and North America’s Best Field Rejuvenation. |
Accelerating additional asset transactions between us and Williams Partners L.P., our master limited partnership. | | | Williams Partners L.P. acquired 100are 4.3 trillion cubic feet equivalent, up 5 percent of Williams Four Corners LLC for a total of $1.583 billion.from year-end 2007 reserves. |
| Increasing the scale of our gathering and processing business in key growth basins. | | | We invested approximately $257$608 million in capital expenditures in Midstream, includingprimarily Deepwater Gulf expansion projects and completinggas-processing capacity in the expansion of our Opal gas processing facility.western United States. |
Filing new ratesContinue to enableinvest in expansion projects on our Gas Pipeline segment to create additional value.interstate natural gas pipelines. | | | NorthwestWe invested $306 million in capital expenditures in Gas Pipeline and Transco each filed a general rate case with the Federal Energy Regulatory Commission (FERC).
In January 2007, Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007. |
| | | |
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| | | |
Objectives | | | Highlights |
Executing power contracts that reduce risk while adding new business and strengthening future cash flow potential. | | | During 2006, Power completed several new power sales contracts that increase the value of the portfolio and provide additional cash-flow certainty in future periods. Additionally, in early 2007, Power executed power sales agreements in southern California through 2011.during 2008. |
| | | | |
Our 20062008income from continuing operationsincreased to $332.8 million,$1.3 billion, as compared to $317.4$847 million in 2005.2007. Ournet cash provided by operating activitieswas $1,889.6 millionalmost $3.4 billion in 20062008 compared to $1,449.9 million$2.2 billion in 2005. These comparative2007.
While these annual measures are favorable compared to the prior year, the overall trend of results reflectwas significantly different when considering the benefitfirst three quarters of strongthe year versus the last quarter. Through September 30, 2008, our Exploration & Production business benefited from increased levels of production and higher net realized average natural gas liquidprices, while our Midstream business realized higher margins partially offset with resolution of certain legacy litigation issues. In addition to achieving these results, the following represent significant actions or events that occurredfrom a favorable energy commodity price environment. However, energy commodity prices declined sharply during the year:last months of 2008, contributing to significantly lower fourth quarter operating results for these segments. The impact of the declining energy commodity prices on our consolidated results was partially mitigated by:
| | |
| • | 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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See additional discussion in Results of Operations.
RecentOther Significant 2008 Events
In June 2006, Williams Partners L.P. acquired 25.1 percentWe completed our stock repurchase program by reaching the $1 billion limit authorized by our Board of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. successfully closed a $150 million private debt offering of senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.
In December 2006, Northwest Pipeline completed and placed into service its capacity replacement project in the state of Washington. The project involved abandoning 268 miles of26-inch pipeline and replacing it with approximately 80 miles of36-inch pipeline constructed in four sections along the same pipeline corridor. Additionally, Northwest Pipeline modified five existing compressor stations and created additional net horsepower.
Northwest Pipeline and Transco have each filed a general rate case with the FERC. Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007. The new rates for Northwest Pipeline are effective in January 2007, subject to refund. The new rates for Transco are expected to be effective in March 2007, subject to refund.
In April 2006, Transco issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Transco completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.
In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.
In May 2006, we replaced our $1.275 billion secured revolving credit facility with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and financial covenants as the secured facility, but contains certain additional restrictions.Directors. (See Note 1112 of Notes to Consolidated Financial Statements.)
In May 2006, our BoardExploration & Production increased its positions by acquiring undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin and undeveloped leasehold acreage and producing properties in the Fort Worth basin. See additional discussion in Results of Directors approved a regular quarterly dividend of 9 cents per share of common stock, which reflects an increase of 20 percent compared with the 7.5 cents per share paid in each of the three prior quarters.Operations — Segments, Exploration & Production.
In June 2006, Northwest Pipeline issued $175We recognized pre-tax income of $183 million aggregate principal amount of 7 percent senior unsecured notes due 2016inincome from discontinued operationsrelated to certain institutional investors in a private debt placement. In October 2006, Northwest
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Pipeline completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.
In June 2006, we reached anagreement-in-principle to settleclass-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000, and July 22, 2002, for a total payment of $290 million to plaintiffs. We funded our $145 million portion of the settlement withcash-on-hand in November 2006, with the balance funded directly by our insurers. We recorded a pre-tax charge for approximately $161 million in second quarter 2006. This settlement did not have a material effect on our liquidity position.former Alaska operations. (See Note 152 of Notes to Consolidated Financial Statements.)
On July 31, 2006, and August 1, 2006, we received a verdict in civil litigationExploration & Production recognized pre-tax income of $148 million related to the sale of a contractual dispute surroundingright to a production payment on certain natural gas processing facilities known as Gulffuture international hydrocarbon production. See additional discussion in Results of Operations — Segments, Exploration & Production.
Williams Pipeline Partners L.P. completed its initial public offering. See additional discussion in Results of Operations — Segments, Gas Pipeline.
In September 2008, Hurricanes Gustav and Ike impacted our operations, primarily at Midstream. As a result, we estimate that our segment profit for 2008 was decreased by approximately $60 million to $85 million due to downtime and charges for repairs and property insurance deductibles. See additional discussion in Results of Operations — Segments, Gas Pipeline and Midstream Gas & Liquids. We recorded a pre-tax charge for approximately $88 million
The overall decline in second quarter 2006 related to this loss contingency.equity markets in 2008 negatively impacted our employee benefit plan assets and will significantly increase our net periodic benefit expense in future periods. (See Note 157 of Notes to Consolidated Financial Statements.)
Our property insurance coverage levels and premiums were revised during the second quarter of 2006. In general, our coverage levels have decreased while our premiums have increased. These changes reflect general trends in our industry due to hurricane-related damages in recent years.
In November 2005, we initiated an offer to convert our 5.5 percent junior subordinated convertible debentures into our common stock. In January 2006, we converted approximately $220.2 million of the debentures in exchange for 20.2 million shares of common stock, a $25.8 million cash premium, and $1.5 million of accrued interest.
Outlook for 20072009
OurWe expect the overall economic recession and related lower energy commodity price environment as well as the challenging financial markets to continue throughout the year. This is expected to result in sharply lower results of operations and cash flow from operations compared to 2008 levels and could also result in a further reduction in capital expenditures. The impacts could include the future nonperformance of counterparties or impairments of goodwill and long-lived assets. Considering this environment, our plan for 20072009 is built around the transition from significant growth to a focus on sustaining our current operations and reducing costs where appropriate. However, we believe we are well positioned to capture growth opportunities when commodity prices strengthen and as economic conditions improve. Although we expect a reduction in capital expenditures compared to the prior year, near-term investment in our businesses will remain significant and focused on continued disciplined growth. Objectivescompleting major projects, meeting legal, regulatory,and/or contractual commitments, and maintaining a reduced level of thisnatural gas production development.
We will continue to operate with a focus on EVA® and invest in our businesses in a way that meets customer needs and enhances our competitive position by:
| | |
| • | Continuing to invest our gathering and processing and interstate natural gas pipeline systems, primarily through the completion of projects currently underway; |
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| • | Continuing to invest in our natural gas production development, although at a lower level than in recent years; |
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| • | 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. |
Potential risksand/or obstacles that could impact the execution of our plan include:
| | |
| | • | Continue to improve both EVA® and segment profit. |
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| • | Invest in our natural gas businesses in a way that improves EVA®, meets customer needs, and enhances our competitive position. |
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| • | Continue to increase natural gas production and reserves. |
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| • | Increase the scale of our gathering and processing business in key growth basins. |
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| • | Successfully resolving the rate cases for both Northwest Pipeline and Transco. |
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| • | Execute power contracts that offset a significant percentage of our financial obligations associated with our tolling agreements.Lower than anticipated commodity prices; |
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Potential risksand/or obstacles that could prevent us from achieving these objectives include:
| | |
| • | Volatility of commodity prices; |
|
| | • | Lower than expected levels of cash flow from operations; |
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| • | Availability of capital; |
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| • | Counterparty credit and performance risk; |
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| | • | Decreased drilling success at Exploration & Production; |
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| | • | Decreased drilling success or abandonment of projects by third parties served by Midstream and Gas Pipeline; |
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| • | Additional general economic, financial markets, or industry downturn; |
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| • | Changes in the political and regulatory environments; |
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| • | Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 1516 of Notes to Consolidated Financial Statements); |
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| • | General economic and industry downturn.. |
We continue to address these risks through utilization of commodity hedging strategies, focused efforts to resolve regulatory issues and litigation claims, disciplined investment strategies, and maintaining our desired level of at least $1 billion in liquidity from cash and cash equivalents and unused revolving credit facilities. In addition, we utilize master netting agreements and collateral requirements with our counterparties.
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We have completed a review of potential changes to our company structure with a goal of enhancing shareholder value and determined to leave our company structure unchanged. Major factors in our decision were the sharp decline in energy commodity prices and a further deterioration in the macroeconomic environment since the initiation of the review in early November 2008. Our business mix and strong credit profile position us to weather the challenging economic and market conditions in 2009 and benefit as the economy recovers.
New Accounting Standards and Emerging IssuesPronouncements Issued But Not Yet Adopted
Accounting standardspronouncements that have been issued and arebut not yet effectiveadopted may have a materialan effect on our Consolidated Financial Statements in the future. These include:
| | |
| • | SFAS No. 157 “Fair Value Measurements” (SFAS 157). The effective date for this Statement is for fiscal years beginning after November 15, 2007. We will assess the impact on our Consolidated Financial Statements. |
|
| • | FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (FIN 48). |
FIN 48 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.
We adopted FIN 48 as of January 1, 2007. The cumulative effect of applying the Interpretation will be reported as an adjustment to the opening balance of retained earnings. The net impact of the cumulative effect of adopting FIN 48 is expected to be in the range of a $10 million to $20 million decrease in retained earnings.
SeeRecent Accounting Standardsin Note 1 of Notes to Consolidated Financial Statements for further information on these and other recently issued accounting standards.
Modernization of Oil & Gas Reporting Requirements
The SEC has revised its oil and gas reserves reporting requirements effective for fiscal years ending on or after December 31, 2009, with early adoption prohibited. These changes include:
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| • | Expanding the definition of oil and gas reserves and providing clarification of certain concepts and technologies used in the reserve estimation process. |
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| • | Allowing optional disclosure of probable and possible reserves and permitting optional disclosure of price sensitivity analysis. |
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| • | Modifying prices used to estimate reserves for SEC disclosure purposes to a12-month average price instead of asingle-day, period-end price. |
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| • | Requiring certain additional disclosures around proved undeveloped reserves, internal controls used to ensure objectivity of the estimation process, and qualifications of those preparingand/or auditing the reserves. |
Historically, the reserves calculated based on the SEC’s reporting requirements were also used to calculate depletion on our producing properties, as required by SFAS 69, “Disclosures about Oil and Gas Producing Activities” (SFAS 69). However, the change in the SEC reporting requirements has not yet been adopted by the FASB. The SEC has announced its intent to discuss potential amendments to SFAS 69 with the FASB so that the reserves disclosed remain consistent with the reserves used to calculate depletion on our producing properties. Any such change would impact our future financial results. The SEC has indicated that it may delay the effective date of the revised reporting requirements if the FASB does not make conforming amendments by December 31, 2009.
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Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts therein.assumptions. We have discussed the following accounting estimates and assumptions as well as related disclosures with our Audit Committee. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Revenue Recognition —Impairments of Long-Lived Assets and Goodwill
We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that may include the estimated fair value of the asset, undiscounted future cash flows, discounted future cash flows, and the current and future economic environment in which the asset is operated.
Based on our assessment of the undiscounted and discounted cash flows on natural gas-producing properties and associated unproved leasehold costs in the Arkoma basin, Exploration & Production recorded an impairment charge of $129 million in December 2008. Significant judgments and assumptions in this impairment analysis included year-end natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, capital costs, and a pre-tax discount rate of 15 percent. The recorded impairment was largely the result of lower forward pricing estimates at year-end and lower reserve estimates resulting from lower year-end prices.
In addition to those long-lived assets for which impairment charges were recorded (see Note 4 of Notes to Consolidated Financial Statements), certain others were reviewed for which no impairment was required. These reviews included Exploration & Production’s properties in other basins and utilized inputs consistent with those described above for the Arkoma basin. Certain assets within our Midstream segment were also evaluated for impairment utilizing judgments and assumptions including future fees, margins and volumes. The use of alternate judgmentsand/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.
We have goodwill of approximately $1 billion at Exploration & Production primarily resulting from a 2001 acquisition. We assess goodwill for impairment annually as of the end of the year. For purposes of our assessment, the reporting unit is Exploration & Production’s domestic operations. As of December 31, 2008, the estimated fair value of the reporting unit exceeds its carrying value, including goodwill, indicating no impairment of Exploration & Production’s goodwill.
We estimated the fair value of the reporting unit on a stand-alone basis primarily by valuing proved and unproved reserves. We used an income approach (discounted cash flows) for valuing reserves. The significant inputs into the valuation of proved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves and appropriate discount rates. Unproved reserves were valued using similar assumptions adjusted further for the uncertainty associated with these reserves.
In estimating the inputs, management must make assumptions that require judgments and are subject to change in response to changing market conditions and other future events. Significant assumptions in valuing proved reserves included reserve quantities of more than 4.3 Tcfe, natural gas prices, adjusted for locational differences, averaging approximately $5.80 per Mcfe and a pre-tax discount rate of 15 percent.
We further reviewed the estimated fair value of the stand-alone reporting unit by reconciling the sum of the fair values of all our businesses to our total market capitalization, including a control premium. In estimating the fair value of our businesses and a control premium, we considered a range of market comparables from historical sales transactions of energy companies. Market capitalization was based on our traded stock price for a reasonably short period of time before and after December 31, 2008. In evaluating these items in our reconciliation analysis, management considered a range of reasonable judgments. This reconciliation allowed management to consider market expectations in corroborating the reasonableness of the estimated stand-alone fair value of the Exploration & Production reporting unit.
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We also perform interim assessments of goodwill if impairment triggering events or circumstances are present. Examples of impairment triggering events or circumstances include:
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| • | The testing for recoverability of a significant long-lived asset group within the reporting unit; |
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| • | Recent operating losses or negative cash flows at the reporting unit level; |
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| • | A decline in natural gas prices or reserve quantities; |
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| • | Not meeting internal forecasts, or downward adjustments to future forecasts; |
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| • | A decline in enterprise market capitalization below our consolidated stockholders’ equity; |
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| • | Industry trends. |
We cannot predict future market conditions and events that might adversely affect the estimated fair value of the Exploration & Production reporting unit and possibly the reported value of goodwill. The estimated fair value of the reporting unit is significantly affected by natural gas prices, reserve quantities and market expectations for required rates of return. Further declines in natural gas prices would lower our estimates of fair value. There are numerous uncertainties inherent in estimating quantities of reserves that could affect our reserve quantities. Low prices for natural gas, regulatory limitations, or the lack of available capital for projects could adversely affect the development and production of additional reserves. Given the significant challenges affecting our businesses and the energy industry in 2009, these factors could impact us and require us to assess goodwill for possible impairment more frequently during 2009.
Subsequent to December 31, 2008, as a result of overall market and energy commodity price declines, we have witnessed periodic reductions in our total market capitalization below our December 31, 2008, consolidated stockholders’ equity balance. If our total market capitalization is below our consolidated stockholders’ equity balance at a future reporting date, we consider this an indicator of potential impairment of goodwill under recent SEC communications and our accounting considerations. We utilize market capitalization in corroborating our assessment of the fair value of our Exploration & Production reporting unit. Considering this, it is reasonably possible that we may be required to conduct an interim goodwill impairment evaluation, which could result in a material impairment of our goodwill.
Accounting for Derivative Instruments and Hedging Activities
We hold a substantial portfolio ofreview our energy trading and nontrading contracts for a variety of purposes. We review these contracts to determine whether they are, nonderivatives or contain derivatives. If they are derivatives, weWe further assess whether the contracts qualifyappropriate accounting method for eitherany derivatives identified, which could include:
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| • | 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; |
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| • | Qualifying for and electing accrual accounting under the normal purchases and normal sales exception, or; |
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| • | Applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings. |
If cash flow hedge accounting or accrual accounting is not applied, a derivative is subject to mark-to-market accounting. Determination of the normal purchasesaccounting method involves significant judgments and normal sales exception.assumptions, which are further described below.
The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in achieving offsetting the cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur, and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.
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For derivatives that are designated as cash flow hedges, we do not reflect changes in their fair value in earnings until the associated hedged item affects earnings. For those that have not been designated as hedges or do notmust periodically assess whether they continue to qualify for hedge accounting, we recognize the net change in their fair value in income currently (marked to market).
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For derivatives that are designated as cash flow hedges, weaccounting. We prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we must also reclassreclassify amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting the cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.
Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand, and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.
TheSince our energy derivative contracts could be accounted for in three different ways, two of which are elective, our accounting method could be different from that used by another party for a similar transaction. Furthermore, the accounting method may influence the level of volatility in the financial statements associated with changes in the fair value of derivative contracts is determined based on the nature of the transaction and the market in which transactions are executed. We also incorporate assumptions and judgments about counterparty performance and credit considerations in our determination of their fair value. Contracts are executed in the following environments:derivatives, as generally depicted below:
| | | | | | | | |
| | • | Organized commodity exchange orover-the-counter markets with quoted prices;Consolidated Statement of Income | | Consolidated Balance Sheet |
Accounting Method | | Drivers | | Impact | | Drivers | | Impact |
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| Accrual Accounting | • | Organized commodity exchange orover-the-counter markets with quoted market prices but limited price transparency, requiring increased judgment to determine fair value;Realizations | | Less Volatility | | None | | No Impact |
| Cash Flow Hedge Accounting | | Realizations & Ineffectiveness | | Less Volatility | | Fair Value Changes | | More Volatility |
| Mark-to-Market Accounting | • | Markets without quoted market prices.Fair Value Changes | | More Volatility | | Fair Value Changes | | More Volatility |
The number
Our determination of transactions executed without quoted market prices is limited. We estimate the fair value of these contracts by using readily available price quotes in similar markets and other market analyses. The fair value of all derivative contracts is continually subjectaccounting method does not impact our cash flows related to change as the underlying commodity market changes and our assumptions and judgments change.derivatives.
Additional discussion of the accounting for energy contracts at fair value is included in Energy Trading Activities within Item 7Notes 1 and Note 115 of Notes to Consolidated Financial Statements.
Oil- and Gas-Producing Activities
We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:
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| | • | An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) ourunit-of-production depreciation, depletion and amortization rates. |
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| | • | Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses, including that for goodwill. |
The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering, and economic data. After being estimated internally, 99.999 percent of our reserve estimates are either audited or prepared by independent experts. (See Part I Item 1 for further discussion.) The data may change substantially over time as a result of numerous factors, including additional development cost and activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. A revision of our reserve estimates within reasonably likely parameters is not expected to result inSuch changes could trigger an impairment of our oiloil- and
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gas gas-producing propertiesand/or goodwill. However, reserve estimate revisions would goodwill and have an impact on our depreciation and depletion expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves for each basin wouldcould change our annualdepreciation, depletion and
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amortizationexpense between approximately $25$46 million and $31$56 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserve categories.
Forward market prices, which are utilized in our impairment analyses, include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating our drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. AnSignificant unfavorable changechanges in the forward price curve within reasonably likely parameters is not expected tocould result in an impairment of our oil and gas propertiesand/or goodwill.
Contingent Liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income in the period in whichwhen new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 1516 of Notes to Consolidated Financial Statements.
Valuation of Deferred Tax Assets and Tax Contingencies
We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of the book basis and from tax carry-forwards generated in the current and prior years. We must evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. At December 31, 2006,2008, we have approximately $926$639 million of deferred tax assets for which a $36$15 million valuation allowance has been established. When assessing the need for a valuation allowance, we consideredconsider forecasts of future company performance, the estimated impact of potential asset dispositions and our ability and intent to execute tax planning strategies to utilize tax carryovers. Based on our projections, we believe that it is probable that we can utilize our year-end 2006 federal tax net operating losses carryovers and charitable contribution carryovers prior to their expiration. We do not expect to be able to utilize $36 million of foreign deferred tax assets related to carryovers. See Note 5 of Notes to Consolidated Financial Statements for additional information regarding the tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.
We regularly face challenges from domestic and foreign tax authorities regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluatingWe evaluate the liability associated with our various filing positions we record a liabilityby applying the two step process of recognition and measurement as required by FASB Interpretation No. 48, “Accounting for probable tax contingencies.Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The ultimate disposition of these contingencies could have a significant impact on operating results and net cash flows. To the extent we were to prevail in matters for which accruals have been established or were required to pay amounts in excess of our accrued liability, our effective tax rate in a given financial statement period may be materially impacted.
See Note 5 of Notes to Consolidated Financial Statements for additional information regarding FIN 48.
Pension and Postretirement Obligations
We have employee benefit plans that include pension and other postretirement benefits. Pension and other postretirementNet periodic benefit plan expense and obligations are calculated by a third-party actuary and are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return
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on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute expense and the benefit obligations are shown in Note 7 of Notes to Consolidated Financial Statements. The following table
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presents the estimated increase (decrease) in pension and other postretirementnet periodic benefit expense and obligations resulting from a one-percentage-point change in the specified assumption.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Benefit Expense | | Benefit Obligation | | | Benefit Expense | | Benefit Obligation | |
| | | One-Percentage-
| | One-Percentage-
| | One-Percentage-
| | One-Percentage-
| | | One-Percentage-
| | One-Percentage-
| | One-Percentage-
| | One-Percentage-
| |
| | | Point Increase | | Point Decrease | | Point Increase | | Point Decrease | | | Point Increase | | Point Decrease | | Point Increase | | Point Decrease | |
| | | (Millions) | | | (Millions) | |
| |
| Pension benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount rate | | $ | (12 | ) | | $ | 14 | | | $ | (129 | ) | | $ | 151 | | | $ | (13 | ) | | $ | 14 | | | $ | (133 | ) | | $ | 154 | |
| Expected long-term rate of return on plan assets | | | (10 | ) | | | 10 | | | | — | | | | — | | | | (7 | ) | | | 7 | | | | — | | | | — | |
| Rate of compensation increase | | | 2 | | | | (2 | ) | | | 14 | | | | (13 | ) | | | 3 | | | | (3 | ) | | | 17 | | | | (17 | ) |
| Other postretirement benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount rate | | | (1 | ) | | | 1 | | | | (41 | ) | | | 47 | | | | (2 | ) | | | 2 | | | | (32 | ) | | | 37 | |
| Expected long-term rate of return on plan assets | | | (2 | ) | | | 2 | | | | — | | | | — | | | | (1 | ) | | | 1 | | | | — | | | | — | |
| Assumed health care cost trend rate | | | 6 | | | | (5 | ) | | | 61 | | | | (48 | ) | | | 8 | | | | (6 | ) | | | 53 | | | | (42 | ) |
The expected long-term rates of return on plan assets are determined by combining a review of historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy Statement, and the capital market projections provided by our independent investment consultant for the asset classifications in which the portfolio is invested as well as the target weightings of each asset classification. TheseThe credit crisis and subsequent economic downturn have negatively impacted the markets and our 2008 investment returns largely mirror market performance. While the market downturn has impacted short-term investment performance, these expected rates are impacted by changes in general market conditions, but because theyof return are long-term in nature and are not significantly impacted by short-term market swings do not significantly impact the rates.swings. Changes to our target asset allocation would also impact these rates.expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans iswas 7.75 percent for 2006 through 2008 and was 8.5 percent from2002-2005.for 2003 through 2005. Over the past ten years, our actual average return on plan assets for our pension plans has been approximately 7.92.1 percent. The 2008 return on plan assets for our pension plans was a loss of approximately 34.1 percent, which significantly impacted the ten-year average rate of return on plan assets. The 2007 ten-year average rate of return on plan assets for the pension plans was approximately 7.7 percent. As described in Note 7 of Notes to Consolidated Financial Statements, the asset allocation is being changed during 2009 with a slightly higher percentage of plan assets being allocated to debt securities and cash and cash equivalents. Therefore, our 2009 expected long-term rate of return on plan assets assumption is expected to slightly decrease.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount future benefitrates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows to today’s dollars. Decreaseswhen benefit payments are due. Increases in thesethe discount rates increasedecrease the obligation and, generally, increasedecrease the related expense. The discount rates for our pension and other postretirement benefit plans wereare determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 7 of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term high-quality corporate bonds.debt securities as well as by the duration of our plans’ liabilities.
The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and expense to increase.
The assumed health care cost trend rates are based on our actual historical cost rates that are adjusted for expected changes in the health care industry. An increase in this rate causes the other postretirement benefit obligation and expense to increase.
Fair Value Measurements
On January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), for our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy derivatives. See Note 14 of Notes to Consolidated Financial Statements for disclosures regarding SFAS No. 157, including discussion of the fair value hierarchy levels and valuation methodologies.
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Certain of our energy derivative assets and liabilities and other assets trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. At December 31, 2008, 22 percent of the total assets measured at fair value and 2 percent of the total liabilities measured at fair value are included in Level 3. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.
The determination of fair value also incorporates the time value of money and credit risk factors including the credit standing of the counterparties involved, the existence of master netting arrangements, the impact of credit enhancements (such as cash deposits and letters of credit) and our nonperformance risk on our liabilities. Currently, our approach is to apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points through time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2008, the credit reserve is $6 million on our net derivative assets and $15 million on our net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.
As of December 31, 2008, 77 percent of our derivatives portfolio expires in the next 12 months and 99 percent of our derivatives portfolio expires in the next 36 months. Our derivatives portfolio is largely comprised ofexchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.
The instruments included in Level 3 at December 31, 2008, predominantly consist of options that hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled. The options are valued using an industry standard Black-Scholes option pricing model. Certain inputs into the model are generally observable, such as commodity prices and interest rates, whereas a significant input, implied volatility by location, is unobservable. The impact of volatility on changes in the overall fair value of the options structured as collars is mitigated by the offsetting nature of the put and call positions. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices. The hedges are accounted for as cash flow hedges where net unrealized gains and losses from changes in fair value are recorded, to the extent effective, inother comprehensive income (loss) and subsequently impact earnings when the underlying hedged production is sold.
Exploration & Production has an unsecured credit agreement through December 2013 with certain banks that, so long as certain conditions are met, serves to reduce our usage of cash and other credit facilities for margin requirements related to instruments included in the facility.
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Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2006.2008. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
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| | | 2006 | | 2005(1) | | 2005(1) | | 2005 | | 2004(1) | | 2004(1) | | 2004 | | | 2008 | | 2007* | | 2007* | | 2007 | | 2006* | | 2006* | | 2006 | |
| | | (Millions) | | | | | | (Millions) | | | | | | (Millions) | | | (Millions) | | | | | | (Millions) | | | | | | (Millions) | |
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| Revenues | | $ | 11,812.9 | | | $ | –770.7 | | | | −6 | % | | $ | 12,583.6 | | | $ | +122.3 | | | | +1 | % | | $ | 12,461.3 | | | $ | 12,352 | | | | +1,866 | | | | +18 | % | | $ | 10,486 | | | | +1,187 | | | | +13 | % | | $ | 9,299 | |
| Costs and expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Costs and operating expenses | | | 9,973.6 | | | | +897.4 | | | | +8 | % | | | 10,871.0 | | | | −119.3 | | | | −1 | % | | | 10,751.7 | | | | 9,156 | | | | −1,149 | | | | −14 | % | | | 8,007 | | | | −518 | | | | −7 | % | | | 7,489 | |
| Selling, general and administrative expenses | | | 449.2 | | | | −123.8 | | | | −38 | % | | | 325.4 | | | | +30.1 | | | | +8 | % | | | 355.5 | | | | 504 | | | | −33 | | | | −7 | % | | | 471 | | | | −82 | | | | −21 | % | | | 389 | |
| Other (income) expense — net | | | 20.7 | | | | +40.5 | | | | +66 | % | | | 61.2 | | | | −112.8 | | | | NM | | | | (51.6 | ) | | | (82 | ) | | | +64 | | | | NM | | | | (18 | ) | | | +52 | | | | NM | | | | 34 | |
| General corporate expenses | | | 132.1 | | | | +13.4 | | | | +9 | % | | | 145.5 | | | | −25.7 | | | | −21 | % | | | 119.8 | | | | 149 | | | | +12 | | | | +7 | % | | | 161 | | | | −29 | | | | −22 | % | | | 132 | |
| Securities litigation settlement and related costs | | | 167.3 | | | | −157.9 | | | | NM | | | | 9.4 | | | | −9.4 | | | | NM | | | | — | | | | — | | | | — | | | | — | | | | — | | | | +167 | | | | +100 | % | | | 167 | |
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| Total costs and expenses | | | 10,742.9 | | | | | | | | | | | | 11,412.5 | | | | | | | | | | | | 11,175.4 | | | | 9,727 | | | | | | | | | | | | 8,621 | | | | | | | | | | | | 8,211 | |
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| Operating income | | | 1,070.0 | | | | | | | | | | | | 1,171.1 | | | | | | | | | | | | 1,285.9 | | | | 2,625 | | | | | | | | | | | | 1,865 | | | | | | | | | | | | 1,088 | |
| Interest accrued — net | | | (658.9 | ) | | | +5.6 | | | | +1 | % | | | (664.5 | ) | | | +163.2 | | | | +20 | % | | | (827.7 | ) | | | (594 | ) | | | +59 | | | | +9 | % | | | (653 | ) | | | — | | | | — | | | | (653 | ) |
| Investing income | | | 173.0 | | | | +149.3 | | | | NM | | | | 23.7 | | | | −24.3 | | | | −51 | % | | | 48.0 | | | | 191 | | | | −66 | | | | −26 | % | | | 257 | | | | +89 | | | | +53 | % | | | 168 | |
| Early debt retirement costs | | | (31.4 | ) | | | −31.0 | | | | NM | | | | (.4 | ) | | | +281.7 | | | | +100 | % | | | (282.1 | ) | | | (1 | ) | | | +18 | | | | +95 | % | | | (19 | ) | | | +12 | | | | +39 | % | | | (31 | ) |
| Minority interest in income of consolidated subsidiaries | | | (40.0 | ) | | | −14.3 | | | | −56 | % | | | (25.7 | ) | | | −4.3 | | | | −20 | % | | | (21.4 | ) | | | (174 | ) | | | −84 | | | | −93 | % | | | (90 | ) | | | −50 | | | | −125 | % | | | (40 | ) |
| Other income — net | | | 26.4 | | | | −0.7 | | | | −3 | % | | | 27.1 | | | | +5.3 | | | | +24 | % | | | 21.8 | | | | — | | | | −11 | | | | −100 | % | | | 11 | | | | −15 | | | | −58 | % | | | 26 | |
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| Income from continuing operations before income taxes and cumulative effect of change in accounting principle | | | 539.1 | | | | | | | | | | | | 531.3 | | | | | | | | | | | | 224.5 | | |
| Income from continuing operations before income taxes | | | | 2,047 | | | | | | | | | | | | 1,371 | | | | | | | | | | | | 558 | |
| Provision for income taxes | | | 206.3 | | | | +7.6 | | | | +4 | % | | | 213.9 | | | | −82.6 | | | | −63 | % | | | 131.3 | | | | 713 | | | | −189 | | | | −36 | % | | | 524 | | | | −313 | | | | −148 | % | | | 211 | |
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| Income from continuing operations | | | 332.8 | | | | | | | | | | | | 317.4 | | | | | | | | | | | | 93.2 | | | | 1,334 | | | | | | | | | | | | 847 | | | | | | | | | | | | 347 | |
| Income (loss) from discontinued operations | | | (24.3 | ) | | | −22.2 | | | | NM | | | | (2.1 | ) | | | −72.6 | | | | NM | | | | 70.5 | | | | 84 | | | | −59 | | | | −41 | % | | | 143 | | | | +181 | | | | NM | | | | (38 | ) |
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| Income before cumulative effect of change in accounting principle | | | 308.5 | | | | | | | | | | | | 315.3 | | | | | | | | | | | | 163.7 | | |
| Cumulative effect of change in accounting principle | | | — | | | | +1.7 | | | | +100 | % | | | (1.7 | ) | | | −1.7 | | | | NM | | | | — | | |
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| Net income | | $ | 308.5 | | | | | | | | | | | $ | 313.6 | | | | | | | | | | | $ | 163.7 | | | $ | 1,418 | | | | | | | | | | | $ | 990 | | | | | | | | | | | $ | 309 | |
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(1)* | | + = Favorable change tonet income; —– = Unfavorable change tonet income; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator, or a percentage change greater than 200. |
20062008 vs. 20052007
Our consolidated results in 2008 have improved significantly compared to 2007. However, these results were considerably influenced by favorable results in the first three quarters of the year, followed by a sharp decline in the fourth quarter due to a rapid decline in energy commodity prices.
The decreaseincrease inrevenuesis primarily due to lower power and natural gas realizedhigher production revenues at Power. TheseExploration & Production resulting from both higher net realized average prices and increased production volumes sold. Midstream also experienced higher olefin production revenues declinedprimarily due to lower saleshigher average prices and volumes associated with reducing the scope of our trading activities and lower natural gas sales prices. Partially offsetting these decreases areas well as increased crude, olefin and natural gas liquid (NGL) marketingproduction revenues resulting from higher average prices, partially offset by lower volumes. Additionally, Gas Marketing Services revenues increased primarily due to favorable price movements on derivative positions economically hedging the anticipated withdrawals of natural gas from storage and higher NGL production revenue at Midstream and increased production revenue at Exploration & Production.the absence of a loss recognized on a legacy derivative sales contract in 2007.
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The decreaseincrease incosts and operating expensesis largelyprimarily due to decreased power purchase volumes and reduced natural gas purchase prices at Power. Partially offsetting these decreases are increased crude,costs associated with our olefin and NGL
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marketing purchases and operating expenses production businesses at Midstream and increasedMidstream. Higher depreciation, depletion, and amortization and leasehigher operating expensetaxes at Exploration & Production.Production also contributed to the increase in expenses.
The increase inselling, general and administrative (SG&A) expensesis(SG&A)primarily includes the impact of higher staffing and compensation at our Exploration & Production and Midstream segments in support of increased operational activities.
Other (income) expense —netwithinoperating incomein 2008 includes:
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| • | Gain of $148 million on the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production; |
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| • | Net gains of $49 million on foreign currency exchanges at Midstream; |
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| • | Income of $32 million related to the partial settlement of our Gulf Liquids litigation at Midstream; |
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| • | Gain of $10 million on the sale of certain south Texas assets at Gas Pipeline; |
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| • | Income of $17 million resulting from involuntary conversion gains at Midstream; |
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| • | Impairment charges totaling $143 million related to certain natural gas producing properties at Exploration & Production; |
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| • | Expense of $23 million related to project development costs at Gas Pipeline. |
Other (income) expense —netwithinoperating incomein 2007 includes:
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| • | Income of $18 million associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral; |
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| • | Income of $17 million associated with a change in estimate related to a regulatory liability at Northwest Pipeline; |
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| • | Income of $12 million related to a favorable litigation outcome at Midstream; |
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| • | Income of $8 million due to the reversal of a planned major maintenance accrual at Midstream; |
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| • | Expense of $20 million related to an accrual for litigation contingencies at Gas Marketing Services; |
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| • | Expense of $10 million related to an impairment of the Carbonate Trend pipeline at Midstream. |
The increase inoperating incomereflects improved operating results at Exploration & Production due to higher net realized average prices, natural gas production growth and a gain of $148 million on the sale of a contractual right to a production payment, partially offset by increased operating costs and $143 million of property impairments in 2008. The increase also reflects improved results at Gas Marketing Services primarily due to increased personnel costs, insurance expense, higher information systems support costsfavorable price movements on derivative positions economically hedging the anticipated withdrawals of natural gas from storage and the absence of a $17.1 millionloss recognized on a legacy derivative sales contract in 2007. Partially offsetting these increases is a decrease inoperating incomeat Midstream primarily due to a sharp decline in energy commodity prices in the latter part of 2008.
Interest accrued —netdecreased primarily due to increased capitalized interest resulting from an increased level of capital expenditures. The decrease was also a result of lower interest rates on debt issuances that occurred late in the fourth quarter of 2007 and in the first half of 2008 for which the proceeds were primarily used to retire existing debt bearing higher interest rates. While our overall debt balances have been relatively comparable, the net effect of these retirements and issuances has resulted in lower rates.
The decrease ininvesting incomeis primarily due to a decrease in interest income largely resulting from lower average interest rates in 2008 compared to 2007.
Minority interest in income of consolidated subsidiariesincreased primarily reflecting the growth in the minority interest holdings of Williams Partners L.P. and Williams Pipeline Partners L.P. in late 2007 and early 2008, respectively.
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Provision for income taxesincreased primarily due to higher pre-tax income partially offset by a reduction in our estimate of pension expensethe effective deferred state tax rate. See Note 5 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rate compared to the federal statutory rate for both periods.
See Note 2 of Notes to Consolidated Financial Statements for a discussion of the items inincome (loss) from discontinued operations.
2007 vs. 2006
The increase inrevenuesis due primarily to higher Midstream revenues associated with increased NGL and olefins marketing revenues and increased production of olefins and NGLs. Exploration & Production experienced higher revenues also due to increases in production volumes and net realized average prices. Additionally, Gas Pipeline revenues increased primarily due to increased rates in effect since the first quarter of 2007. These increases are partially offset by a mark-to-market loss recognized at Gas PipelineMarketing Services on a legacy derivative natural gas sales contract that we expect to assign to another party in 2005.2008 under an asset transfer agreement that we executed in December 2007.
The increase incosts and operating expensesis due primarily to increased NGL and olefins marketing purchases and increased costs associated with our olefins production business at Midstream. Additionally, Exploration & Production experienced higher costsdepreciation, depletion and amortization and lease operating expenses due primarily to higher production volumes.
The increase inSG&Ais primarily due to increased staffing in support of increased drilling and operational activity.activity at Exploration & Production, the absence of a $25 million gain in 2006 related to the sale of certain receivables at Gas Marketing Services, and a $9 million charge related to certain international receivables at Midstream.
Other (income) expense —netwithinoperating incomein 2006 includes:
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| | • | A $72.7$73 million accrual for a Gulf Liquids litigation contingency; |
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| • | Income of $12.7 million due to reducing contingent obligations associated with our former distributive power generation business at Power; |
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| | • | Income of $9 million due to a settlement of an international contract dispute at Midstream;Midstream. |
The increase inOther (income) expense — netwithinoperating incomein 2005 includes:
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| • | An $82.2 million accrual for litigation contingencies at Power, associated primarily with agreements reached to substantially resolve exposure related to certain natural gas price and volume reporting issues; |
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| • | Gains totaling $29.6 million on the sale of certain natural gas properties at Exploration & Production; |
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| • | A gain of $9 million on a sale of land in our Other segment. |
Generalgeneral corporate expensesdecreasedis attributable to various factors, including higher employee-related costs, increased levels of charitable contributions and information technology expenses. The higher employee-related costs are primarily duethe result of higher stock compensation expense. (See Note 1 of Notes to the absence of $13.8 million of insurance settlement charges in 2005 associated with certain insurance coverage allocation issues.Consolidated Financial Statements.)
Thesecurities litigation settlement and related costsis primarily the result of settlingour 2006 settlement related toclass-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002. (See Note 16 of Notes to Consolidated Financial Statements.)
The increase inoperating incomereflects record high NGL margins at Midstream, continued strong natural gas production growth at Exploration & Production, the positive effect of new rates at Gas Pipeline, and the absence of 2006 litigation expenses associated with shareholder lawsuits and Gulf Liquids litigation.
Interest accrued — netin 2006 includes $22a decrease of $19 million in interest expense associated with our Gulf Liquids litigation contingency.contingency, offset by changes in our debt portfolio, most significantly the issuance of new debt in December 2006 by Williams Partners L.P.
The increase ininvesting incomeis due to:
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| | • | The absence of an $87.2 million impairment in 2005 on our investment in Longhorn Partners Pipeline, L.P. (Longhorn); |
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| • | The absence of a $23 million impairment in 2005 of our Aux Sable Liquid Products, L.P. (Aux Sable) equity investment; |
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| • | An approximate $37A $27 million increase in interest income primarily associated with increased earnings onlarger cash and cash equivalent balances associatedcombined with slightly higher rates of return;return in 2007 compared to 2006; |
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| | • | Increased equity earnings of $33.3$38 million due largely to the absence of equity losses in 2006 on Longhorn and 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; |
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These increases are partially offset by:
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| | • | A $16.4The absence of a $16 million impairment in 2006 of a Venezuelan cost-based investment at Exploration & Production; |
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| | • | The absence$14 million of an $8.6 million gain on salegains from sales of our remainingMid-America Pipeline (MAPL) and Seminole Pipeline (Seminole)cost-based investments at Midstream in 2005.2007. |
These increases are partially offset by the absence of a $7 million gain on the sale of an international investment in 2006.
Early debt retirement costsin 2007 includes $19 million of premiums and fees related to the December 2007 repurchase of senior unsecured notes.Early debt retirement costsin 2006 includes $25.8$27 million in premiums and $1.2 million in fees related to the January 2006 debt conversion and $4.4$4 million of accelerated amortization of debt expenses related to the retirement of the debt secured by assets of Williams Production RMT Company.
The increase inminorityMinority interest in income of consolidated subsidiaries isincreased primarily due to the growth in the minority interest holdings of Williams Partners L.P., our consolidated master limited partnership.
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Provision for income taxeschanged favorably during the year. The effective income tax rate for 2006 is slightlywas significantly higher than the federal statutory rate primarily due to state income taxes, the effect of taxes on foreign operations, nondeductible convertible debenture expenses and an accrual for income tax contingencies, partially offset by the favorable resolution of federal income tax litigation and the utilization of charitable contribution carryovers not previously benefited. The 2006 effective income tax rate has been increased by an adjustment to increase overall deferred income tax liabilities. The effective income tax rate for 2005 is higher than the federal statutory ratein 2007 due primarily to state income taxes, nondeductible expenses, the effect of taxes on foreign operations and the inability to utilize charitable contribution carryovers. The 2005 effective income tax rate was reduced by an adjustment to reduce overall deferred income tax liabilities and favorable settlements on federal and state income tax matters. (Seehigher pre-tax earnings. See Note 5 of Notes to Consolidated Financial Statements.)Statements for a reconciliation of the effective tax rate compared to the federal statutory rate for both periods.
Income (loss) from discontinued operationsin 2006 includes:
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| • | An $11.9 millionnet-of-tax litigation settlement related to our former chemical fertilizer business; |
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| • | A $3.7 millionnet-of-tax charge associated with the settlement of a loss contingency related to a former exploration business; |
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| • | A $9.1 millionnet-of-tax charge associated with an oil purchase contract related to our former Alaska refinery. |
Cumulative effect of change in accounting principlein 2005 is due to the implementation of FIN 47. (SeeSee Note 92 of Notes to Consolidated Financial Statements.)
2005 vs. 2004
The increase in revenues is due primarily to increased revenues at Exploration & Production due to higher natural gas prices and production volumes sold and gas management income, and at Midstream due primarily to increased NGL prices and crude marketing revenue. Partially offsetting these increases is decreased revenue at Power due primarily toStatements for a discussion of the absence of crude and refined products activity and reduced net forward unrealizedmark-to-market gains.
The increaseitems incosts and operating expensesis due primarily to increased crude marketing costs and increased NGL costs at Midstream in addition to increased depreciation, depletion and amortization and gas management expense at Exploration & Production. Partially offsetting these increases are decreased costs at Power primarily due to the absence of crude and refined products activity.
The decrease inSG&A expensesis primarily due to the $17.1 million reduction in expenses at Gas Pipeline to record the cumulative impact of a correction to pension expense attributable to the periods 2003 and 2004 and a $9.7 reduction of bad debt expense at Power resulting from the sale of certain receivables to a third party. Partially offsetting these items is increased staffing costs at Exploration & Production in support of increased operational drilling activity.
Other (income) expense — net,withinoperating incomein 2004 includes:
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| • | Income of $93.6 million from an insurance arbitration award associated with Gulf Liquids at Midstream; |
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| • | Gains of $16.2 million from the sale of Exploration & Production’s securities, invested in a coal seam royalty trust, that were purchased for resale; |
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| • | A $9.5 million gain on the sale of Louisiana olefins assets at Midstream; |
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| • | A $15.4 million loss provision related to an ownership dispute on prior period production included at Exploration & Production; |
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| • | An $11.8 million environmental expense accrual related to the Augusta refinery facility included in our Other segment; |
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| • | A $9 million write-off of previously capitalized costs on an idled segment of Northwest Pipeline’s system included at Gas Pipeline. |
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The increase ingeneral corporate expensesis due primarily to the $13.8 million of expense related to the settlement of certain insurance coverage issues and a $16 million increase in outside legal costs associated primarily with securities class action matters.
The decrease ininterest accrued — netis due primarily to lower average borrowing levels in 2005 as compared to 2004.
The decrease ininvesting incomeis due primarily to a $76.4 increase in impairment charges on our investment in Longhorn, a $13.9 million increase in Longhorn equity losses, and the $23 million impairment of our Aux Sable equity investment. Partially offsetting these decreases are the following increases:
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| • | A $30.4 million increase in domestic and international equity earnings, excluding Longhorn and Aux Sable; |
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| • | The absence in 2005 of a $20.8 million impairment of an international cost-based investment; |
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| • | The absence in 2005 of a $16.9 million impairment of our Discovery equity investment; |
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| • | The $8.6 million gain on the sale of our remaining interests in the MAPL and Seminole assets; |
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| • | The absence in 2005 of a $6.5 million Longhorn recapitalization fee. |
Early debt retirement costsinclude premiums, fees and expenses related to the retirement of debt.
Provision for income taxeschanged unfavorably primarily due to increased pre-tax income in 2005 as compared to 2004. The effective income tax rate for 2005 is higher than the federal statutory rate due primarily to state income taxes, nondeductible expenses, the effect of taxes on foreign operations and the inability to utilize charitable contribution carryovers. The 2005 effective income tax rate has been reduced by an adjustment to reduce the overall deferred income tax liabilities and favorable settlements on federal and state income tax matters. The effective income tax rate for 2004 is higher than the federal statutory rate due primarily to state income taxes, a charge associated with charitable contribution carryovers and the effect of taxes on foreign operations. A 2004 accrual for income tax contingencies was offset by favorable settlements of certain federal and state income tax matters. (See Note 5 of Notes to Consolidated Financial Statements.)
Income (loss) from discontinued operationsoperations.in 2004 is comprised of gains on the sales of the Canadian straddle plants and the Alaska refinery of $189.8 million and $3.6 million, respectively, as well as $22 million in income from our Canadian straddles discontinued operation. Partially offsetting these are $153 million of charges to increase our accrued liability associated with certain Quality Bank litigation matters.
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Results of Operations — Segments
We are currently organized into the following segments: Exploration & Production, Gas Pipeline, Midstream, Power,Gas Marketing Services, and Other. Other primarily consists of corporate operations. Our management currently evaluates performance based on segment profit (loss) from operations. (See Note 1718 of Notes to Consolidated Financial Statements.)
Exploration & Production
Overview of 20062008
In 2006, we2008, segment revenues and segment profit for Exploration & Production improved significantly compared to 2007. The 2008 results benefited from higher production levels coupled with higher natural gas prices through the first three quarters of the year. However, the results were negatively impacted by a significant decline in natural gas prices in the fourth quarter. The potential impact of sustained lower natural gas prices is discussed further in the followingOutlook for 2009section.
We’ve remained focused on continuing our objective to rapidly expanddomestic development ofdrilling program in our drilling inventory. This resulted in significant growth as evidenced by the following accomplishments:basins. Accordingly, we:
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| | • | WeBenefited 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 2320 percent over last year, surpassing our goal of 15compared to 20 percent.2007. The average daily domestic production for 2008 was approximately 7521,094 million cubic feet of gas equivalent (MMcfe) compared to 612913 MMcfe in 2005.2007. The increased production is primarily due to increased development within the Piceance, and Powder River, and Fort Worth basins. |
Domestic Production
2006 domestic production grew 23 percent or 140 MMcfe per day over 2005
| | |
| | • | We continued to increase our development drilling program during 2006. We drilledDrilled 1,783 gross domestic development wells in 2006 compared to 1,627 in 2005.2008 with a success rate of approximately 99 percent. This contributed to the additiontotal net additions of 597602 billion cubic feet equivalent (Bcfe) in net reserves — a replacement rate for our domestic production of 216 percent in 2006 compared to 277 percent in 2005.148 percent. Capital expenditures for domestic drilling, development, gathering facilities and acquisition activity in 20062008 were approximately $1.4$2.5 billion compared to approximately $768 million$1.7 billion in 2005. |
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| | |
| | 2007. Capital expenditures for 2008 include acquisitions in the Piceance and Fort Worth basins discussed inSignificant eventsbelow. |
The benefitbenefits of higher net realized average prices and higher production volumes to operating results was more thanwere partially offset by the downward trending of natural gas market prices during the year and increased operating costs. The increase in operating costs reflects an increase in ourwas primarily due to the impact of increased production volumes combinedand prices on operating taxes and higher well service and lease service costs. In addition, higher production volumes coupled with a general industry condition of greater demand for serviceshigher capitalized drilling costs increased depreciation, depletion, and products as production activities increase in our key basins.amortization expense.
Significant events
At December 31, 2006, all ten newstate-of-the-art FlexRig4® drilling rigs have been placed into service pursuantIn January 2008, we sold a contractual right to our lease agreement with Helmerich & Payne. The March 2005 contract provideda production payment on certain future international hydrocarbon production for the operation$148 million. As a result of the drilling rigs, each for a primary lease termcontract termination, we have no further interests associated with the crude oil concession, which is located in Peru. We had obtained these interests through our acquisition of three years. This arrangement supports our continuing objective toBarrett Resources Corporation in 2001.
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accelerate the pace of natural gas developmentIn May 2008, we acquired certain undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin through both deploymentfor $285 million. A third party subsequently exercised its contractual option to purchase, on the same terms and conditions, an interest in a portion of the additional rigs and through the drilling and operational efficiencies of the new rigs.acquired assets for $71 million.
In 2006,September 2008, we increased our position in the Fort Worth basin by acquiring certain undeveloped leasehold acreage and producing properties and undeveloped leasehold interests for approximately $64$147 million. These acquisitions increasedThis acquisition is consistent with our diversification into the Mid-Continent region and will allow us to usegrowth strategy of leveraging our horizontal drilling expertise by acquiring and developing low-risk properties.
Based on our assessment of undiscounted and discounted future cash flows, which considered year-end natural gas reserve quantities, we recorded an impairment of $129 million in December 2008 related to develop wellsour properties in the Barnett Shale formation.Arkoma basin. In September 2008, we recorded a $14 million impairment due to unfavorable drilling results, also in the Arkoma basin.
In December 2008, the Wyoming Supreme Court ruled against us on our appeal of the Wyoming State Board of Equalization’s decision to uphold an assessment by the Wyoming Department of Audit related to severance and ad valorem taxes for the years 2000 through 2002. Related to this decision, we adjusted our estimated liability for the periods from 2000 through 2008, which resulted in a charge of $34 million. (See Note 4 of Notes to Consolidated Financial Statements.)
Outlook for 20072009
OurConsidering the previously discussed significant decline in natural gas prices, we expect segment revenues and segment profit in 2009 to be significantly lower than in 2008. As a result, we plan to reduce capital expenditures and deploy fewer drilling rigs in 2009 compared to 2008 which will reduce the number of wells drilled. We have the following expectations and objectives for 2007 include:2009:
| | |
| | • | MaintainingContinuing our development drilling program in our key basins ofthe Piceance, Fort Worth, Powder River and San Juan Arkoma, and Fort Worthbasins through our planned capital expenditures of $1.3 to $1.4projected between $950 million and $1.05 billion. |
| |
| | • | Continuing to growSlight growth in our domesticannual average daily domestic production level compared to 2008, with a goal of 10fourth quarter 2009 volumes likely to 20 percent annual growth. |
Approximately 172 MMcfe, or 18 percent, of our forecasted 2007 daily production is hedged by NYMEX and basis fixed price contracts at prices that average $3.90 per Mcfe at a basin level. In addition, we have collar agreements for each month in 2007 as follows:
| | |
| • | NYMEX collar agreement for approximately 15 MMcfe per day at a weighted-average floor price of $6.50 per Mcfe and a weighted-average ceiling price of $8.25 per Mcfe.be less than the prior comparable period. |
| |
| | • | Northwest Pipeline/Rockies collar agreementDeclines in the costs of services and materials associated with development activities as demand for approximately 50 MMcfe per day at a floor pricethese resources decline. However, in the first quarter of $5.65 per Mcfe2009, we estimate we will incur between $25 million and a ceiling price of $7.45 per Mcfe at a basin level. |
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| • | El Paso/San Juan collar agreements totaling approximately 130 MMcfe per day at a weighted average floor price of $5.98 per Mcfe and a weighted average ceiling price of $9.63 per Mcfe at a basin level. |
|
| • | Mid-Continent (PEPL) collar agreements totaling approximately 75 MMcfe per day at a weighted average floor price of $6.82 per Mcfe and a weighted average ceiling price of $10.80 per Mcfe at a basin level.$35 million in expense from contract penalties associated with the reduction in drilling rigs deployed. |
We have recently entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Margin requirements, if any, under this new facility are dependent on the level of hedging and on natural gas reserves value.
Additional risksRisks to achieving our expectations include unfavorable natural gas market price movements which are impacted by numerous factors, including weather conditions, at certain of our locations duringdomestic natural gas production levels and demand, and the first and fourth quarters of 2007, drilling rig availability, obtaining permits as planneddownturn in the global economy. A further significant decline in natural gas prices would impact these expectations for drilling, and market price movements.2009.
Year-Over-Year Operating Results
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Millions) | |
| |
| Segment revenues | | $ | 1,487.6 | | | $ | 1,269.1 | | | $ | 777.6 | |
| | | | | | | | | | | | | |
| Segment profit | | $ | 551.5 | | | $ | 587.2 | | | $ | 235.8 | |
| | | | | | | | | | | | | |
2006 vs. 2005
Totalsegment revenuesincreased $218.5 million, or 17 percent, primarily due toIn addition, changes in laws and regulations may impact our development drilling program. For example, the following:Colorado Oil & Gas Conservation Commission has enacted new rules effective in April 2009 which will increase our costs of permitting and environmental compliance and potentially delay drilling permits. The new rules include
| | |
| • | $165 million, or 15 percent, increase in domestic production revenues reflecting $245 million primarily associated with a 23 percent increase in natural gas production volumes sold, offset by a decrease of $80 million associated with a 6 percent decrease in net realized average prices. The increase in production volumes is primarily from the Piceance and Powder River basins and the decrease in prices reflects the downward trending of market prices in the latter part of 2006. |
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additional environmental and operational requirements before permit approvals are granted, tracking of certain chemicals brought on location, increased wildlife stipulations, new pit and waste management procedures and increased notifications and approvals from surface landowners.
| | |
| • | $10 million increase in production revenues from our international operations primarily due to increases in net realized average prices for crude oil production volumes sold. |
|
| • | $14 million of net unrealized gains in 2006 from hedge ineffectiveness and forwardmark-to-market gains on certain basis swaps not designated as hedges as compared to $10 million in net unrealized losses attributable to hedge ineffectiveness from NYMEX collars in 2005. |
Commodity Price Risk Strategy
To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative forward sales contracts that fix the sales price relating to a portion of our future production. Approximately 40 percent of domestic production in 2006 was hedged byusing NYMEX and basis fixed pricefixed-price contracts and collar agreements.
For 2009, we have the following agreements and contracts for our daily domestic production, shown at a weighted average price of $3.82 per Mcfe at a basin level compared to 47 percent hedged at avolumes and basin-level weighted average priceprices:
| | | | | | | | | |
| | | | | | Price ($/Mcf)
| |
| | | Volume
| | | Floor-Ceiling for
| |
| | | (MMcf/d) | | | Collars | |
| |
| Collar agreements — Rockies | | | 150 | | | $ | 6.11 - $9.04 | |
| Collar agreements — San Juan | | | 245 | | | $ | 6.58 - $9.62 | |
| Collar agreements — Mid-Continent | | | 95 | | | $ | 7.08 - $9.73 | |
| NYMEX and basis fixed-price | | | 106 | | | | $3.67 | |
The following is a summary of $3.99 per Mcfeour agreements and contracts for daily production for the years ended December 31, 2008, 2007 and 2006:
| | | | | | | | | | | | | |
| | | 2008 | | 2007 | | 2006 |
| | | | | Price ($/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 |
| |
| Collars — NYMEX | | — | | — | | 15 | | $6.50 - $8.25 | | 49 | | $6.50 - $8.25 |
| Collars — NYMEX | | — | | — | | — | | — | | 15 | | $7.00 - $9.00 |
| Collars — Rockies | | 170 | | $6.16 - $9.14 | | 50 | | $5.65 -$7.45 | | 50 | | $6.05 - $7.90 |
| Collars — San Juan | | 202 | | $6.35 - $8.96 | | 130 | | $5.98 - $9.63 | | — | | — |
| Collars — Mid-Continent | | 63 | | $7.02 - $9.72 | | 76 | | $6.82 -$10.77 | | — | | — |
| NYMEX and basis fixed-price | | 70 | | $3.97 | | 172 | | $3.90 | | 299 | | $3.82 |
Additionally, we utilize contracted pipeline capacity through Gas Marketing to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We also expect additional pipeline capacity to be put into service in 2005. In addition, approximately 15 percent of domestic production was hedged by2009.
Year-Over-Year Operating Results
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (Millions) | |
| |
| Segment revenues | | $ | 3,121 | | | $ | 2,021 | | | $ | 1,411 | |
| | | | | | | | | | | | | |
| Segment profit | | $ | 1,260 | | | $ | 756 | | | $ | 552 | |
| | | | | | | | | | | | | |
2008 vs. 2007
The increase in totalsegment revenuesis primarily due to the following collar agreements in 2006:following:
| | |
| | • | NYMEX collar agreement$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, |
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| | |
| | 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 approximately 49 MMcfe per day atgas management activities related to gas sold on behalf of certain outside parties, which is substantially offset by a floor price of $6.50 per Mcfesimilar increase insegment costs and a ceiling price of $8.25 per Mcfe.expenses. This increase is primarily due to increases in natural gas prices and volumes sold. |
| |
| | • | NYMEX collar agreement for approximately 15 MMcfe per day at a floor price of $7.00 per Mcfe and a ceiling price of $9.00 per Mcfe. |
|
| • | Northwest Pipeline/Rockies collar agreement for approximately 50 MMcfe per day at a floor price of $6.05 per Mcfe and a ceiling price of $7.90 per Mcfe at a basin level.$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. |
In 2005, approximately 10 percent of domestic production was hedged by a NYMEX collar agreement for approximately 50 MMcfe per day at a floor price of $7.50 per Mcfe and a ceiling price of $10.49 per Mcfe in the first quarter and at a floor price of $6.75 per Mcfe and a ceiling price of $8.50 per Mcfe in the second, third, and fourth quarters, and a Northwest Pipeline/Rockies collar agreement for approximately 50 MMcfe per day in the fourth quarter at a floor price of $6.10 per Mcfe and a ceiling price of $7.70 per Mcfe.
Our hedges are executed with our Power Totalsegment which, in turn, executes offsetting derivative contracts with unrelated third parties. Generally, Power bears the counterparty performance risks associated with unrelated third parties. Hedging decisions are made considering our overall commodity risk exposure and are not executed independently by Exploration & Production.
Totalcosts and expensesincreased $257$591 million, primarily due to the following:
| | |
| | • | $107202 million higher depreciation, depletion and amortization expense primarily due to higher production volumes and increased capitalized drilling costs;costs. |
| |
| | • | $54149 million higher lease operating expense primarily due to the increased number of producing wells and higher well service and industry costs due to increased demand and approximately $6 millionincrease in expenses forout-of-period expenses gas management activities related to 2005. Our management has concluded that the effectgas purchased on behalf of this itemcertain outside parties, which is not material to our consolidated results for 2006, or prior periods, or to our trend of earnings;offset by a similar increase insegment revenues. |
| |
| | • | $19143 million higher operating taxes primarily due to higher production volumes sold and increased tax rates;of property impairments in 2008 in the Arkoma basin as previously discussed. |
| |
| | • | $33118 million higher selling, generaloperating taxes primarily due to both higher average market prices and administrativehigher 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 higher compensation for additionalincreased staffing in support of increased drilling and operational activity. In addition, we incurredactivity, including higher legal, insurance, and information technology support costs related to the increased activity;compensation. The higher SG&A expenses also include an increase of $11 million in bad debt expense. |
| |
| | • | The absence in 2006 of $29.6$17 million higher gathering expenses due to higher domestic production volumes. |
|
| • | $17 million of gains onexpense in 2008 related to the saleswrite-off of properties in 2005.certain exploratory drilling costs for our domestic and international operations. |
These increases are partially offset by the $148 million gain associated with the previously discussed sale of our Peru interests in 2008.
The $35.7$504 million decreaseincrease in segment profitis primarily due to lowerthe 28 percent increase in domestic net realized average prices and highercosts and expensesas discussed previously, and the absence in 2006 of $29.6 million of gains on the sales of properties in 2005. Partially offsetting these decreases are a 2320 percent increase in domestic production volumes sold, and anpartially offset by the increase in income from ineffectivenesstotalsegment costs and forward mark-to-market gains.expenses.
Segment profit2007 vs. 2006also includes an $8 million
The increase in our international operationstotalsegment revenuesis primarily due to higher revenue and equity earnings as a result of increases in net realized average prices for crude oil production volumes sold.the following:
| | |
| • | $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 insegment costs and expenses. |
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2005 vs. 2004
The $491.5These increases were partially offset by a $30 million or 63 percent increase insegment revenuesis primarilyunfavorable change related to hedge ineffectiveness due to an increase in domestic production revenues of $434 million during 2005 reflecting higher net realized average prices and higher production volumes sold. Also contributing to the increase is a $58 million increase in revenues from gas management activities, offset incosts and expenses, and $13 million increased production revenues from our international operations. Partially offsetting these increases is $10$16 million in net unrealized losses attributable to NYMEX collars from hedge ineffectiveness.
The increaseineffectiveness in domestic production revenues primarily results from $3192007 compared to $14 million higher revenues associated with a 42 percent increase in net realized average prices for production sold as well as a $115 million increase associated with an 18 percent increaseunrealized gains in average daily production volumes. The higher net realized average prices reflect the benefit of the lower volumes hedged in 2005 as compared to 2004 coupled with higher market prices for natural gas in 2005. The increase in production volumes primarily reflects an increase in the number of producing wells resulting from our successful 2005 drilling program.
Approximately 77 percent of domestic production in 2004 was hedged at a weighted average price of $3.65 per Mcfe at a basin level.2006.
Totalsegment costs and expensesincreased $147$409 million, primarily due to the following:
| | |
| | • | $62173 million higher depreciation, depletion and amortization expense primarily due to higher production volumes and increased capitalized drilling costs;costs. |
| |
| | • | $16144 million higher lease operating expense from the increased numberincrease in expenses for gas management activities related to gas purchased on behalf of producing wells and generally higher industry costs;certain outside parties which is offset by a similar increase insegment revenues. |
| |
| | • | $2346 million higher lease operating taxesexpenses from the increased number of producing wells primarily due to increased market priceswithin the Piceance, Powder River, and production volumes sold;Fort Worth basins in combination with higher well service expenses, facility expenses, equipment rentals, maintenance and repair services, and salt water disposal expenses. |
| |
| | • | $1836 million higher selling, general and administrativeSG&A expensesprimarily due to higher compensation and increased staffing in 2005 in support of increased drilling and operational activity; |
|
| • | $58activity, 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 higher gas managementof expenses associated with higher revenues from gas management activities, offseta correction of costs incorrectly capitalized insegment revenues; |
|
| • | $11 million lower gain in 2005 than in 2004 on the sale of securities associated with our coal seam royalty trust that were previously purchased for resale. prior periods. |
These increasedcosts and expensesare partially offset by the absence in 2005 of a $15.4 million loss provision related to an ownership dispute on prior period production in 2004, a $7.9 million gain on the sale of an undeveloped leasehold position in Colorado in the first quarter of 2005, and a $21.7 million gain on the sale of certain outside operated properties in the Powder River basin area of Wyoming in the third quarter of 2005.
The $351.4$204 million increase in segment profitis primarily due to increased revenues from higherthe 21 percent increase in domestic production volumes and highersold as well as the 15 percent increase in net realized average prices, as well as the gains on sales of assets, partially offset by higher expenses as discussed above.Segment profitalso includes a $19 millionthe increase in our international operations reflecting higher revenuesegment costs and equity earnings resulting from higher net realized oil and gas prices.expenses.
Gas Pipeline
Overview
We operate, through our Northwest Pipeline and Transco subsidiaries, approximately 14,400 miles of pipeline from the Gulf Coast to the northeast United States and from northern New Mexico to the Pacific Northwest with a total annual throughput of approximately 2,500 trillion BTUs. Additionally, we hold a 50 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). This asset, which extends from the Mobile Bay area in Alabama to markets in Florida, has current transportation capacity of 1.1 MMdt/d.
OurPipeline’s strategy to create value for our shareholders focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.
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Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates. As a result, the recent decline in energy commodity prices has not significantly impacted our results of operations.
Significant events of 20062008 include:
FilingGas Pipeline master limited partnership
In 2008, Williams Pipeline Partners L.P. completed its initial public offering. We own approximately 47.7 percent of the interests, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. We consolidate Williams Pipeline Partners L.P. within our Gas Pipeline segment due to our control through the general partner. (See Note 1 of Notes to Consolidated Financial Statements.) Gas Pipeline’s segment profit includes 100 percent of Williams Pipeline Partners L.P.’s segment profit with the minority interest’s share presented below segment profit.
Status of rate casescase
During 2006, Northwest Pipeline and Transco each filed a general rate casescase with the FERC fordesigned to recover increases in rates due to higher costs in recent years.costs. The new rates arewere effective, subject to refund, on March 1, 2007. On November 28, 2007, Transco filed a formal stipulation and agreement with the FERC resolving all substantive issues in January 2007 for Northwest Pipeline and in March 2007 for Transco. We expect the new rates to result in significantly higher revenues.
In January 2007, Northwest Pipeline reached a settlement in itstheir pending 2006 rate case. On March 7, 2008, the
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FERC approved the agreement without modification. The settlement is subject to FERC approval, which is expected by mid-2007.agreement became effective June 1, 2008 and required refunds were issued in July 2008.
GulfstreamHurricane Ike
In March 2006,September 2008, Hurricane Ike impacted several onshore and offshore facilities on Transco’s interstate natural gas pipeline system resulting in varying degrees of damage. However, Transco has continued to meet its customer commitments while running at lower-than-normal volumes. We expect the majority of associated costs will be recoverable through insurance, with the remainder recoverable through Transco’s rates. We also expect the premiums for insuring our assets in the Gulf of Mexico region against weather events to significantly increase in 2009.
Gulfstream Phase III expansion project
In June 2007, our equity method investee, Gulfstream announced a new long-term agreement with a Florida utility company, which fully subscribed the pipeline’s mainline capacity on a long-term basis. Under the agreement, Gulfstream willNatural Gas System, L.L.C. (Gulfstream), received FERC approval to extend its existing pipeline approximately 3534 miles within Florida. Construction began in April 2008 and the expansion was placed into service in September 2008. The agreementextension fully subscribed the remaining 345 Mdt/d of firm capacity on the existing pipeline. Gulfstream’s estimated cost of this project is subject to the approval of various authorities. Construction of the extension is anticipated to begin in early 2008 with a targeted completion of summer 2008.$118 million.
Gulfstream Phase IV expansion project
In May 2006,September 2007, Gulfstream announced a new agreement to provide 155 Mdt/d of natural gas to a Florida utility. In December 2006, Gulfstream filed an application with thereceived FERC seeking approval to expand its pipeline system to provide the additional capacity. Under this agreement, Gulfstream will construct approximately 17.517.8 miles of 20 inch20-inch pipeline and the installation ofto install a new compressor facility. If approved, all of the facilities will beConstruction began in December 2007. The pipeline expansion was placed into service byin the fourth quarter of 2008, and the compressor facility was placed into service in January 2009. The expansion increased capacity by 155 Mdt/d. Gulfstream’s estimated cost of this project is $192 million.
Parachute LateralSentinel expansion project
In August 2006,2008, we received FERC approval to construct a37.6-milean expansion that will provide additional natural gas transportation capacity in northwest Colorado.the northeast United States. The planned expansion will increase capacity by 450 Mdt/d throughcost of the30-inch diameter line and project is estimated to cost approximately $86be up to $200 million. The expansionWe placed Phase I into service in December 2008 increasing capacity by 40 Mdt/d. Phase II will provide an additional 102 Mdt/d and is expected to be inplaced into service in March 2007.by November 2009.
Grays Harbor
Effective January 2005, Duke Energy Trading and Marketing, LLC (Duke) terminated its firm transportation agreement related to Northwest Pipeline’s Grays Harbor lateral. In January 2005, Duke paid Northwest Pipeline $94 million for the remaining book value of the asset and the related income taxes. We and Duke have not agreed on the amount of the income taxes due Northwest Pipeline as a result of the contract termination. We have deferred the $6 million difference between the proceeds and net book value of the lateral pending resolution of the disputed early termination obligation.
On June 16, 2005, we filed a Petition for a Declaratory Order with the FERC requesting that it rule on our interpretation of our tariff to aid in resolving the dispute with Duke. On July 15, 2005, Duke filed a motion to intervene and provided comments supporting its position concerning the issues in dispute.
On October 4, 2006, the FERC issued its Order on Petition for Declaratory Order, providing clarification on issues relating to Duke’s obligation to reimburse us for future tax expenses. We reviewed the Order and filed a request for rehearing requesting further clarification of certain items. Based upon the order, as written, we do not anticipate any adverse impact to our results of operations or financial position.
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Northwest Pipeline capacity replacementColorado Hub Connection project
In September 2005, we received FERC approval to construct and operate approximately 80 miles of36-inch pipeline loop as a replacement for most of the capacity previously served by 268 miles of26-inch pipeline in the Washington state area. The capacity replacement as well as the abandonment of the old capacity was completed in December 2006. In addition to the capacity replacement, five existing compressor stations were modified, and we increased net horsepower.
Outlook for 2007
Leidy to Long Island expansion project
In May 2006, we received FERC approval to expand Transco’s natural gas pipeline in the northeast United States. The estimated cost of the project is approximately $141 million with three-quarters of that spending expected to occur in 2007. The expansion will provide 100 Mdt/d of incremental firm capacity and is expected to be in service by November 2007.
Potomac expansion project
In July 2006,2008, we filed an application with the FERC to expand Transco’s existing facilities inconstruct a27-mile pipeline to provide increased access to the Mid-Atlantic region of the United States by constructing 16.5 miles of42-inch pipeline. The project will provide 165 Mdt/d of incremental firm capacity.Rockies natural gas supplies. The estimated cost of the project is approximately $74$60 million with an anticipated in-service dateservice targeted to commence in November 2009. We will combine the lateral capacity with 341 Mdt/d of November 2007.existing mainline capacity from various receipt points for delivery to Ignacio, Colorado, including approximately 98 Mdt/d of capacity that was sold on a short-term basis.
Outlook for 2009
In addition to the Gulfstream Phase IV compressor facility, Phase II of the Sentinel expansion project, and the Colorado Hub Connection project previously discussed, we have several other proposed projects to meet customer demands. Subject to regulatory approvals, construction of some of these projects could begin as early as 2009.
Year-Over-Year Operating Results
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Segment revenues | | $ | 1,347.7 | | | $ | 1,412.8 | | | $ | 1,362.3 | | | $ | 1,634 | | | $ | 1,610 | | | $ | 1,348 | |
| | | | | | | | | |
| Segment profit | | $ | 467.4 | | | $ | 585.8 | | | $ | 585.8 | | | $ | 689 | | | $ | 673 | | | $ | 467 | |
| | | | | | | | | |
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Significant 2005 adjustments
Operating results for 2005 included:
| | |
| • | Adjustments of $17.7 million reflected as a $12.1 million reduction ofcosts and operating expenses and a $5.6 million reduction ofSG&A expenses. These cost reductions were corrections of the carrying value of certain liabilities that were recorded in prior periods. Based on a review by management, these liabilities were no longer required. |
|
| • | Pension expense reduction of $17.1 million in the second quarter of 2005 to reflect the cumulative impact of a correction of an error attributable to 2003 and 2004. The error was associated with our third-party actuarial computation of annual net periodic pension expense and resulted from the identification of errors in certain Transco participant data involving annuity contract information utilized for 2003 and 2004. |
|
| • | Adjustments of $37.3 million reflected as increases incosts and operating expenses related to $32.1 million of prior period accounting and valuation corrections for certain inventory items and an accrual of $5.2 million for contingent refund obligations. |
Our management concluded that the effects of these adjustments were not material to our consolidated results for 2005 or prior periods, or to our trend of earnings.
20062008 vs. 20052007
RevenuesSegment revenuesdecreased $65.1increased $24 million, or 51 percent, due primarily to $75a $52 million lowerincrease in transportation revenues associated with exchangeresulting primarily from Transco’s new rates, which were effective March 2007, and expansion projects that Transco placed into service in the fourth quarter of 2007. In addition,segment revenuesincreased $28 million due to transportation imbalance settlements (offset incosts and operating expenses). Partially offsetting this decreasethese increases is the absence of $59 million associated with a $9 million increase in revenue due to an adjustment for the recovery2007 sale of state income tax rate changesexcess inventory gas (offset inprovision for income taxescosts and operating expenses).
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Costs and operating expensesdecreased $11 million, or 1 percent, due primarily to the absence of $59 million associated with a 2007 sale of excess inventory gas (offset insegment revenues). The decrease is partially offset by an increase in costs of $28 million associated with transportation imbalance settlements (offset insegment revenues) and higher rental expense related to the Parachute lateral that was transferred to Midstream in December 2007.
Other income —netchanged unfavorably by $31 million due primarily to the absence of $18 million of income recognized in 2007 associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral and the absence of $17 million of income recorded in 2007 for a change in estimate related to a regulatory liability at Northwest Pipeline. In addition, project development costs were $21 million higher in 2008. Partially offsetting these unfavorable changes is a $10 million gain in 2008 on the sale of certain south Texas assets by Transco and a $9 million gain in 2008 on the sale of excess inventory gas.
The $16 million, or 2 percent, increase insegment profitis due primarily to:to the favorable changes in segment revenues and costs and operating expenses as well as slightly higher equity earnings from Gulfstream. These increases are partially offset by the unfavorable change inother income— net.
| | |
| • | A decrease in costs of $75 million associated with exchange imbalance settlements (offset inrevenues); |
|
| • | A decrease in costs of $37.3 million related to the absence of $32.1 million of 2005 prior period accounting and valuation corrections for certain inventory items and an accrual of $5.2 million for contingent refund obligations. |
Partially offsetting these decreases are:
| | |
| • | An increase in contract and outside service costs of $23 million due primarily to higher pipeline assessment and repair costs; |
|
| • | An increase in depreciation expense of $15 million due to property additions; |
|
| • | An increase in operating and maintenance expenses of $15 million; |
|
| • | An increase in operating taxes of $10 million; |
|
| • | The absence of $14.2 million of income in 2005 associated with the resolution of litigation; |
|
| • | The absence of $12.1 million of expense reductions during 2005 related to the carrying value of certain liabilities. |
SG&A2007 vs. 2006
Revenuesincreased $262 million, or 19 percent, due primarily to a $173 million increase in transportation revenues and a $25 million increase in storage revenues resulting primarily from new rates effective in the first quarter of 2007. In addition, revenues increased $59 million due to the sale of excess inventory gas.
Costs and operating expensesincreased $77$86 million, or 9211 percent, due primarily to:
| | |
| | • | An increase in personnel costs of $18 million; |
|
| • | The absence$59 million associated with the sale of a 2005 $17.1 million reduction in pension costs to correct an error in prior periods;excess inventory gas; |
| |
| | • | An increase in information systems support costsdepreciation expense of $16 million;$30 million due to property additions; |
| |
| | • | An increase in property insurance expensespersonnel costs of $14 million; |
|
| • | The absence$10 million due primarily to higher compensation as well as an increase in number of $5.6 million of cost reductions in 2005 that related to correcting the carrying value of certain liabilities.employees. |
Partially offsetting these increases is a decrease of $12 million in contract and outside service costs and a decrease of $7 million in materials and supplies expense.
Other (income) expense —netchanged favorably by $15 million due primarily to $18 million of income associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral. Also included in the favorable change is $17 million of income recorded in the second quarter of 2007 for a change in estimate related to a regulatory liability at Northwest Pipeline, partially offset by $18 million of expense related to higher asset retirement obligations.
Equity earnings increased $14 million due primarily to a $14 million increase in equity earnings from Gulfstream. Gulfstream’s higher earnings were primarily due to a decrease in property taxes from a favorable litigation outcome as well as improved operating results.
The $118.4$206 million, or 2044 percent, decreaseincrease insegment profitis due primarily to the absence of significant 2005 adjustments $262 million higher revenues, $14 million higher equity earnings and $15 million favorableother (income) expense — netas previously discussed,discussed. Partially offsetting these increases inare highercosts and operating expensesandSG&A expensesas previously discussed, and the absence of a $4.6 million construction completion fee recognized in 2005 related to our investment in Gulfstream.discussed.
2005 vs. 2004
The $50.5 million, or 4 percent, increase in Gas Pipelinerevenuesis due primarily to $86 million higher revenues associated with exchange imbalance cash-out settlements (offset incosts and operating expenses). Partially offsetting this increase is $24 million lower transportation revenues due primarily to the termination of the Grays Harbor contract, and $11 million lower revenues associated with reimbursable costs, which are passed through to customers (offset incosts and operating expensesandSG&A expenses).
Costs and operating expensesincreased $109 million, or 16 percent, due primarily to:
| | |
| • | An increase in costs of $86 million associated with exchange imbalances (offset inrevenues); |
|
| • | The increase in costs of $32.1 million due to prior period accounting and valuation corrections related to inventory, as previously discussed; |
|
| • | An increase in operating and maintenance expense of $14 million due primarily to increased contract service costs, materials and supplies and rental fees; |
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| • | The increase in costs of $5.2 million due to an accrual for contingent refund obligations, as previously discussed. |
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Partially offsetting these increases are decreases due to:
| | |
| • | Income of $14.2 million associated with the resolution of the litigation related to recovery of gas costs; |
|
| • | The cost reduction of $12.1 million due to adjusting the carrying value of certain liabilities, as previously discussed; |
|
| • | Lower reimbursable costs of $5 million (offset inrevenues). |
SG&A expensesdecreased approximately $38 million, or 31 percent, due to the $17.1 million reduction in pension costs to correct a prior period error, $6 million lower reimbursable costs (offset inrevenues), and the reversal of $5.6 million of prior period accruals.
Comparativesegment profitis unchanged from 2004. The following are significant components of 2005 segment profit:
| | |
| • | The reduction in pension costs of $17.1 million to correct a prior period error, as previously discussed; |
|
| • | An increase in Gulfstream equity earnings of $14 million due to the realization of a $4.6 million construction fee award on the completion of the Phase II expansion project coupled with increased revenues associated with the Gulfstream expansions; |
|
| • | Income of $14.2 million from the reversal of the contingency related to recovery of gas costs; |
|
| • | The $17.7 million reversal of prior period accruals; |
|
| • | The increase in costs of $32.1 million due to prior period accounting and valuation corrections related to inventory; |
|
| • | An increase in operating and maintenance expense of $14 million due primarily to increased contract service costs, materials and supplies and rental fees; |
|
| • | A decrease in transportation revenue of $24 million due primarily to the termination of the Grays Harbor contract. |
Midstream Gas & Liquids
Overview of 20062008
Midstream’s ongoing strategy is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive lowper-unit costs. Our business is focusedWe focus on consistently attracting new business by providing highly reliable service to our customers.
Significant events during 2006 included2008 include the following:
In the first three quarters of 2008, segment revenues and segment profit improved considerably compared to 2007. However, these results were followed by a steep decline in the fourth quarter due to a rapid decline in NGL and olefin prices. Compared to the prior year, our combined margins associated with the production and marketing of NGLs declined 70 percent in the fourth quarter and 15 percent for the year. Compared to the prior year, our combined margin from our olefin production and marketing business unit declined 81 percent in the fourth quarter and 18 percent for the year. The ongoing impact of sustained lower commodity prices is discussed further in the following Outlook for 2009 section.
FavorableVolatile commodity price marginsprices
The actual realizedDomestic Gathering and Processing Per-Unit NGL per unitMargin with Production and
Sales Volumes by Quarter
(excludes partially owned plants)
During the first three quarters of 2008, strongper-unit NGL margins at our processing plants exceeded Midstream’s rolling five-year average for the last four quarters. The geographic diversification of Midstream assetsdriven by higher crude prices, which impact NGL prices, in relationship to natural gas prices contributed significantly to our actual realized unitmargins. During the fourth quarter, NGL and natural gas prices, along with most other energy commodities, were significantly impacted by the weakening economy and experienced a sharp decline. Although average annual natural gas prices increased from 2007 to 2008, we continued to benefit from favorable gas price differentials in the Rocky Mountain area which contributed to realizedper-unit margins resulting in marginsthat were generally greater than that of the industry benchmarks for gas processed in the Henry Hub area and for liquids fractionated and sold at Mont Belvieu. The largest impact wasBelvieu, Texas.
Our average realized NGLper-unit margin at our western United States gas processing plants which benefited from lower regional market natural gas prices. During 2006,during 2008 was 61 cents per gallon (cpg), compared to 55 cpg in 2007. The increase in our NGL production rebounded from levels experiencedper-unit margin is partially due to a change in fourth-quarter 2005the mix of NGL products sold. Due to third-party NGL pipeline capacity restrictions during the third quarter of 2008 and to unfavorable ethane economics in response to improved gas processing spreads as crude prices, which correlate to NGL prices, averaged $66 per barrel and natural gas prices decreased.the fourth quarter of 2008, we reduced our recoveries of ethane in those periods.
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Because we typically realize lowerDomestic Gatheringper-unit margins for ethane versus other NGLs, if we had produced the same mix of ethane and Processing Per Unitnon-ethane NGLs during 2008 as we generally have in prior years, the averageper-unit margin in 2008 would have been lower. NGL Margin with Productionmargins have exceeded our rolling five-year average for the last seven quarters, in spite of strong NGL margins in 2007 and
Sales Volumes by Quarter
(excludes partially owned plants)
Expansion efforts in growth areas
Consistent with early 2008 that have significantly increased our strategy, we continued to expand our midstream operations where we have large-scale assets in growth basins.
We continued constructionrolling five-year average from 26 cpg at our existing gas processing plant located near Opal, Wyoming, to add a fifth cryogenic train capablethe end of processing up to 350 MMcf/d, bringing total Opal capacity to approximately 1,450 MMcf/d. This plant expansion is being placed into service during the first quarter of 2007 to begin processing gas from37 cpg at the Pinedale Anticline field.
Also, we continued construction on a37-mile extension of our oil and gas pipelines from our Devils Tower spar to the Blind Faith prospect located in Mississippi Canyon. This extension, estimated to cost approximately $200 million, is expected to be ready for service by the second quarterend of 2008.
NGL margins are defined as NGL revenues less BTU replacement cost, plant fuel, transportation and fractionation.Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our domestic gathering and processing plants recognize NGL margins on our NGL equity volumes based upon market-based transfer prices to our NGL marketing business. The NGL marketing business transports and markets those equity volumes, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes produced by Discovery Producer Services L.L.C. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points, as well as the impact of lower of cost or market write-downs on ending inventory balances.
NGL marketing margins impacted by sharp decline in prices
In May 2006, we entered into an agreementlate 2007, the NGL marketing business sold the majority of our equity volumes in the West region to develop newa third-party directly from the plants, which reduced our average inventory levels in the latter part of 2007. In early 2008, our NGL marketing business began to transport these volumes on a third-party pipeline capacity for transporting natural gas liquids from production areas in southwestern Wyoming to central Kansas. The other partysale at downstream markets, which increased our inventory levels. Inventory volumes also increased during 2008 due to the agreement reimbursedpreviously discussed hurricane-related suspension of operations at a third-party fractionation facility at Mont Belvieu, Texas.
During 2006 and 2007, NGL price changes did not significantly affect in-transit inventory values. However in 2008 due to significantly and rapidly declining NGL prices, primarily during the fourth quarter, combined with higher average inventory levels, our NGL marketing business experienced a marketing loss of $78 million.
NGL sales volume constrained
Primarily during the third quarter of 2008, we experienced restrictions on the volume of NGLs we could deliver to third-party pipelines in our West region. These restrictions were caused by a lack of third-party NGL pipeline transportation capacity which resulted in us forreducing our recovery of ethane to accommodate these restrictions. In the development costsfourth quarter of 2008, these restrictions were alleviated as we incurredwere able to date for the proposed pipeline and initially will own 99 percent of the pipeline, known as Overland Pass Pipeline Company, LLC. We retained a 1 percent interest and have the option to increase our ownership to 50 percent and become the operator within two years of the pipeline becoming operational.Start-up is planned for early 2008. Additionally, we have agreed to dedicate our equitydeliver NGL volumes from our two Wyoming plants into the new Overland Pass NGL pipeline.
Due to unfavorable ethane economics during the fourth quarter of 2008, we elected to temporarily suspend ethane recoveries at certain plants which further reduced our NGL sales volumes. While reducing the recovery of ethane did benefit our overall average realized NGLper-unit margins as previously described, it negatively impacted our NGL volumes and operating profit.
Hurricanes Gustav and Ike
As a result of Hurricanes Gustav and Ike in September 2008, not only did our Gulf Coast region facilities experience reduced volumes and damage, but our West region was also negatively impacted. We estimate that our segment profit for transport under2008 was decreased by approximately $60 million to $85 million due to downtime and charges for repairs and property insurance deductibles associated with Hurricanes Gustav and Ike. Other than the Cameron Meadows natural gas processing plant and the Discovery offshore gathering system, our major gathering and processing assets in the Gulf of Mexico returned to full operations by the end of the third quarter. The Cameron Meadows plant sustained significant damage from Hurricane Ike. Operations are suspended while we evaluate the timing and extent of the required repairs. The Discovery offshore system, which we operate and own a long-term shipping agreement.60 percent equity interest in, also sustained hurricane damage and was not accepting offshore gas from producers while repairs were being made. The terms represent significant savings comparedmainline of the Discovery offshore system was repaired and returned to service in January 2009. In the West region, we had to store NGL inventories due to the hurricane-related suspension of operations at a third-party fractionation facility at Mont Belvieu, Texas. A portion of this inventory was sold in the fourth quarter of 2008, and we expect to sell the remaining excess inventory in 2009. While we expect business interruption insurance to largely mitigate any losses associated with outages beyond 60 days, the existing tariff and other alternatives considered.timing to resolve these claims
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is uncertain. We expect the cost of insuring our assets in the Gulf Coast region against weather events to significantly increase in 2009.
Williams Partners L.P. acquires Four Corners gathering and processing business
In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. closed a $150 million private debt offering of senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. closed a $600 million private debt offering of senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan basin in Colorado and New Mexico.
We currently own approximately 22.523.6 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us. Considering the presumption of control of the general partner in accordance
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with EITF IssueNo. 04-5,us, and incentive distribution rights. We consolidate Williams Partners L.P. is consolidated within the Midstream segment.segment due to our control through the general partner. (See Note 1 of Notes to Consolidated Financial Statements.) Midstream’s segment profit includes 100 percent of Williams Partners L.P.’s segment profit, with the minority interest’s share deductedpresented below segment profit. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively.
Gulf Coast operations return to normal after 2005’s hurricanes
In 2005, Hurricanes Dennis, Katrina and Rita caused temporary shut-downs of most of our facilities and our producers’ facilities in the Gulf Coast region, which reduced product flows in the second half of 2005. Our major facilities resumed normal operations shortly after the passage of each hurricane except for our Devils Tower spar which returned to service in early November 2005 and our Cameron Meadows gas processing plant which returned to partial service in February 2006 and achieved full service in January 2007. Generally, overall product flows returned to pre-hurricane levels during the first quarter of 2006.
Gulf Liquids litigation
We recorded pre-tax charges totalling $94.7 million resulting from jury verdicts in civil litigation. (See Note 15 of Notes to Consolidated Financial Statements.) These charges reflect our estimated exposure for actual damages of $72.7 million, including estimated legal fees of $4.7 million, and potential pre-judgment interest of $22 million. Midstream Other segment profit reflects the $72.7 million charge for the estimated actual damages and legal fees. The matter is related to a contractual dispute surrounding construction in 2000 and 2001 of certain refinery off-gas processing facilities by Gulf Liquids. In addition, it is reasonably possible that any ultimate judgment may include additional amounts of $199 million in excess of our accrual, which represents our estimate of potential punitive damage exposure under Texas law. The jury verdicts are subject to trial and appellate court review. Entry of a judgment in the trial court is expected in the second or third quarter of 2007. If the trial court enters a judgment consistent with the jury’s verdicts against us, we will seek a reversal through appeal.
Outlook for 20072009
The following factors could impact our business in 2007 and beyond.2009.
Commodity price changes
| | |
| | • | As evidenced in recent years, natural gas and crude oil markets are highly volatile. NGL margins earned at our gas processing plants in the last four quarters were above our rolling five-year average, due to global economics maintaining high crude prices which correlate to strong NGL prices in relationship to natural gas prices. Forecasted domestic demand for ethylene and propylene, whose feedstock are ethane and propane, along with political instability in many of the key oil producing countries will continue to support unit margins in 2007 exceeding our rolling five-year average. We do not expect to achieve the record levels we experienced in 2006. |
|
| • | Margins in our NGL and olefins unitbusiness are highly dependent upon continued economic growthdemand within the U.S.global economy. NGL products are currently the preferred feedstock for ethylene and any significantpropylene 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 the economy woulddomestic and global economies could further reduce the demand for the petrochemical products we produce in both Canada and the U.S. Based onUnited States. |
|
| • | As evidenced by recent marketevents, NGL, crude and natural gas prices are highly volatile. NGL price forecasts,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 lowerper-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 suchper-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 unit marginsproduction business for the 2009 year to be slightly lower than 2006below 2008 levels. |
| |
| | • | Gathering andFee-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 revenues at our facilities are expectedcontracts contain provisions that allow customers to be atperiodically elect processing services on either a fee-basis or above levels of previous years duea keep-whole or percent-of-liquids basis. If customers switch from keep-whole to continued strong drilling activitiesfee-based processing, we expect a reduction in our core basins.NGL equity sales volumes in 2009 compared to 2008. |
Gathering and processing volumes
| | |
| | • | Revenues from deepwater production areas are often subject to risks associated with the interruption and timing of product flows which can be influenced by weather and other third-party operational issues. |
|
| • | We will continue to invest in facilities in the growth basins in which we provide services. We expect continued expansion ofNatural gas supplies supporting our gathering and processing systemsvolumes 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 Gulf Coastgathered volumes and West regions to keep pace with increased demandvolumes available for our services.both fee-based and keep-whole processing. |
| |
| | • | We expect continued growthhigher fee revenues, depreciation and operating expenses in our Gulf Coast region as our Devils Tower infrastructure expansions serving the deepwater areas of the Gulf of Mexico to contribute to,Blind Faith and becomeBass Lite prospects move into a larger component of, our future segment revenues and segment profit. We expect these additional fee-full |
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| | |
| | | based revenuesyear 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 our proportionate exposurevolumes in other Gulf Coast areas due to commodity price risks. We expect revenues fromnatural declines. |
Allocation of capital to expansion projects
Given the current economic conditions and the volatility of the commodity price environment, we will continually prioritize and balance our capital expenditures against the demand for our services.
Completed expansion projects
| | |
| • | In the eastern deepwater production areas to decrease as volumes decline in 2007 and increase in 2008 asof the extensionGulf of Mexico, we completed construction of37-mile extensions of both of our oil and gas pipelines from our Devils Tower spar to the Blind Faith prospect is placed into service.located in Mississippi Canyon. The pipelines have been commissioned and production began flowing in the fourth quarter of 2008. |
Ongoing commitments
| | |
| | • | In 2007 we will begin construction on our Perdido Norte project which includes oil and gas lines that expand the scale of our existing infrastructure in the western deepwater of the Gulf of Mexico. Additionally,Mexico, we expect to spend $205 million on our major expansion projects in 2009, including the Perdido Norte project, which will be expandinginclude 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 adequately serve this new gas production. The project is estimatedbegin contributing to cost approximately $480 million and be in service inour segment profit at the third quarterend of 2009. |
| |
| | • | WeIn 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. |
Other factors for consideration
| | |
| • | The current economic and commodity price environment may cause financial difficulties for certain of our customers. Many of our marketing counterparties are currently negotiating with our customer in Venezuela to resolve approximately $14 million in past due invoices related to labor escalation charges. The customer is not disputing the index used to calculate these charges and we have calculatedpetrochemicals industry, which has been under severe stress from the charges according to the terms of the contract. The customer does, however, believe the index has resulted in a disproportionate escalation over time. We believe the receivables, net of associated reserves, are fully collectible.current economic downturn. Although we believeactively manage our negotiations will be successful, failure to resolve this matter could ultimately trigger default noncompliance provisionscredit exposure through certain collateral or payment terms and arrangements, continued economic downturn may result in the services agreement.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 government continues its public criticism of U.S. economicoil industry and political policy, has implemented unilateral changes to existing energy related contracts, continues to publicly declare that additional energy contracts will be unilaterally amended, and that privately held assets will be expropriated, indicating that a level of political risk still remains.thereby unfavorably impact all service providers, including us. |
In addition, the economic situation resulting from lower commodity prices may further exacerbate political tension in Venezuela. The Venezuelan government continues its public criticism of U.S. economic and political policy, has implemented unilateral changes to existing energy related contracts, and has expropriated privately held assets within the energy and telecommunications sector. The continued threat of nationalization of certain energy-related assets in Venezuela could have a material negative impact on our results of operations. We may not receive adequate compensation for our interest in these assets, or any compensation, if our assets in Venezuela are nationalized. We own 70 percent and
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66.67 percent controlling interests in the two subsidiaries that hold these assets. See Note 11 of Notes to Consolidated Financial Statements for a discussion of the non-recourse debt related to these assets.
Year-Over-Year Operating Results
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Segment revenues | | $ | 4,124.7 | | | $ | 3,232.7 | | | $ | 2,882.6 | | | $ | 5,642 | | | $ | 5,180 | | | $ | 4,159 | |
| Segment profit | | | | | | | | | | | | | |
| | | | | | | | | |
| Segment profit (loss) | | | | | | | | | | | | | |
Domestic gathering & processing | | | 626.8 | | | | 379.7 | | | | 385.8 | | | | 841 | | | | 897 | | | | 631 | |
Venezuela | | | 98.4 | | | | 94.7 | | | | 85.6 | | | | 104 | | | | 89 | | | | 98 | |
Other | | | 3.4 | | | | 62.3 | | | | 134.0 | | |
NGL Marketing, Olefins and Other | | | | 113 | | | | 174 | | | | 16 | |
Indirect general and administrativeexpense | | | (70.3 | ) | | | (65.5 | ) | | | (55.7 | ) | | | (95 | ) | | | (88 | ) | | | (70 | ) |
| | | | | | | | | | | | | | | |
| Total | | $ | 658.3 | | | $ | 471.2 | | | $ | 549.7 | | | $ | 963 | | | $ | 1,072 | | | $ | 675 | |
| | | | | | | | | | | | | | | |
In order to provide additional clarity, our management’s discussion and analysis of operating results separately reflects the portion of general and administrative expense not allocated to an asset group asindirect general and administrative expense.expense. These charges represent any overhead cost not directly attributable to one of the specific asset groups noted in this discussion.
20062008 vs. 20052007
The $892.0 million increase insegment revenuesis largely due to:
| | |
| | • | A $561$210 million increase in crude marketing revenues which is offset by a similar change in costs, resulting from additional deepwaterour olefins production coming on-linebusiness due primarily to higher average product prices and also to higher volumes sold associated with the increase of our ownership interest in November 2005;the Geismar olefins facility effective July 2007. |
| |
| | • | A $165$163 million increase in revenues associated with the production of NGLs due primarily due to higher average NGL prices, combined withpartially 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;volumes during 2007 as we transitioned from shipping volumes through a pipeline for sale downstream to product sales at the plant. |
| |
| | • | A $137 million increase in the marketing of NGLs and olefins, which is offset by a similar change in costs; |
|
| • | An $83$69 million increase in fee-based revenues including $52 million in higher production handling revenues;due primarily to the West region, Venezuela, the deepwater Gulf Coast region and at our Conway fractionation and storage facilities. |
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| | |
| • | A $44 million increase in revenues in our olefins unit due to higher volumes. |
These increases were partially offset by an $84 million reduction in NGL revenues due to a change in classification of NGL transportation and fractionation expenses from costs of goods sold to net revenues (offset in costs and operating expenses).
Segment costs and expensesincreased $707.3$569 million, or 14 percent, primarily as a result of:
| | |
| | • | A $561$213 million increase in crude marketing purchases, which is offset bycosts 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 similar change in revenues;$10 million higher charge to write down the value of olefin inventories. |
| |
| | • | A $137$191 million increase in NGL and olefins marketing purchases, offset by a similar change in revenues; |
|
| • | An $82 million increase in operating expenses including a $10.6 million accounts payable accrual adjustment,costs associated with the production of NGLs due primarily to higher system losses, depreciation, insurance expense, personnel and related benefit expenses, turbine overhauls, materials and supplies, compression and post-hurricane inspection and survey costs required by a government agency;average natural gas prices. |
| |
| | • | A $59$126 million increase in other expense including the $68 million estimated exposure for actual damages for the Gulf Liquids litigation,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 $9$19 million favorable settlementhigher charge in 2008 to write down the value of a contract dispute;NGL and olefin inventories. |
| |
| | • | A $20$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 productionthe increase of our ownership interest in ourthe Geismar olefins unit.facility. |
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These increases wereare partially offset by:
| | |
| | • | An $84A $44 million reduction in NGL transportation and fractionation expensesfavorable change related to foreign currency exchange gains primarily due to the above-noted changerevaluation of current assets held in classification (offset in revenues);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 $77$16 million favorable change due to higher involuntary conversion gains in 2008 related to insurance recoveries in excess of the carrying value of our Ignacio and Cameron Meadows plants. |
The decrease in Midstream’ssegment profitreflects the previously described changes insegment revenuesandsegment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.
Domestic gathering & processing
The decrease indomestic gathering & processing segment profitincludes a $49 million decrease in the West region and a $7 million decrease in the Gulf Coast region.
The decrease in our West region’ssegment profitincludes:
| | |
| • | 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. |
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| • | 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. |
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| • | A $12 million involuntary conversion gain related to our Ignacio plant. These insurance recoveries were used to rebuild the plant. |
The decrease in the Gulf Coast region’ssegment profitis primarily due to $39 million higher operating costs including higher depreciation, gas transportation expenses and hurricane repair and property insurance deductibles. These increases are partially offset by $18 million higher NGL margins and $8 million higher fee revenues due primarily to connecting new supplies in the deepwater.
Venezuela
Segment profitfor our Venezuela assets increased due to higher fee revenues and lower bad debt expense, partially offset by lower currency exchange gains.
NGL marketing, olefins and other
The significant components of the decrease insegment profitof our other operations include:
| | |
| • | $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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| | |
| • | $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. |
These increases are partially offset by:
| | |
| • | 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). |
2007 vs. 2006
The increase insegment revenuesis largely due to:
| | |
| • | A $528 million increase in revenues from the marketing of NGLs and olefins. |
|
| • | A $303 million increase in revenues from our olefins production business. |
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| • | A $244 million increase in revenues associated with the production of NGLs. |
These increases are partially offset by a $35 million decrease in fee revenues.
Segment costs and expensesincreased $645 million, or 18 percent, primarily as a result of:
| | |
| • | A $491 million increase in NGL and olefin marketing purchases. |
|
| • | A $257 million increase in costs from our olefins production business. |
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| • | A $37 million increase in operating expenses including higher depreciation, maintenance, gathering fuel expenses and operating taxes. |
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| • | $24 million higher general and administrative expenses. |
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| • | A $10 million loss on impairment of the Carbonate Trend pipeline and an $8 million loss on impairment of other assets. |
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| • | The absence of $11 million of net gains on the sales of assets in 2006. |
These increases are partially offset by:
| | |
| • | 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. |
The $187.1 million increase in MidstreamMidstream’ssegment profitis primarily due toreflects $339 million higher NGL margins higher deepwater production handling revenues, higher gathering and processing revenues, higher margins from our olefins unit, and a settlementthe absence of an international contract dispute, largely offset by the $72.7previously mentioned $73 million charge related to the Gulf Liquids litigation contingency combined with higher operatingcharge in 2006, as well as the other previously described changes insegment revenuesandsegment costs and lower margins related to the marketing of olefins and NGLs.expenses. A more detailed analysis of thesegment profitof Midstream’s various operations is presented as follows.
Domestic gathering & processing
The $247.1 million increase indomestic gathering and processing segment profitincludes a $143$308 million increase in the West region, andpartially offset by a $104$42 million increasedecrease in the Gulf Coast region.
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The $143 million increase in our West region’ssegment profitprimarily results from higher productNGL margins, higher processing fee based revenues and higher gathering and processing revenues,a favorable litigation settlement, partially offset by higher operating expenses.expenses and lower gathering fee revenues. The significant components of this increase include the following:
| | |
| | • | NGL margins increased $166$326 million in 2007 compared to 2005.2006. This increase was driven by an increase in average per unit NGL prices, a decrease in costs associated with the production of NGLs an increase in average per unit NGLreflecting lower natural gas prices and higher volumes resulting from lower NGL recoveries duringdue primarily to new capacity on the fourth quarter of 2005 caused by intermittent periods of uneconomical market commodity prices and a power outage and associated operational issuesfifth cryogenic train at our Opal Wyoming facility. NGL margins are defined as NGL revenues less BTU replacement cost, plant fuel, transportation and fractionation expense.plant. |
| |
| | • | Gathering and processingProcessing fee revenues increased $26$12 million. Gathering fees are higher as a result of higher averageper-unit gathering rates. Processing volumes are higher due to customers electing to take liquids and pay processing fees. |
| |
| | • | Operating expenses increased $51$12 million including $11income in 2007 from a favorable litigation outcome. |
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| • | Gathering fee revenues decreased $6 million due primarily to natural volume declines and the shutdown of the Ignacio plant in higher net system product lossesthe fourth quarter of 2007 as a result of systemthe 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 2005 comparedthe prior year, $5 million higher leased compression costs and $4 million higher costs related to losses in 2006,the Jicarilla lease arrangement. These were partially offset by the absence of a $7 million accounts payable accrual adjustment; $8adjustment in 2006 and $5 million in higher personnel and related benefit expenses; $6 million in higher materials |
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| | |
| | and supplies; $6 million in higher gathering fuel, $4 million in higher leased compression costs; $4 million in higher turbine overhaul costs; and $4 million in higher depreciation.lower system product losses. |
The $104 million increasedecrease in the Gulf Coast region’ssegment profitis primarily a result of higher NGL margins, higherlower volumes from our deepwater facilities, losses on impairments, and the absence of gains on assets in 2006, partially offset by higher operating expenses.NGL margins and higher other fee revenues. The significant components of this increasedecrease include the following:
| | |
| | • | 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. |
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| • | 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. |
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| • | NGL margins increased $77$14 million compared to 2005. This increase was driven by an increase in average per unithigher NGL prices, partially offset by lower NGL recoveries and a decreasean increase in costs associated with the production of NGLs. |
| |
| | • | FeeOther fee revenues from our deepwater assets increased $52$8 million as a result of $51 million indriven by higher volumes flowing across the Devils Tower facility and $22 million in higher Devils Towerunit-of-production rates recognized as a result of a new reserve study. These increases are partially offset by a $21 million decline in other gathering and production handling revenues due to volume declines in other areas. |
|
| • | Operating expenses increased $25 million primarily as a result of $12 million in higher insurance costs, $4 million in higher depreciation expense on our deepwater assets, $3 million in higher net system product losses as a result of lower gain volumes in 2006, $2 million in post-hurricane inspection and survey costs required by a government agency, and a $1 million accounts payable accrual adjustment.water removal fees. |
Venezuela
Segment profitfor our Venezuela assets increased $3.7 million and includesdecreased primarily due to the absence of a $9 million resultinggain from the settlement of a contract dispute in 2006, $6 million lower fee revenues due primarily to the discontinuance in 2007 of revenue recognition related to labor escalation receivables, $7 million higher operating expenses, and $8 million higher bad debt expense related to labor escalation receivables, partially offset by $19 million of higher currency exchange gains and $1 million in higher revenues due to higher natural gas volumes and prices at our compression facility. These are partially offset by $4 million in higher expenses related to higher insurance, personnel and contract labor costs and a $2 million increase in the reserve for uncollectible accounts.equity earnings.
OtherNGL marketing, olefins and other
The $58.9 million decreasesignificant components of the increase insegment profitof our other operations is largely due toinclude the $72.7 million of charges related to the Gulf Liquids litigation contingency combined with $13 million in lower margins related to the marketing of olefins. The decrease also reflects $12 million in lower margins related to the marketing of NGLs due to more favorable changes in pricing while product was in transit during 2005 as compared to 2006. These were partially offset by $24 million in higher margins in our olefins unit, $7 million in higher earnings from our equity investment in Discovery Producer Services, L.L.C. (Discovery), $7 million in higher fractionation, storage and other fee revenues, and a $4 million favorable transportation settlement.
2005 vs. 2004
The $350.1 million increase insegment revenuesis largely due to:following:
| | |
| | • | A $196The absence of the previously mentioned $73 million increaseGulf Liquids litigation charge in crude marketing revenues, which is offset by a similar change in costs, resulting from the start up of a deepwater pipeline in the second quarter of 2004;2006. |
| |
| | • | A $72 million increase in revenues associated with production of NGLs, primarily due to $180$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 prices partially offset by $108 million in lower sales volumes. The decline in sales volumesproducts produced in our Gulf Coast region is largely due to the impact of summer hurricanes, while the decline in the West region is largely due to the higher levels of NGL rejection as well as maintenance issues with our gas processing facility at Opal, Wyoming; |
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| • | A $58 million increase in the marketing of NGLs, which is offset by a similar change in costs, resulting from higher prices and additional spot sales; |
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| • | A $21 million increase in fee-based revenues in part due to higher customer production volumes flowing to our West region and deepwater assets. |
Costs and operating expensesincreased $364.1 million primarily as a result of:
| | |
| • | A $196 million increase in crude marketing purchases, which is offset by a similar change in revenues;Canadian olefins operations. |
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| | |
| | • | A $92$18 million increase in costshigher margins related to the productionmarketing of NGLs as a result of $100olefins and $21 million in higher natural gas purchasesmargins related to the marketing of NGLs due largely to higher prices, partially offset by lower volumes;more favorable changes in pricing while product was in transit during 2007 as compared to 2006. |
| |
| | • | A $58An $8 million increase related to the marketingreversal of NGLs and additional spot purchases, which is offset by a similar change in revenues;maintenance accrual (see below). |
| |
| | • | A $33$9 million increase in operating expenses mostlyhigher Aux Sable equity earnings primarily due to favorable processing margins. |
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| • | $11 million higher Discovery equity earnings primarily due to higher fuel expenseNGL margins and commodity costs associated with our NGL storage and fractionation business and higher depreciation expense.volumes. |
The $78.5 million decline in Midstreamsegment profitis primarily due to the absence of the $93.6 million gain from the Gulf Liquids’ insurance arbitration award in 2004. The offsetting increase in segment profit is primarily due to higher fee revenues from our domestic gathering and processing and Venezuela businesses and higher earnings from our investment in the Discovery partnership,These increases are partially offset by lower NGL margins and higher operating costs. A more detailed analysis of the segment profit of Midstream’s various operations is presented below.
Domestic gathering & processing
The $6.1 million decrease indomestic gathering and processing segment profitincludes a $30 million decline in the Gulf Coast region, largely offset by a $24 million increase in the West region.
The $24 million increase in our West region’ssegment profitprimarily results from higher gathering and processing fee revenues, and the absence of an asset write-down and other 2004 charges, offset partially by higher operating expenses and lower NGL margins. The significant drivers to these items are as follows:by:
| | |
| | • | Gathering and processing fee revenues increased $18$19 million primarily as a result ofin higher averageper-unit gathering and processing rates and higher volumes in the Rocky Mountain production area due to increased drilling activity. A portion of this increase is also dueforeign exchange losses related to the increaserevaluation of current assets held in volumes subject to fee-based processing contracts.U.S. dollars within our Canadian operations. |
| |
| | • | A favorable variance due to theThe absence of the write-down of $7.6a $4 million for an idle treating facilityfavorable transportation settlement in 2004. |
|
| • | NGL margins decreased $6 million due to a $17 million impact from lower sales volumes resulting from lower fourth quarter 2005 NGL recoveries caused by intermittent periods of uneconomical market commodity prices and a power outage and associated operational issues at our Opal, Wyoming facility. NGL margins are defined as NGL revenues less BTU replacement cost, plant fuel, transportation and fractionation expense. The impact of lower volumes is partially offset by an $11 million impact of higher per unit NGL margins.2006. |
The $30 million decrease in the Gulf Coast region’sEffective January 1, 2007, we adopted FASB Staff Position (FSP) No. AUG AIR-1,segment profitAccounting for Planned Major Maintenance Activities.is primarilyAs a result, we recognized as other income an $8 million reversal of higher operating and depreciation expenses and lower NGL margins. The significant components of this decline includean accrual for major maintenance on our Geismar ethane cracker. We did not apply the following:
| | |
| • | Operating expenses increased $10 million primarily due to higher maintenance expenses related to our gathering assets, compressor overhauls, and an increase in hurricane-related costs of $2 million. Inspection and repair expenses related to the hurricanes were recorded as incurred up to the level of our insurance deductible. |
|
| • | Depreciation expense increased $13 million primarily due to placing in service our Devils Tower spar and associated deepwater gas and oil pipelines in May and June 2004, respectively. |
|
| • | NGL margins declined $14 million due to lower volumes, largely due toFSP retrospectively because the impact of summer hurricanes, and the increase in natural gas prices. While revenues from the Devils Tower deepwater facility are recognized as volumes are delivered over the life of the reserves, cash payments from our customers are based on a contractual fixed fee received over a defined term. As a result, $44 million of cash received in 2005, which is included in cash flow from operations, was deferred at December 31, 2005 and will be recognized as revenue in periods subsequent to 2005. The total amount deferred for all years as of December 31, 2005 was $80 million. |
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Venezuela
Segment profitfor our Venezuela assets increased $9.1 million as a result of higher plant volumes and higher equity earnings from our investment in the ACCROVEN partnership. The higher equity earnings are largely due to the renegotiation of a power supply contract and the absence of 2004 legal fees associated with the Jose Terminal.
Other
The $71.7 million decrease insegment profitof our other operations is largely due to the absence of the $93.6 million gain from the Gulf Liquids’ insurance arbitration award and a $9.5 million gain on the sale of the Choctaw ethylene distribution assets in 2004 partially offset by $7 million in higher olefins and commodity margins, $6 million in higher earnings from our equity investment in the Discovery partnership, and the absence of a 2004 $16.9 million impairment charge also related to our equity investment infirst quarter 2007 and estimated full year 2007 earnings, as well as the Discovery partnership.impact to prior periods, is not material. We have adopted the deferral method for accounting for these costs going forward.
Indirect general and administrative expense
The $9.8 million unfavorable variance for ourincrease in indirect general and administrative expensesexpense is due primarily due to higher technical support services and other charges for various administrative support functions and higher employee expenses and administrative costs associated with the creation of Williams Partners L.P.expenses.
PowerGas Marketing Services
Gas Marketing Services (Gas Marketing) primarily supports our natural gas businesses by providing marketing and risk management services, which include marketing and hedging the gas produced by Exploration & Production, and procuring fuel and shrink gas and hedging natural gas liquids sales for Midstream. Gas Marketing also provides similar services to third parties, such as producers. In addition, Gas Marketing manages various natural gas-related contracts such as transportation, storage, related hedges and proprietary trading positions, including certain legacy natural gas contracts and positions.
Overview of 20062008
Power’sGas Marketing’s operating results for 2006 reflect an accrual gross margin loss2008 were primarily driven by higher realized margins on its nonderivative tolling contracts. Power’s resultsboth storage and transportation contracts in 2006addition to favorable price movements on derivative positions executed to hedge the anticipated withdrawals of natural gas from storage. These gains were also influencedpartially offset by adjustments made to the carrying value of the natural gas inventories in storage reflecting a decreasedecline in forward power prices against a net long derivative position, which caused net forward unrealizedmark-to-market (MTM) losses. Power’s results do not reflect, however, cash flows that Power realized in 2006 from hedges for whichmark-to-market gains or losses had been previously recognized.the price of natural gas.
In 2006, Power continued toOutlook for 2009
For 2009, Gas Marketing will focus on its objectives of minimizing financial risk, maximizing cash flow, meeting contractual commitments, executing new contracts to hedge its portfolio and providing services that support our natural gas businesses.
Outlook for 2007
For 2007, Power intends to service its customers’ needs while increasing the certainty of cash flows from its long-term tolling contracts by executing new long-term electricity and capacity sales contracts. In the first quarter of 2007, Power executed agreements to sell dispatch and tolling rights and supply natural gas in southern California for periods through 2011. These contracts mirror Power’s rights under its California tolling agreement and represent up to 1,920 megawatts of power.
As Power continues to apply hedge accounting in 2007, its future Gas Marketing’s earnings may be less volatile. However,continue to reflect mark-to-market volatility from commodity-based derivatives that represent economic hedges but are not all of Power’s derivative contractsdesignated as hedges for accounting purposes or do not qualify for hedge accounting. Application of hedge accounting requires quantitative and qualitative analysis. To qualify for hedge accounting, Power must assess derivatives for their expected effectiveness in offsetting the risk being hedged. In addition, it must assess whether the hedged forecasted transaction is probable of occurring. If Power no longer expects the hedge to be highly effective, or if it believes that the hedged forecasted transaction is no longer probable of occurring, it would discontinue hedge accounting prospectively and recognize future changes in fair value directly to earnings.
Because certain derivative contracts qualifying for hedge accounting were previouslymarked-to-market through earnings prior to their designation as cash flow hedges, the amounts recognized in future earnings under hedge accounting will not necessarily align with the expected cash flows to be realized from the settlement of those derivatives. For example, future earnings may reflect losses from underlying transactions, such as natural gas purchases and power sales associated with our tolling contracts, which have been hedged by derivatives. A portion of the offsetting gains from these hedges, however, has already been recognized in prior periods undermark-to-market accounting. So, while earnings in a reported period may not reflect the full amount realized from our hedges, cash flows will continue to reflect the total amount from both the hedged transactions and the
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hedges. In 2006, 2005 and 2004 Power had positive cash flows from operations, and expects to continue to have positive cash flows from operations in 2007.
Even with the application of hedge accounting, Power’s earnings will continue to reflectmark-to-market volatility from unrealized gains and losses resulting from:
| | |
| • | Market movements of commodity-based derivatives that represent economic hedges but which do not qualify for hedge accounting; |
|
| • | Ineffectiveness of cash flow hedges, primarily caused by locational differences between the hedging derivative and the hedged item or changes in the creditworthiness of counterparties; |
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| • | Market movements of commodity-based derivatives that are held for trading purposes. |
The fair value of Power’s tolling, full requirements, transportation, storage and transmission contracts is not reflected on the balance sheet since these contracts are not derivatives. Some of these contracts have a significant negative estimated fair value and could result in future operating losses. Power’s estimate of fair value may differ significantly from a third party’s estimate. Power’s estimate of fair value is based on internal valuation assumptions, which include assumptions of natural gas prices, electricity prices, price volatility, correlation of gas and electricity, and many other inputs. Some of these assumptions are readily available in the market, while others are not.
Key factors that may influence Power’s financial condition and operating performance include:
| | |
| • | Prices of power and natural gas, including changes in the margin between power and natural gas prices; |
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| • | Changes in power and natural gas price volatility; |
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| • | Changes in power and natural gas supply and demand; |
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| • | Changes in the regulatory environment; |
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| • | The inability of counterparties to perform under contractual obligations due to their own credit constraints; |
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| • | Changes in interest rates; |
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| • | Changes in market liquidity, including changes in the ability to effectively hedge commodity price risk; |
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| • | The inability to apply hedge accounting. |
Year-Over-Year Operating Results
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Millions) | |
| |
| Realized revenues | | $ | 7,484.6 | | | $ | 8,921.8 | | | $ | 8,954.7 | |
Net forward unrealizedmark-to-market gains (losses) | | | (22.2 | ) | | | 172.1 | | | | 304.0 | |
| | | | | | | | | | | | | |
| Segment revenues | | | 7,462.4 | | | | 9,093.9 | | | | 9,258.7 | |
| Cost of sales | | | 7,619.8 | | | | 9,150.3 | | | | 9,073.3 | |
| | | | | | | | | | | | | |
| Gross margin | | | (157.4 | ) | | | (56.4 | ) | | | 185.4 | |
| Operating expenses | | | 18.0 | | | | 22.2 | | | | 23.7 | |
| Selling, general and administrative expenses | | | 62.2 | | | | 64.5 | | | | 83.2 | |
| Other (income) expense — net | | | (26.8 | ) | | | 113.6 | | | | 1.8 | |
| | | | | | | | | | | | | |
| Segment profit (loss) | | $ | (210.8 | ) | | $ | (256.7 | ) | | $ | 76.7 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (Millions) | |
| |
| Realized revenues | | $ | 6,385 | | | $ | 4,948 | | | $ | 5,185 | |
| Net forward unrealized mark-to-market gains (losses) | | | 27 | | | | (315 | ) | | | (136 | ) |
| | | | | | | | | | | | | |
| Segment revenues | | $ | 6,412 | | | $ | 4,633 | | | $ | 5,049 | |
| | | | | | | | | | | | | |
| Segment profit (loss) | | $ | 3 | | | $ | (337 | ) | | $ | (195 | ) |
| | | | | | | | | | | | | |
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20062008 vs. 20052007
The $1.4 billion decrease inrealizedRealized revenuesis primarily due to a decrease in power and natural gas realized revenues. Realized revenues represent (1) revenue from the sale of commodities or completion of energy-related servicesnatural gas and (2) gains and losses from the net financial settlement of derivative contracts.
Power and natural gas realizedRealized revenues decreasedincreased $1,437 million primarily due to an increase in physical natural gas revenue as a 20result of a 26 percent decrease in power sales volumes and a 17 percent decreaseincrease in average prices on physical natural gas sales prices. Power sales volumes decreased because certain long-term physical contracts were not replaced duesales. This is slightly offset by a decrease related to reducing the scopenet financial settlements of trading activities subsequent to 2002.derivative contracts.
Net forward unrealizedmark-to-market gains (losses)primarily represent changes in the fair values of certain derivative contracts with a future settlement or delivery date that have not been designated as cash flow hedges and the impact of the ineffectiveness of cash flow hedges. The effect of changes in forward prices on power contractsare not designated as cash flow hedges for accounting purposes or do not qualify for hedge accounting. The favorable change of $342 million includes the effect of a $156 million loss realized in December 2007 related to a legacy derivative natural gas sales contract. We had previously accounted for this contract on an accrual basis under the normal purchases and normal sales exception of SFAS No. 133. We discontinued normal purchase and normal sales treatment because it was no longer probable that the contract would not be net settled. In addition, 2008 reflects favorable price movements on our derivative positions executed to hedge the anticipated withdrawal of natural gas from storage.
Totalsegment costs and expensesincreased $1,439 million, primarily caused the $194.3 million decrease innet forward unrealizedmark-to-market gains (losses). A 2005due to a 33 percent increase in forward poweraverage prices caused gains on physical natural gas purchases. These increases were partially offset by the net forward purchase position, whileabsence of a 2006 decrease$20 million accrual for litigation contingencies in forward power prices caused losses on the net forward power purchase contracts.2007.
The $1.5 billion decrease$340 million favorable change in Power’scost of salessegment profit (loss)is primarily due to the favorable change innet forward unrealized mark-to-market gains (losses), which includes the absence of a 20 percent2007 loss recognized on a legacy derivative natural gas sales contract. The favorable change insegment profit (loss)also reflects the absence of a $20 million accrual for litigation contingencies in 2007, partially offset by a decline in accrual earnings.
2007 vs. 2006
Realized revenuesdecreased $237 million primarily due to a decrease in power purchasenet financial settlements of derivative contracts. This is partially offset by an increase in physical natural gas revenue as a result of a 9 percent increase in natural gas sales volumes and an 18partially offset by a 6 percent decrease in average prices on physical natural gas sales.
Net forward unrealized mark-to-market gains (losses)changed unfavorably as a result of a $156 million loss related to a legacy derivative natural gas sales contract that was previously accounted for on an accrual basis under the normal purchases and normal sales exception of SFAS No. 133. In addition, losses on gas purchase contracts caused by a decrease in forward natural gas prices were greater in 2007 than in 2006.
Totalsegment costs and expensesdecreased $274 million, primarily due to a decrease in costs and operating expenses reflecting a 7 percent decrease in average prices on physical natural gas purchases partially offset by a 4 percent increase in natural gas purchase prices.
volumes. The net decrease inselling, general and administrative expensesis due primarily to increased gains from the sale of certain Enron receivables to a third party. Power recognized a $24.8 million gain in 2006 compared to a $9.7 million gain in 2005.
Other (income) expense — netin 2006 includes a $12.7 million reduction of contingent obligations associated with our former distributive power generation business.
Other (income) expense — netin 2005 includes:was also partially offset by:
| | |
| | • | An $82.2A $20 million accrual for estimated litigation contingencies primarily associated with agreements reached to substantially resolve exposure related to natural gas price and volume reporting issues (see Note 15 of Notes to Consolidated Financial Statements);in 2007. |
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| | • | A $4.6The absence of a $25 million accrual forgain from the sale of certain receivables to a regulatory settlement; |
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| • | A $23 million impairment of an equity investment (see Note 3 of Notes to Consolidated Financial Statements).third party in 2006. |
The decrease$142 million unfavorable change insegment lossis primarily due to favorable changes inother (income) expense — netdescribed above, partially offset by a decrease in gross margin.
2005 vs. 2004
The $164.8 million decrease in revenues includes a $32.9 million decrease inrealized revenuesand a $131.9 million decrease innet forward unrealized mark-to -market gains (losses).
The $32.9 million decrease inrealized revenuesprofit (loss)is primarily due to the absence in 2005 of $471loss recognized on a legacy derivative contract previously treated as a normal purchase and normal sale, a $20 million in crude and refined products realized revenues, partially offset by a $444 million increase in power and natural gas realized revenues. The absence of crude and refined products revenues is due to the sale of the refined products business in 2004. Power and natural gas realized revenues increased primarily due to a 33 percent increase in average natural gas sales prices and a 17 percent increase in average power sales prices. Hurricane Katrina, among other factors, contributed to the increase in prices. A 29 percent decrease in power sales volumes partially offsets the increase in prices. Power sales volumes decreased because Power did not replace certain long-term physical contracts that expired or were terminated and because of mild weather in California, which resulted in lower demand.
The $131.9 million decrease innet forward unrealizedmark-to-market gains (losses)is primarily due to a $165 million decrease associated with power and gas derivative contracts, partially offset by the absence in 2005 of a $38 million unrealized loss on the interest rate portfolio in 2004.accrual for
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The decrease in powerlitigation contingencies and gas unrealizedmark-to-market gains primarily results from the impact of cash flow hedge accounting, which was prospectively applied to certain of Power’s derivative contracts beginning October 1, 2004. Net unrealized gains of $711 million related to the effective portion of the hedges are reported inaccumulated other comprehensive lossin 2005 compared to $15 million in 2004. If Power had not applied cash flow hedge accounting in 2005, we would have reported the $711 million inrevenuesinstead of inaccumulated other comprehensive loss. Also in 2005, Power recognized losses of $6.8 million representing a correction of unrealized losses associated with a prior year. Our management concluded that the effects of this correction are not material to prior periods, 2005 results, or our trend of earnings. Partially offsetting these decreases is the effectabsence of a greater increase in forward power prices on a greater volume of power purchase contracts in 2005 compared to 2004, resulting in increased unrealizedmark-to-market gains on net power derivatives that are not accounted for as cash flow hedges.
The absence in 2005 of the unrealized loss on the interest rate portfolio is due to the termination and liquidation of all remaining interest-rate derivatives in fourth quarter 2004. A decrease in forward interest rates caused unrealized losses in the interest rate portfolio in 2004.
The $77$25 million increase in Power’scost of salesis primarily due to an increase in power and natural gas costs of $563 million, partially offset by a decrease in crude and refined products costs of $486 million. Power and natural gas costs increased primarily due to a 32 percent increase in average power purchase prices and a 44 percent increase in average natural gas purchase prices, partially offset by a 29 percent decrease in power purchase volumes. Hurricane Katrina, among other factors, contributed to the increase in prices. Costs in 2005 include approximately $8 million in purchases due to an outage at an electric generating facility that Power has access to via a fuel conversion service agreement. A 2004 reduction to certain contingent loss accruals of $10.4 million associated with power marketing activities in California during 2000 and 2001 also contributes to the increase in costs. Costs in 2004 include $486 million of crude and refined products costs, which are absent in 2005 due to the sale of the refined products business in 2004. Costs in 2004 also reflect a $13 million payment made to terminate a nonderivative power sales contract.
Selling, general and administrative expensesdecreased primarily due to decreased employee incentive compensation and decreased costs for outside services. A $9.7 million reduction of allowance for bad debts resultinggain from the sale of certain receivables, to a third party also contributed to the decreasepartially offset by an improvement inSG&A expenses.SG&A expensesin 2004 include a $6.3 million reduction of allowance for bad debts resulting from a 2004 settlement with certain California utilities.
Other (income) expense — netin 2004 includes $6.1 million in fees paid related to the sale of certain receivables to a third party.
Although increased gas prices favorably impacted the fair value of Power’s derivative natural gas hedges, the $333.4 million change from asegment profit to asegment lossis primarily due to the impact of cash flow hedge accounting. Additionally, plant outages and depressed margin spreads between the cost of gas and sales price of electricity contributed to lowersegment profit. Accruals in 2005 for litigation contingencies and an impairment of an equity investment also contributed to the change insegment profit (loss). Partially offsetting the decrease insegment profitis the absence in 2005 of unrealized and realized losses from the interest rate portfolio, which was liquidated in the fourth quarter of 2004. accrual earnings.
Other
Overview of 2006
While we continue to have an equity ownership interest in Longhorn, the management of Longhorn completed an asset sale of the pipeline during the third quarter of 2006. As a result, we received full payment of the $10 million secured bridge loan that we provided Longhorn during 2005. The carrying value of our equity investment in Longhorn is zero as of December 31, 2006.
We continue to receive payments associated with the 2005 transfer of the Longhorn operating agreement to a third party. These payments totaled approximately $3.3 million for the year ended December 31, 2006. Any ongoing
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payments received or through monetization of the contract will be recognized as income when received. These ongoing payments were not impacted by the sale of the pipeline.
Year-Over-Year Operating Results
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Segment revenues | | $ | 26.5 | | | $ | 27.2 | | | $ | 32.8 | | | $ | 24 | | | $ | 26 | | | $ | 27 | |
| Segment profit (loss) | | $ | 1.9 | | | $ | (105.0 | ) | | $ | (41.6 | ) | |
| | | | | | | | | |
| Segment loss | | | $ | (3 | ) | | $ | (1 | ) | | $ | (13 | ) |
| | | | | | | | | |
20062008 vs. 20052007
The results of our Othersegment profitfor 2006 includes $3.3 million in payments received relatedare relatively comparable to the 2005 transfer of the Longhorn operating agreement.prior year.
Other2007 vs. 2006
The improvement insegment lossfor 2005 includes $87.22007 is primarily driven by $5 million of impairment charges, of which $38.1 million was recorded during the fourth quarter, related to our investment in Longhorn. In a related matter, we wrote off $4 million of capitalized project costs associated with Longhorn. We also recorded $23.7 million of equity losses associated with our investment in Longhorn. Partially offsetting these charges and losses was a $9 million fourth quarter gainnet gains on the sale of land.
2005 vs. 2004
Othersegment lossfor 2005 includes various items which are discussed above.
Othersegment lossfor 2004 includes $11.8 million of accrued environmental remediation expense associated with the Augusta refinery. Also included in Othersegment lossis $10.8 million of impairment charges related to our investment in Longhorn, $9.8 million of equity losses associated with our investment in Longhorn, and $6.5 million of net unreimbursed advisory fees related to the recapitalization of Longhorn.
Energy Trading Activities
Fair Value of Trading and Nontrading Derivatives
The chart below reflects the fair value of derivatives held for trading purposes as of December 31, 2006. We have presented the fair value of assets and liabilities by the period in which we expect them to be realized.
Net Assets (Liabilities) — Trading
(Millions)
| | | | | | | | | | | | | | | | | | | | | |
To be
| | To be
| | | To be
| | | To be
| | | To be
| | | | |
Realized in
| | Realized in
| | | Realized in
| | | Realized in
| | | Realized in
| | | | |
1-12 Months
| | 13-36 Months
| | | 37-60 Months
| | | 61-120 Months
| | | 121+ Months
| | | Net
| |
(Year 1) | | (Years 2-3) | | | (Years 4-5) | | | (Years 6-10) | | | (Years 11+) | | | Fair Value | |
| |
| $3 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3 | |
As the table above illustrates, we are not materially engaged in trading activities. However, we hold a substantial portfolio of nontrading derivative contracts. Nontrading derivative contracts are those that hedge or could possibly hedge forecasted transactions on an economic basis. We have designated certain of these contracts as cash flow hedges of Power’s forecasted purchases of gas, its purchases and sales of power related to its long-term structured contracts and owned generation, and Exploration & Production’s forecasted sales of natural gas production. Certain of Power’s other derivatives have not been designated as or do not qualify as SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) cash flow hedges. The chart below reflects the fair value of derivatives held for nontrading purposes as of December 31, 2006, for the Power and Exploration & Production businesses. Of the total fair value of nontrading derivatives, SFAS 133 cash flow hedges had a net asset value of $360 million as of December 31, 2006, which includes the existing fair value of the derivatives at the time of their designation as SFAS 133 cash flow hedges.
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Net Assets (Liabilities) — Nontrading
(Millions)
| | | | | | | | | | | | | | | | | | | | | |
To be
| | To be
| | | To be
| | | To be
| | | To be
| | | | |
Realized in
| | Realized in
| | | Realized in
| | | Realized in
| | | Realized in
| | | | |
1-12 Months
| | 13-36 Months
| | | 37-60 Months
| | | 61-120 Months
| | | 121+ Months
| | | Net
| |
(Year 1) | | (Years 2-3) | | | (Years 4-5) | | | (Years 6-10) | | | (Years 11+) | | | Fair Value | |
| |
| $94 | | $ | 227 | | | $ | 88 | | | $ | 24 | | | $ | — | | | $ | 433 | |
Methods of Estimating Fair Value
Most of the derivatives we hold settle in active periods and markets in which quoted market prices are available. These include futures contracts, option contracts, swap agreements and physical commodity purchases and sales in the commodity markets in which we transact. While an active market may not exist for the entire period, quoted prices can generally be obtained for natural gas through 2012 and power through 2011.
These prices reflect current economic and regulatory conditions and may change because of market conditions. The availability of quoted market prices in active markets varies between periods and commodities based upon changes in market conditions. The ability to obtain quoted market prices also varies greatly from region to region. The time periods noted above are an estimation of aggregate availability of quoted prices. An immaterial portion of our total net derivative value of $436 million relates to periods in which active quotes cannot be obtained. We estimate energy commodity prices in these illiquid periods by incorporating information about commodity prices in actively quoted markets, quoted prices in less active markets, and other market fundamental analysis. Modeling and other valuation techniques, however, are not used significantly in determining the fair value of our derivatives.
Counterparty Credit Considerations
We include an assessment of the risk of counterparty nonperformance in our estimate of fair value for all contracts. Such assessment considers (1) the credit rating of each counterparty as represented by public rating agencies such as Standard & Poor’s and Moody’s Investors Service, (2) the inherent default probabilities within these ratings, (3) the regulatory environment that the contract is subject to and (4) the terms of each individual contract.
Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We continually assess this risk. We have credit protection within various agreements to call on additional collateral support if necessary. At December 31, 2006, we held collateral support, including letters of credit, of $695 million.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2006 and 2005, we did not incur any significant losses due to recent counterparty bankruptcy filings.
The gross credit exposure from our derivative contracts as of December 31, 2006, is summarized below.
| | | | | | | | | |
| | | Investment
| | | | |
Counterparty Type | | Grade(a) | | | Total | |
| | | (Millions) | |
| |
| Gas and electric utilities | | $ | 248.0 | | | $ | 249.9 | |
| Energy marketers and traders | | | 412.7 | | | | 1,784.3 | |
| Financial institutions | | | 2,219.4 | | | | 2,219.4 | |
| Other | | | 23.3 | | | | 29.8 | |
| | | | | | | | | |
| | | $ | 2,903.4 | | | | 4,283.4 | |
| | | | | | | | | |
| Credit reserves | | | | | | | (20.3 | ) |
| | | | | | | | | |
| Gross credit exposure from derivatives | | | | | | $ | 4,263.1 | |
| | | | | | | | | |
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We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of December 31, 2006, is summarized below.
| | | | | | | | | |
| | | Investment
| | | | |
Counterparty Type | | Grade(a) | | | Total | |
| | | (Millions) | |
| |
| Gas and electric utilities | | $ | 120.4 | | | $ | 120.5 | |
| Energy marketers and traders | | | 209.0 | | | | 455.4 | |
| Financial institutions | | | 325.5 | | | | 325.5 | |
| Other | | | 20.4 | | | | 20.4 | |
| | | | | | | | | |
| | | $ | 675.3 | | | | 921.8 | |
| | | | | | | | | |
| Credit reserves | | | | | | | (20.3 | ) |
| | | | | | | | | |
| Net credit exposure from derivatives | | | | | | $ | 901.5 | |
| | | | | | | | | |
| | |
(a) | | We determine investment grade primarily using publicly available credit ratings. We included counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. We also classify counterparties that have provided sufficient collateral, such as cash, standby letters of credit, adequate parent company guarantees, and property interests, as investment grade. |
Trading Policy
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Power’svalue-at-risk is limited in aggregate and calculated at a 95 percent confidence level.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2008, we continued to focus upon growth through disciplined investments in our natural gas businesses. Examples of this growth included:
| | |
| • | Continued investment in Exploration & Production’s development drilling programs. |
|
| • | Expansion of Gas Pipeline’s interstate natural gas pipeline system to meet the demand of growth markets. |
|
| • | Continued investment in Midstream’s Deepwater Gulf expansion projects and gas processing capacity in the western United States. |
These investments were primarily funded through our cash flow from operations, which totaled nearly $3.4 billion for 2008.
During the latter part of 2008, global credit markets experienced significant instability, our market capitalization declined as markets witnessed significant reductions in value and energy commodity prices experienced significant and rapid declines. While we have periodically provided for incremental funding needs through the issuance of debtand/or the sale of master limited partnership units, these sources of funding were considered economically unfavorable at December 31, 2008. In consideration of our liquidity under these conditions, we note the following:
| | |
| • | 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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Outlook
WeFor 2009, we expect operating results and cash flows to be sharply reduced from 2008 levels by the continued impact of lower energy commodity prices. This impact is somewhat mitigated by certain of our cash flow streams that are substantially insulated from sustained lower commodity prices as follows:
| | |
| • | Firm demand and capacity reservation transportation revenues under long-term contracts from Gas Pipeline; |
|
| • | Hedged natural gas sales at Exploration & Production related to a significant portion of its production; |
|
| • | Fee-based revenues from certain gathering and processing services at Midstream. |
In addition, we expect certain costs for services and materials to decline in 2009 as demand for these resources declines.
Although the financial markets and energy commodity environment are expected to be depressed for at least the near term, we believe we have, or have access to, the financial resources and liquidity necessary to meet futureour requirements for working capital, capital and investment expenditures, and debt payments while maintaining a sufficient level of liquidity to reasonably protect against unforeseen circumstances requiringliquidity. In particular, we note the use of funds. In 2007, we expect to maintain liquidity from cash and cash equivalents and unused revolving credit facilities of at least $1 billion. We maintain adequate liquidity to manage margin requirements related to significant movements in commodity prices, unplanned capital spending needs, near term scheduled debt payments, and litigation and other settlements. We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements through cash flow from operations, which is currently estimated to be between $2 billion and $2.3 billion in 2007, proceeds from debt issuances and sales of units of Williams Partners L.P., as well as cash and cash equivalents on hand as needed.
We enter 2007 positionedfollowing assumptions for growth through disciplined investments in our natural gas businesses. Examples of this planned growth include:the coming year:
| | |
| | • | Exploration & Production will continueWe expect to maintain its development drilling program in its key basinsliquidity of Piceance, Powder River, San Juan, Arkoma,at least $1 billion from cash and Fort Worth. During 2006, all tenstate-of-the-art FlexRig4® drilling rigs were placed in service in the Piceance basin pursuant to our March 2005 contract with Helmerich & Payne. Each rig is leased for three years.cash equivalents and unused revolving credit facilities. |
| |
| | • | Gas Pipeline will continueWe expect to expand its systemfund 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 meet the demand of growth markets. |
|
| • | Midstream will continuebuild additional liquidity. We estimate our cash flow from operations to pursue significant deepwater production commitmentsbe between $1.9 billion and expand capacity$2.2 billion in the western United States.2009. |
We estimate capital and investment expenditures will total $2,150 million to $2,450 million in 2009. Of this total, approximately $2.2 billiontwo-thirds is considered nondiscretionary to $2.4 billion in 2007. As a resultmeet legal, regulatory,and/or contractual requirements or to preserve the value of increasing our development drilling program, $1.3 billion to $1.4 billion of the total estimated 2007
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capital expenditures is related to Exploration & Production. Alsoexisting assets. Included within the total estimated expenditures for 20072009 is approximately $215$250 million to $270$300 million for compliance and maintenance-related projects at Gas Pipeline, including pipeline replacement and Clean Air Act compliance. Commitments for construction and acquisition of property, plant and equipment are approximately $406 million at December 31, 2006.
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:
| | |
| | • | Lower than expected levels of cash flow from operations due to commodity pricing volatility. To mitigate this exposure, Exploration & Production has economically hedged the price of natural gas for approximately 172 MMcfe per day of its expected 2007 production. In addition, Exploration & Production has collar agreements for each month of 2007 which hedge approximately 270 MMcfe per day of expected 2007 production. Power has entered into various sales contracts that economically cover substantially all of its fixed demand obligations through 2010.operations. |
| |
| | • | Sensitivity of margin requirements associated with our marginableSustained reductions in energy commodity contracts. As of December 31, 2006, we estimate our exposure to additional margin requirements through 2007 to be no more than $521 million, using a statistical analysis at a 99 percent confidence level.prices from year-end 2008 levels. |
| |
| | • | Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 1516 of Notes to Consolidated Financial Statements). |
In August 2006, the Pension Protection Act of 2006 was signed into law. The Act makes significant changes to the requirements for employer-sponsored retirement plans, including revisions affecting the funding of defined benefit pension plans beginning in 2008. We are assessing the impact of the legislation on our future funding requirements, but do not expect a significant increase in required contributions over current levels, assuming long-term rates of return on assets and current discount rates do not experience a significant decline.
Overview
In November 2005, we initiated an offer to induce conversion of up to $300 million of the 5.5 percent junior subordinated convertible debentures into our common stock. The conversion was executed in January 2006 and approximately $220.2 million of the debentures were exchanged for common stock. We paid $25.8 million in premiums that are included inearly debt retirement costsin the Consolidated Statement of Income. See Note 12 of Notes to Consolidated Financial Statements for further information.
In April 2006, Transco issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement to fund general corporate expenses and capital expenditures. In October 2006, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.
In May 2006, we replaced our $1.275 billion secured revolving credit facility with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and financial covenants as the secured facility, but contains certain additional restrictions. (See Note 11 of Notes to Consolidated Financial Statements.)
In June 2006, Northwest Pipeline issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement to fund general corporate expenses and capital expenditures. In October 2006, Northwest Pipeline completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
In June 2006, we reached anagreement-in-principle to settleclass-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002, for a total payment of $290 million to plaintiffs. On February 9, 2007, the court gave its final approval of the settlement. We recorded a pre-tax charge for approximately $161 million in second quarter 2006. Our portion of the total payment was $145 million.
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On June 1, 2006, the FERC entered its final order (FERC Final Order) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank litigation. The Quality Bank Administrator will determine and invoice for amounts due based on the FERC Final Order, subject to the final disposition of the FERC Final Order appeals. We estimate that our net obligation could be as much as $116 million. (See Note 15 of Notes to Consolidated Financial Statements.)
In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. 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 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of 7.25 percent senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.
Exploration & Production has recently entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Margin requirements, if any, under this new facility are dependent on the level of hedging and on natural gas reserves value.
Credit ratingsLiquidity
On May 4, 2006, Standard & Poor’s raisedBased on our senior unsecured debt ratingforecasted levels of cash flow from a B+ to a BB- with a positive ratings outlook. With respect to Standard & Poor’s, a ratingoperations and other sources of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify it’s ratings with a “+” or a “–” sign to show the obligor’s relative standing within a major rating category.
On June 7, 2006, Moody’s Investors Service raised our senior unsecured debt rating from a B1 to a Ba2 with a stable ratings outlook. With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is consideredliquidity, we expect to have speculative elements. A “Ba” rating indicates an obligation that is judgedsufficient liquidity to have speculative elementsmanage our businesses in 2009. As noted below, certain of our unsecured revolving and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.
On May 15, 2006, Fitch Ratings raised our senior unsecured rating from BB to BB+ with a stable ratings outlook. With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibilityletter of credit risk developing, particularly as the resultfacilities are scheduled to expire in 2009 and 2010. These facilities were originated primarily in support of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “–” sign to show the obligor’s relative standing within a major rating category.
Our goal is to attain investment grade ratios at some point in the future.
Liquidityour former power business.
Our internal and external sources of liquidity include cash generated from our operations, cash and cash equivalents on hand, and our credit facilities. Additional sources of liquidity, if needed, include bank financings, and proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. While most of our sources are available to us at the parent level, others aremay be available to certain of our subsidiaries, including equity and debt issuances from Williams Partners L.P. and Williams Pipeline Partners L.P., our master limited partnerships. Our ability to raise funds in the capital markets will be impacted by our financial condition, interest rates, market conditions, and industry conditions.
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In response to the challenges encountered by many financial institutions, the U.S. Government has provided substantial support to financial institutions, some of which are providers under our credit facilities. We continue to closely monitor the credit status of all providers under our credit facilities.
Available Liquidity
| | | | | |
| | | Year Ended
| |
| | | December 31, 2006
| |
| | | (Millions) | |
| |
| Cash and cash equivalents* | | $ | 2,268.6 | |
| Auction rate securities and other liquid securities | | | 103.2 | |
| Available capacity under our four unsecured revolving and letter of credit facilities totaling $1.2 billion | | | 304.9 | |
| Available capacity under our $1.5 billion unsecured revolving and letter of credit facility** | | | 1,471.2 | |
| | | | | |
| | | $ | 4,147.9 | |
| | | | | |
| | | | | | | | | |
| | | | | | Year Ended
| |
| | | Credit Facilities
| | | December 31, 2008
| |
| | | Expiration | | | (Millions) | |
| |
| Cash and cash equivalents(1) | | | | | | $ | 1,439 | |
| Available capacity under our unsecured revolving and letter of credit facilities totaling $1.2 billion: | | | | | | | | |
| $400 million facilities | | | April 2009 | | | | 400 | |
| $100 million facilities | | | May 2009 | | | | 100 | |
| $700 million facilities | | | September 2010 | | | | 480 | |
| Available capacity under our $1.5 billion unsecured revolving and letter of credit facility(2) | | | May 2012 | | | | 1,359 | |
| Available capacity under Williams Partners L.P.’s $450 million senior unsecured credit facility(3) | | | December 2012 | | | | 188 | |
| | | | | | | | | |
| | | | | | | $ | 3,966 | |
| | | | | | | | | |
| | |
*(1) | | Cash and cash equivalentsincludes $128.7$30 million of funds received from third parties as collateral. The obligation for these amounts is reported ascustomer margin deposits payableaccrued liabilitieson the Consolidated Balance Sheet. Also included is $347$609 million of cash and cash equivalents that is being utilized by certain subsidiary and international operations. The remainder of ourcash and cash equivalentsis primarily held in government-backed instruments. |
| |
**(2) | | This facility is guaranteed by Williams Gas Pipeline Company, L.L.C. 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. has accessWe expect that Williams Partners L.P.’s ability to $75borrow under this facility is reduced by $12 million due to the extentbankruptcy 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 utilizedimpacted by us, that we guarantee.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. |
In addition to the above, Northwest Pipeline and Transco have shelf registration statements available for the issuance of up to $350 million aggregate principal amount of debt securities. The ability of Northwest Pipeline to utilize their registration statement to issue debt securities is restricted by certain covenants of its debt agreements. If the credit rating of Northwest Pipeline or Transco is below investment grade, they can only use their shelf registration statements to issue debt if such debt is guaranteed by us.
Williams Partners L.P. has a shelf registration statement, which expires in October 2009, available for the issuance of approximately $1.2$1.17 billion aggregate principal amount of debt and limited partnership unit securities.
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In addition, atAt the parent-company level, we have a shelf registration statement, thatwhich as a well-known seasoned issuer, allows us to issue publiclyan unlimited amount of registered debt and equity securities as needed.securities. This shelf registration statement filedexpires in May 19, 2006, replaces2009.
Exploration & Production has an unsecured credit agreement with certain banks that, so long as certain conditions are met, serves to reduce our previously filed shelf registration.use of cash and other credit facilities for margin requirements related to our hedging activities as well as lower transaction fees. The agreement extends through December 2013. (See Note 11 of Notes to Consolidated Financial Statements.)
Credit ratings
Standard & Poor’s rates our senior unsecured debt at BB+ and our corporate credit at BBB-with a stable ratings outlook. With respect to Standard & Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “−” sign to show the obligor’s relative standing within a major rating category.
Moody’s Investors Service rates our senior unsecured debt at Baa3. On November 6, 2008, Moody’s revised our ratings outlook to negative from stable. On February 23, 2009, Moody’s revised our ratings outlook to stable from negative. With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.
Fitch Ratings rates our senior unsecured debt at BBB–. On November 6, 2008, Fitch revised our ratings outlook to evolving from stable. On February 24, 2009, Fitch revised our ratings outlook to stable from evolving. With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “−” sign to show the obligor’s relative standing within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2008, we estimate that a downgrade to a rating below investment grade would have required us to post up to $400 million in additional collateral with third parties.
Sources (Uses) of Cash
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Net cash provided (used) by: | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 1,889.6 | | | $ | 1,449.9 | | | $ | 1,487.9 | | | $ | 3,355 | | | $ | 2,237 | | | $ | 1,890 | |
| Financing activities | | | 1,103.2 | | | | 36.5 | | | | (3,505.5 | ) | | | (432 | ) | | | (511 | ) | | | 1,103 | |
| Investing activities | | | (2,321.4 | ) | | | (819.2 | ) | | | 629.4 | | | | (3,183 | ) | | | (2,296 | ) | | | (2,321 | ) |
| | | | | | | | | | | | | | | |
| Increase (decrease) in cash and cash equivalents | | $ | 671.4 | | | $ | 667.2 | | | $ | (1,388.2 | ) | | $ | (260 | ) | | $ | (570 | ) | | $ | 672 | |
| | | | | | | | | | | | | | | |
Operating Activities
Ournet cash provided by operating activitiesin 20062008 increased from 20052007 due largelyprimarily to higherthe increase in our earnings. Significant transactions impacting ournet cash provided by operating income at Midstream, partially offsetactivitiesin 2008 include:
| | |
| • | $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). |
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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). |
Ournet cash provided by operating activitiesin 2007 increased from 2006 due primarily to the increase in our operating results and the absence of a $145 million securities litigation settlement payment in fourth quarter 2006.
Our 2005net cash provided These increases are partially offset by operating activitiesdecreased slightly from 2004. A primary driverincreased income tax payments innet cash provided by operating activitiesisincome from continuing operations,which increased primarily as a result of higher gas production volumes 2007 and net average realized prices for production sold. Also contributing to the increase in income from continuing operations is the reduction in interest expense due to lower average borrowing levels.
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Cash payments for interest decreased $224 million from 2004. In addition to theother changes in results of operations, net cash inflows from margin deposits and customer margin deposits payable decreased significantly from 2004. In 2004, our Power subsidiary issued a significant number of letters of credit to replace its cash margin deposits. As the letters of credit were issued, the counterparties returned our cash margin deposits to us. Due to fewer letters of credit being issued to replace cash margin deposits in 2005, we have fewer receipts of margin deposits than in 2004.
Other, including changes in noncurrent assets and liabilities,includes contributions to our tax-qualified pension plans of $42.1 million in 2006, $52.1 million in 2005 and $136.8 million in 2004. It is our policy to make annual contributions to our tax-qualified pension plans in an amount at least equal to the greater of the actuarially computed annual normal cost plus any unfunded actuarial accrued liability, amortized over approximately five years, or the minimum required contribution under existing laws. Additional amounts may be contributed to increase the funded status of the plans. In an effort to strengthen our funded status and take advantage of strong cash flows, we contributed approximately $26.5 million, $41.1 million and $98.9 million more than our funding policy required in 2006, 2005 and 2004, respectively.working capital.
Financing Activities
During the first quarter of 2006, we paid $25.8 million in premiums for early debt retirement costs relating to the debt conversion previously discussed.
See Overview, within this section, for a discussion of 2006 debt issuances, debt retirement, and additional financing by Williams Partners L.P.
During January 2005, we retired $200 million of 6.125 percent notes issued by Transco, which matured January 15, 2005. In the first quarter of 2005, we received approximately $273 million inproceeds from the issuance of common stockpurchased under the FELINE PACS equity forward contracts. During August 2005, we completed an initial public offering of approximately 40 percent of our interest in Williams Partners L.P. resulting in net proceeds of $111 million.
During 2004, we repaid long-term debt through tender offers and early retirements. We also reduced our debt through our FELINE PACS exchange. This noncash exchange resulted in payments of fees and expenses reported aspremiums paid on tender offer, early debt retirements and FELINE PACS exchange.2008
| | |
| • | 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. |
Quarterly dividends paid on common stock increased from 7.5 cents to 9 cents per common share during the second quarter
2007
| | |
| • | 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. |
2006 and totaled $206.6 million for year ended December 31, 2006. For the fourth quarter of 2005, dividends paid on common stock were 7.5 cents per share and totaled $143 million for the year ended December 31, 2005.
| | |
| • | 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. |
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| | |
| • | We paid $207 million of quarterly dividends on common stock for the year ended December 31, 2006. |
Investing Activities
During 2006, capital expenditures totaled $2,509.2 million and were primarily related to Exploration & Production’s increased drilling activity, mostly in the Piceance basin, and Northwest Pipeline’s capacity replacement project.2008
| | |
| • | Our net investment in property, plant and equipment totaled $3.3 billion and was primarily related to Exploration & Production’s drilling activity. This total includes Exploration & Production’s acquisitions of certain interests in the Piceance and Fort Worth basins (see Results of Operations — Segments, Exploration & Production). |
|
| • | $148 million of cash received from Exploration & Production’s 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. |
During 2006, we purchased $386.3 million and received $414.1 million from the sale of auction rate securities. These instruments are utilized as a component of our overall cash management program.
2007
| | |
| • | Our net investment in property, plant and equipment totaled $2.9 billion and was primarily related to Exploration & Production’s drilling activity, mostly in the Piceance basin. |
|
| • | We received $496 million of gross proceeds from the sale of substantially all of our power business. |
|
| • | We purchased $304 million and received $353 million from the sale of auction rate securities. These were utilized as a component of our overall cash management program. |
In January 2005, Northwest Pipeline received an $87.9 million contract termination payment, representing reimbursement of the net book value of the related assets.
2006
In January 2005, we received approximately $54.7 million proceeds from the sale of our note with Williams Communications Group, our previously owned subsidiary (WilTel).
During 2005, we received $310.5 million in proceeds from the Gulfstream recapitalization.
In 2004, we sold all of our restricted investments resulting in proceeds of $851.4 million. When our $800 million revolving and letter of credit facility that required 105 percent cash collateral was replaced with a new revolving credit facility in January 2005, we were no longer required to hold the restricted investments.
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In 2004, we had numerous asset sales resulting in proceeds in 2004 of $877.8 million.
| | |
| • | Our net investment in property, plant and equipment totaled $2.4 billion and was primarily related to Exploration & Production’s drilling activity, mostly in the Piceance basin, and Northwest Pipeline’s capacity replacement project. |
|
| • | We purchased $386 million and received $414 million from the sale of auction rate securities. |
Off-balance sheet financing arrangements and guarantees of debt or other commitments
In January 2005, we terminated our two unsecured revolving and letter of credit facilities totaling $500 million and replaced them with two new facilities that contain similar terms but fewer restrictions. In September 2005, we also entered into two new revolving and letter of credit facilities that have a similar structure. (See Note 11 of Notes to Consolidated Financial Statements.)
We have provided a guarantee for obligations of Williams Partners L.P. under the $1.5 billion unsecured revolving and letter of credit facility.
We have various other guarantees and commitments which are disclosed in Notes 3, 9, 10, 11, 14,15, and 1516 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.
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Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations, by period.including obligations related to discontinued operations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 2008-
| | 2010-
| | | | | | | | | 2010-
| | 2012-
| | | | | |
| | | 2007 | | 2009 | | 2011 | | Thereafter | | Total | | | 2009 | | 2011 | | 2013 | | Thereafter | | Total | |
| | | (Millions) | | | (Millions) | |
| |
| Long-term debt, including current portion: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Principal | | $ | 391 | | | $ | 291 | | | $ | 1,385 | | | $ | 5,974 | | | $ | 8,041 | | | $ | 53 | | | $ | 994 | | | $ | 1,248 | | | $ | 5,611 | | | $ | 7,906 | |
| Interest | | | 606 | | | | 1,147 | | | | 1,083 | | | | 5,713 | | | | 8,549 | | | | 588 | | | | 1,151 | | | | 894 | | | | 4,452 | | | | 7,085 | |
| Capital leases | | | 2 | | | | 3 | | | | — | | | | — | | | | 5 | | | | 3 | | | | 2 | | | | — | | | | — | | | | 5 | |
Operating leases(1) | | | 227 | | | | 433 | | | | 366 | | | | 1,121 | | | | 2,147 | | | | 96 | | | | 80 | | | | 42 | | | | 44 | | | | 262 | |
| Purchase obligations: | | | | | | | | | | | | | | | | | | | | | |
| Fuel conversion and other service contracts(2)(5) | | | 249 | | | | 505 | | | | 495 | | | | 2,377 | | | | 3,626 | | |
| Purchase obligations(2) | | | | 1,299 | | | | 1,342 | | | | 1,209 | | | | 2,405 | | | | 6,255 | |
| Other long-term liabilities, including current portion: | | | | | | | | | | | | | | | | | | | | | |
| Physical and financial derivatives(3)(4) | | | | 575 | | | | 606 | | | | 296 | | | | 196 | | | | 1,673 | |
| Other(5)(6) | | | 877 | | | | 1,134 | | | | 1,144 | | | | 2,943 | (4) | | | 6,098 | | | | — | | | | 1 | | | | — | | | | — | | | | 1 | |
| Other long-term liabilities, including current portion: | | | | | | | | | | | | | | | | | | | | | |
| Physical and financial derivatives(3)(5) | | | 628 | | | | 392 | | | | 204 | | | | 304 | | | | 1,528 | | |
| Other(7) | | | 72 | | | | 31 | | | | 16 | | | | — | | | | 119 | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 3,052 | | | $ | 3,936 | | | $ | 4,693 | | | $ | 18,432 | | | $ | 30,113 | | | $ | 2,614 | | | $ | 4,176 | | | $ | 3,689 | | | $ | 12,708 | | | $ | 23,187 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Excludes sublease incomeThe debt instruments in this table are classified by stated maturity date. See Note 11 of $1.2 billion consistingNotes to Consolidated Financial Statements for discussion of $331 million in 2007, $564 million in2008-2009, and $258 million in2010-2011. Includes a Power tolling agreementcertain non-recourse debt of two of our Venezuelan subsidiaries that is accounted forin technical default and classified as an operating lease.current on our Consolidated Balance Sheet. |
| |
| (2) | | Power has entered into certain contracts giving us the right to receive fuel conversion services as well as certain other services associated with electric generation facilities that are currently in operation throughout the continental United States. CertainIncludes $3.7 billion of Power’s tolling agreements couldnatural gas purchase obligations at market prices at our Exploration & Production segment. The purchased natural gas can be considered leases pursuant to the guidance in EITF Issue01-8, “Determining Whether an Arrangement Contains a Lease,” if in the future the agreements are modified for any reason. If deemed to be a capital lease, the net present value of the fixed demand payments would be reported on the Consolidated Balance Sheet consistent with other capital lease obligations, and as an asset inproperty, plant and equipment — net. See Note 1 of Notes to the Consolidated Financial Statements for further information.sold at market prices. |
| |
| (3) | | The obligations for physical and financial derivatives are based on market information as of December 31, 2006.2008 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) | | Includes one year of annual payments totaling $2 million for contracts with indefinite termination dates. |
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| | |
(5) | | Expected offsetting cash inflows of $7.2$3.6 billion at December 31, 2006,2008, 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. |
| |
(6) | | Includes $4.5 billion of natural gas purchase obligations at market prices at our Exploration & Production segment. The purchased natural gas can be sold at market prices. |
|
(7)(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 $58$75 million in 20062008 and $73$56 million in 2005.2007. In 2007,2009, we expect to contribute approximately $57$77 million to these plans (see Note 7 of Notes to Consolidated Financial Statements), including $40. During 2008, we contributed $60 million to our tax-qualified pension plans. There were noplans which was greater than the minimum funding requirements torequirements. 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 2006 or 2005, and we do not expect any2009, which is expected to be greater than the minimum funding requirements. Estimated future minimum funding requirements in 2007. We anticipate that future contributions will notmay vary significantly from recent historical contributions, assumingrequirements if investment returns do not return to expected levels. Future minimum funding requirements may also be impacted if actual results do not differ significantly from estimated results for assumptions such as discountinterest rates, returns on plan assets, retirement rates, mortality and other significant assumptions and assuming no furtheror by changes into current and prospective legislation and regulations. Based on |
|
| (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 anticipated levelsliabilities. Therefore, these liabilities have been excluded from the table above. See Note 5 of future contributions, we do not expectNotes to trigger any minimum funding requirements in the future.Consolidated Financial Statements for information regarding our contingent tax liability reserves. |
Effects of Inflation
Our operations in recent years have benefited from relatively low inflation rates. Approximately 4638 percent of our gross property, plant and equipment is at Gas Pipeline and the remainder is at other operating units.Pipeline. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing
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assets. Cost-based regulation, along with competition and other market factors, may limit our ability to recover such increased costs. For the other operating units, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in oil and natural gas and related commodities than by changes in general inflation. Crude, refined product, natural gas, and natural gas liquids and power prices are particularly sensitive to OPECthe Organization of the Petroleum Exporting Countries (OPEC) production levelsand/or the market perceptions concerning the supply and demand balance in the near future.future, as well as general economic conditions. However, our exposure to these price changes is reduced through the use of hedging instruments.instruments and the fee-based nature of certain of our services.
Environmental
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operationsand/or remedial processes at certain sites, some of which we currently do not own. (Seeown (see Note 1516 of Notes to Consolidated Financial Statements.)Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $52$43 million, all of which are recorded as liabilities on our balance sheet at December 31, 2006.2008. We will seek recovery of approximately $11$14 million of the accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2006,2008, we paid approximately $12$10 million for cleanupand/or remediation and monitoring activities. We expect to pay approximately $17$11 million in 20072009 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2006,2008, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
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We are subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990, which require the EPA to issue new regulations. We are also subject to regulation at the state and local level. In September 1998, the EPA promulgated rules designed to mitigate the migration of ground-level ozone in certain states. In March 2004 and June 2004, the EPA promulgated additional regulation regarding hazardous air pollutants, which may imposeresult in additional controls. Capital expenditures necessary to install emission control devices on our Transco gas pipeline system to comply with rules were approximately $41$2 million in 20062008 and are estimated to be between $35$5 million and $40$10 million through 2010.2012. The actual costs incurred will depend on the final implementation plans developed by each state to comply with these regulations. We consider these costs on our Transco system associated with compliance with these environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.
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| |
| Item 7A. | QualitativeQuantitative and QuantitativeQualitative Disclosures About Market Risk |
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio. The majority of our debt portfolio is comprised of fixed rate debt in order to mitigate the impact of fluctuations in interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets.
The tables below provide information about our interest rate risk-sensitive instruments as of December 31, 20062008 and 2005.2007. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Fair Value
| | | | | | | | | | | | | | | | | Fair Value
| |
| | | | | | | | | | | | | | | | | December 31,
| | | | | | | | | | | | | | | | | December 31,
| |
| | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | Thereafter(1) | | Total | | 2006 | | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | Thereafter(1) | | Total | | 2008 | |
| | | (Dollars in millions) | | | (Dollars in millions) | |
| |
| Long-term debt, including current portion(4): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt, including current portion(4)(6): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed rate | | $ | 381 | | | $ | 153 | | | $ | 41 | | | $ | 205 | | | $ | 1,161 | | | $ | 5,922 | | | $ | 7,863 | | | $ | 8,343 | | | $ | 41 | | | $ | 27 | | | $ | 948 | | | $ | 971 | | | $ | 17 | | | $ | 5,566 | | | $ | 7,570 | | | $ | 6,011 | |
| Interest rate | | | 7.7 | % | | | 7.7 | % | | | 7.7 | % | | | 7.5 | % | | | 7.6 | % | | | 7.8 | % | | | | | | | | | | | 7.6 | % | | | 7.6 | % | | | 7.6 | % | | | 7.6 | % | | | 7.5 | % | | | 7.9 | % | | | | | | | | |
| Variable rate | | $ | 10 | | | $ | 85 | | | $ | 12 | | | $ | 12 | | | $ | 7 | | | $ | 23 | | | $ | 149 | | | $ | 137 | | | $ | 12 | | | $ | 12 | | | $ | 7 | | | $ | 255 | | | $ | 5 | | | $ | 13 | | | $ | 304 | | | $ | 274 | |
| Interest rate(2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Fair Value
| | | | | | | | | | | | | | | | | Fair Value
| |
| | | | | | | | | | | | | | | | | December 31,
| | | | | | | | | | | | | | | | | December 31,
| |
| | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter(1) | | Total | | 2005 | | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | Thereafter(1) | | Total | | 2007 | |
| | | (Dollars in millions) | | | (Dollars in millions) | |
| |
| Long-term debt, including current portion(4): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed rate | | $ | 104 | | | $ | 381 | | | $ | 153 | | | $ | 41 | | | $ | 205 | | | $ | 6,179 | | | $ | 7,063 | | | $ | 7,952 | | | $ | 53 | | | $ | 41 | | | $ | 27 | | | $ | 948 | | | $ | 971 | | | $ | 5,111 | | | $ | 7,151 | | | $ | 7,994 | |
| Interest rate | | | 7.7 | % | | | 7.7 | % | | | 7.8 | % | | | 7.8 | % | | | 7.8 | % | | | 7.8 | % | | | | | | | | | | | 7.7 | % | | | 7.7 | % | | | 7.4 | % | | | 7.4 | % | | | 7.3 | % | | | 7.7 | % | | | | | | | | |
| Variable rate | | $ | 15 | | | $ | 15 | | | $ | 563 | | | $ | 12 | | | $ | 12 | | | $ | 30 | | | $ | 647 | | | $ | 647 | | | $ | 85 | | | $ | 12 | | | $ | 12 | | | $ | 7 | | | $ | 605 | (5) | | $ | 18 | | | $ | 739 | | | $ | 735 | |
| Interest rate(3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | IncludingIncludes unamortized discount and premium. |
| |
| (2) | | The weighted-average interest rate for 2006at December 31, 2008, is LIBOR plus 10.76 percent. |
| |
| (3) | | The weighted-average interest rate for 2005at December 31, 2007 was LIBOR plus 20.75 percent. |
| |
| (4) | | Excludes capital leases. |
|
| (5) | | Includes Transco’s 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. |
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of natural gas electricity, and natural gas liquids, as well as other market factors, such as market volatility and commodity price correlations, including correlations between natural gas and power prices.correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our proprietary trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to changes in energy-commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. We measure the risk in our portfolios using avalue-at-risk methodology to estimate the potentialone-day loss from adverse changes in the fair value of the portfolios.
75
Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Ourvalue-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that theone-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying thevalue-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions
76
or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than aone-day holding period to execute. While aone-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Derivative contracts designated as normal purchases or sales under SFAS No. 133 and nonderivative energy contracts have been excluded from our estimation of value at risk.
Trading
Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net liability of $29 million at December 31, 2008. Our value at risk for contracts held for trading purposes was approximately$0.2 million at December 31, 2008, and $1 million at December 31, 2006, and $4 million at December 31, 2005.2007. During the year ended December 31, 2006,2008, our value at risk for these contracts ranged from a high of $4$3.3 million to a low of $1$0.2 million.
Nontrading
Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from the following activities:
| | | |
Segment | | Commodity Price Risk Exposure |
| |
| Exploration & Production | | • Natural gas sales |
| | |
| Midstream | | • Natural gas purchases |
| | |
PowerGas Marketing Services | | • Natural gas purchases and sales |
| | • Electricity purchases and sales |
The fair value of our nontrading derivatives was a net asset of $511 million at December 31, 2008.
The value at risk for derivative contracts held for nontrading purposes was $12$33 million at December 31, 2006,2008, and $28$24 million at December 31, 2005.2007. During the year ended December 31, 2006,2008, our value at risk for these contracts ranged from a high of $25$72 million to a low of $12$33 million. The increase in value at risk reflects the impact on our nontrading portfolio of the increase in volumes of Exploration & Production hedges in 2009 and 2010. Derivative contracts included in our assets and liabilities of discontinued operations are included in the nontrading portfolio, but these had a value at risk of zero for both periods.
Certain of the derivative contracts held for nontrading purposes are accounted for as cash flow hedges under SFAS No. 133. Of the total fair value of nontrading derivatives, SFAS No. 133 cash flow hedges had a net asset value of $458 million as of December 31, 2008. Though these contracts are included in ourvalue-at-risk calculation, any change in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.
Trading Policy
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations.Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.
76
Foreign Currency Risk
We have international investments that could affect our financial results if the investments incur a permanent decline in value as a result of changes in foreign currency exchange ratesand/or the economic conditions in foreign countries.
International investments accounted for under the cost method totaled $42$17 million at December 31, 2006,2008, and $45$24 million at December 31, 2005.2007. These investments are primarily in nonpublicly traded companies for which it is not practicable to estimate fair value. We believe that we can realize the carrying value of these investments considering the status of the operations of the companies underlying these investments. If a 20 percent change occurred in the value of the underlying currencies of these investments against the U.S. dollar, the fair value at December 31, 2006, could change by approximately $8.3 million assuming a direct correlation between the currency fluctuation and the value of the investments.
Net assets of consolidated foreign operations, whose functional currency is the local currency, are located primarily in Canada and approximate 65 percent and 7 percent of our net assets at December 31, 20062008 and 2005.2007, respectively. These foreign operations do not have significant transactions or financial instruments denominated in other currencies. However, these investments do have the potential to impact our financial position, due to fluctuations in these local currencies arising from the process of re-measuringtranslating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar couldwould have changedstockholders’ equityby approximately $68$84 million at December 31, 2006.2008.
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| |
| Item 8. | Financial Statements and Supplementary Data |
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Williams’ managementManagement is responsible for establishing and maintaining adequate internal control over financial reporting (as defined inRules 13a-15(f) and15d-15(f) under the Securities Exchange Act of 1934) and for the assessment of the effectiveness of. Our internal controlcontrols over financial reporting. Our internal control system wasreporting are designed to provide reasonable assurance to our management and Boardboard of Directorsdirectors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations.limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to
Under the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancesupervision and with the policies or procedures may deteriorate.
Ourparticipation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of Williams’our internal control over financial reporting as of December 31, 2006. In making this assessment, management used2008, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based on our assessment we believe that, as of December 31, 2006, Williams’2008, our internal control over financial reporting is effective based on those criteria.was effective.
Ernst & Young LLP, our independent registered public accounting firm, has issued an audit report onaudited our assessment of the company’s internal control over financial reporting. A copy of thisreporting, as stated in their report which is included in this Annual Report onForm 10-K.
78
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that The Williams Companies, Inc. maintained effective’s internal control over financial reporting as of December 31, 2006,2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Williams Companies, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting.reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment,assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that The Williams Companies, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, The Williams Companies, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006,2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of The Williams Companies, Inc. as of December 31, 20062008 and 2005,2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 20062008 of The Williams Companies, Inc. and our report dated February 22, 200723, 2009 expressed an unqualified opinion thereon.
Tulsa, Oklahoma
February 22, 200723, 2009
79
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. as of December 31, 20062008 and 2005,2007, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006.2008. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Williams Companies, Inc. at December 31, 20062008 and 2005,2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006,2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As explained in Note 15 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R),Share-Based Paymentand as explained in Note 7 to the consolidated financial statements, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. Also, as explained in Note 9 to the consolidated financial statements, effective December 31, 2005,2007 the Company adopted FASB Interpretation No. 47,48,Accounting for Conditional Asset Retirement Obligations.Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2006,2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 200723, 2009 expressed an unqualified opinion thereon.
Tulsa, Oklahoma
February 22, 200723, 2009
80
THE WILLIAMS COMPANIES, INC.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions, except per-share amounts) | | | (Millions, except per-share amounts) | |
| |
| Revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
| Exploration & Production | | $ | 1,487.6 | | | $ | 1,269.1 | | | $ | 777.6 | | | $ | 3,121 | | | $ | 2,021 | | | $ | 1,411 | |
| Gas Pipeline | | | 1,347.7 | | | | 1,412.8 | | | | 1,362.3 | | | | 1,634 | | | | 1,610 | | | | 1,348 | |
| Midstream Gas & Liquids | | | 4,124.7 | | | | 3,232.7 | | | | 2,882.6 | | | | 5,642 | | | | 5,180 | | | | 4,159 | |
| Power | | | 7,462.4 | | | | 9,093.9 | | | | 9,272.4 | | |
| Gas Marketing Services | | | | 6,412 | | | | 4,633 | | | | 5,049 | |
| Other | | | 26.5 | | | | 27.2 | | | | 32.8 | | | | 24 | | | | 26 | | | | 27 | |
| Intercompany eliminations | | | (2,636.0 | ) | | | (2,452.1 | ) | | | (1,866.4 | ) | | | (4,481 | ) | | | (2,984 | ) | | | (2,695 | ) |
| | | | | | | | | | | | | | | |
| Total revenues | | | 11,812.9 | | | | 12,583.6 | | | | 12,461.3 | | | | 12,352 | | | | 10,486 | | | | 9,299 | |
| | | | | | | | | | | | | | | |
| Segment costs and expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
| Costs and operating expenses | | | 9,973.6 | | | | 10,871.0 | | | | 10,751.7 | | | | 9,156 | | | | 8,007 | | | | 7,489 | |
| Selling, general and administrative expenses | | | 449.2 | | | | 325.4 | | | | 355.5 | | | | 504 | | | | 471 | | | | 389 | |
| Other (income) expense — net | | | 20.7 | | | | 61.2 | | | | (51.6 | ) | | | (82 | ) | | | (18 | ) | | | 34 | |
| | | | | | | | | | | | | | | |
| Total segment costs and expenses | | | 10,443.5 | | | | 11,257.6 | | | | 11,055.6 | | | | 9,578 | | | | 8,460 | | | | 7,912 | |
| | | | | | | | | | | | | | | |
| General corporate expenses | | | 132.1 | | | | 145.5 | | | | 119.8 | | | | 149 | | | | 161 | | | | 132 | |
| Securities litigation settlement and related costs | | | 167.3 | | | | 9.4 | | | | — | | | | — | | | | — | | | | 167 | |
| | | | | | | | | | | | | | | |
| Operating income (loss): | | | | | | | | | | | | | | | | | | | | | | | | |
| Exploration & Production | | | 529.7 | | | | 568.4 | | | | 223.9 | | | | 1,240 | | | | 731 | | | | 530 | |
| Gas Pipeline | | | 430.3 | | | | 542.2 | | | | 557.6 | | | | 630 | | | | 622 | | | | 430 | |
| Midstream Gas & Liquids | | | 631.3 | | | | 446.6 | | | | 552.2 | | | | 904 | | | | 1,011 | | | | 635 | |
| Power | | | (223.8 | ) | | | (236.8 | ) | | | 86.5 | | |
| Gas Marketing Services | | | | 3 | | | | (337 | ) | | | (195 | ) |
| Other | | | 1.9 | | | | 5.6 | | | | (14.5 | ) | | | (3 | ) | | | (1 | ) | | | (13 | ) |
| General corporate expenses | | | (132.1 | ) | | | (145.5 | ) | | | (119.8 | ) | | | (149 | ) | | | (161 | ) | | | (132 | ) |
| Securities litigation settlement and related costs | | | (167.3 | ) | | | (9.4 | ) | | | — | | | | — | | | | — | | | | (167 | ) |
| | | | | | | | | | | | | | | |
| Total operating income | | | 1,070.0 | | | | 1,171.1 | | | | 1,285.9 | | | | 2,625 | | | | 1,865 | | | | 1,088 | |
| | | | | | | | | | | | | | | |
| Interest accrued | | | (676.1 | ) | | | (671.7 | ) | | | (834.4 | ) | | | (653 | ) | | | (685 | ) | | | (670 | ) |
| Interest capitalized | | | 17.2 | | | | 7.2 | | | | 6.7 | | | | 59 | | | | 32 | | | | 17 | |
| Investing income | | | 173.0 | | | | 23.7 | | | | 48.0 | | | | 191 | | | | 257 | | | | 168 | |
| Early debt retirement costs | | | (31.4 | ) | | | (0.4 | ) | | | (282.1 | ) | | | (1 | ) | | | (19 | ) | | | (31 | ) |
| Minority interest in income of consolidated subsidiaries | | | (40.0 | ) | | | (25.7 | ) | | | (21.4 | ) | | | (174 | ) | | | (90 | ) | | | (40 | ) |
| Other income — net | | | 26.4 | | | | 27.1 | | | | 21.8 | | | | — | | | | 11 | | | | 26 | |
| | | | | | | | | | | | | | | |
| Income from continuing operations before income taxes and cumulative effect of change in accounting principle | | | 539.1 | | | | 531.3 | | | | 224.5 | | |
| Income from continuing operations before income taxes | | | | 2,047 | | | | 1,371 | | | | 558 | |
| Provision for income taxes | | | 206.3 | | | | 213.9 | | | | 131.3 | | | | 713 | | | | 524 | | | | 211 | |
| | | | | | | | | | | | | | | |
| Income from continuing operations | | | 332.8 | | | | 317.4 | | | | 93.2 | | | | 1,334 | | | | 847 | | | | 347 | |
| Income (loss) from discontinued operations | | | (24.3 | ) | | | (2.1 | ) | | | 70.5 | | | | 84 | | | | 143 | | | | (38 | ) |
| | | | | | | | | |
| Income before cumulative effect of change in accounting principle | | | 308.5 | | | | 315.3 | | | | 163.7 | | |
| Cumulative effect of change in accounting principle | | | — | | | | (1.7 | ) | | | — | | |
| | | | | | | | | | | | | | | |
| Net income | | $ | 308.5 | | | $ | 313.6 | | | $ | 163.7 | | | $ | 1,418 | | | $ | 990 | | | $ | 309 | |
| | | | | | | | | | | | | | | |
| Basic earnings (loss) per common share: | | | | | | | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | | $ | .56 | | | $ | .55 | | | $ | .18 | | | $ | 2.30 | | | $ | 1.42 | | | $ | .58 | |
| Income (loss) from discontinued operations | | | (.04 | ) | | | — | | | | .13 | | | | .14 | | | | .24 | | | | (.06 | ) |
| | | | | | | | | |
| Income before cumulative effect of change in accounting principle | | | .52 | | | | .55 | | | | .31 | | |
| Cumulative effect of change in accounting principle | | | — | | | | — | | | | — | | |
| | | | | | | | | | | | | | | |
| Net income | | $ | .52 | | | $ | .55 | | | $ | .31 | | | $ | 2.44 | | | $ | 1.66 | | | $ | .52 | |
| | | | | | | | | | | | | | | |
| Weighted-average shares (thousands) | | | 595,053 | | | | 570,420 | | | | 529,188 | | | | 581,342 | | | | 596,174 | | | | 595,053 | |
| | | | | | | | | | | | | | | |
| Diluted earnings (loss) per common share: | | | | | | | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | | $ | .55 | | | $ | .53 | | | $ | .18 | | | $ | 2.26 | | | $ | 1.40 | | | $ | .57 | |
| Income (loss) from discontinued operations | | | (.04 | ) | | | — | | | | .13 | | | | .14 | | | | .23 | | | | (.06 | ) |
| | | | | | | | | | | | | | | |
| Income before cumulative effect of change in accounting principle | | | .51 | | | | .53 | | | | .31 | | |
| Cumulative effect of change in accounting principle | | | — | | | | — | | | | — | | |
| | | | | | | | | |
| Net income | | $ | .51 | | | $ | .53 | | | $ | .31 | | | $ | 2.40 | | | $ | 1.63 | | | $ | .51 | |
| | | | | | | | | | | | | | | |
| Weighted-average shares (thousands) | | | 608,627 | | | | 605,847 | | | | 535,611 | | | | 592,719 | | | | 609,866 | | | | 608,627 | |
| | | | | | | | | | | | | | | |
See accompanying notes.
81
THE WILLIAMS COMPANIES, INC.
| | | | | | | | | | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Dollars in millions, except per-share amounts) | | | (Dollars in millions, except per-share amounts) | |
| |
ASSETS | ASSETS | ASSETS |
| Current assets: | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 2,268.6 | | | $ | 1,597.2 | | | $ | 1,439 | | | $ | 1,699 | |
| Restricted cash | | | 91.6 | | | | 92.9 | | |
| Accounts and notes receivable (net of allowance of $15.9 million in 2006 and $86.6 million in 2005) | | | 1,212.9 | | | | 1,613.8 | | |
| Accounts and notes receivable (net of allowance of $40 at December 31, 2008 and $27 at December 31, 2007) | | | | 941 | | | | 1,192 | |
| Inventories | | | 241.4 | | | | 272.6 | | | | 260 | | | | 209 | |
| Derivative assets | | | 1,878.2 | | | | 5,299.7 | | | | 1,464 | | | | 1,736 | |
| Margin deposits | | | 59.3 | | | | 349.2 | | |
| Assets of discontinued operations | | | | 6 | | | | 185 | |
| Deferred income taxes | | | 337.2 | | | | 241.0 | | | | — | | | | 199 | |
| Other current assets and deferred charges | | | 232.8 | | | | 230.9 | | | | 301 | | | | 318 | |
| | | | | | | | | | | |
| Total current assets | | | 6,322.0 | | | | 9,697.3 | | | | 4,411 | | | | 5,538 | |
| Restricted cash | | | 34.5 | | | | 36.5 | | |
| Investments | | | 866.0 | | | | 887.8 | | | | 971 | | | | 901 | |
| Property, plant and equipment — net | | | 14,180.7 | | | | 12,409.2 | | | | 18,065 | | | | 15,981 | |
| Derivative assets | | | 2,384.9 | | | | 4,656.9 | | | | 986 | | | | 859 | |
| Goodwill | | | 1,011.4 | | | | 1,014.5 | | | | 1,011 | | | | 1,011 | |
| Other assets and deferred charges | | | 602.9 | | | | 740.4 | | | | 562 | | | | 771 | |
| | | | | | | | | | | |
| Total assets | | $ | 25,402.4 | | | $ | 29,442.6 | | | $ | 26,006 | | | $ | 25,061 | |
| | | | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | LIABILITIES AND STOCKHOLDERS’ EQUITY | LIABILITIES AND STOCKHOLDERS’ EQUITY |
| Current liabilities: | | | | | | | | | | | | | | | | |
| Accounts payable | | $ | 1,148.5 | | | $ | 1,360.6 | | | $ | 1,059 | | | $ | 1,131 | |
| Accrued liabilities | | | 1,241.4 | | | | 1,123.1 | | | | 1,170 | | | | 1,158 | |
| Customer margin deposits payable | | | 128.7 | | | | 320.7 | | |
| Derivative liabilities | | | 1,782.9 | | | | 5,523.2 | | | | 1,093 | | | | 1,824 | |
| Liabilities of discontinued operations | | | | 1 | | | | 175 | |
| Long-term debt due within one year | | | 392.1 | | | | 122.6 | | | | 196 | | | | 143 | |
| | | | | | | | | | | |
| Total current liabilities | | | 4,693.6 | | | | 8,450.2 | | | | 3,519 | | | | 4,431 | |
| Long-term debt | | | 7,622.0 | | | | 7,590.5 | | | | 7,683 | | | | 7,757 | |
| Deferred income taxes | | | 2,879.9 | | | | 2,508.9 | | | | 3,390 | | | | 2,996 | |
| Derivative liabilities | | | 2,043.8 | | | | 4,331.1 | | | | 875 | | | | 1,139 | |
| Other liabilities and deferred income | | | 1,009.1 | | | | 920.3 | | | | 1,485 | | | | 933 | |
| Contingent liabilities and commitments (Note 15) | | | | | | | | | |
| Contingent liabilities and commitments (Note 16) | | | | | | | | | |
| Minority interests in consolidated subsidiaries | | | 1,080.8 | | | | 214.1 | | | | 614 | | | | 1,430 | |
| Stockholders’ equity: | | | | | | | | | | | | | | | | |
| Common stock (960 million shares authorized at $1 par value; 602.8 million shares issued at December 31, 2006, and 579.1 million shares issued at December 31,2005) | | | 602.8 | | | | 579.1 | | |
| Common stock (960 million shares authorized at $1 par value; 613 million shares issued at December 31, 2008, and 608 million shares issued at December 31, 2007) | | | | 613 | | | | 608 | |
| Capital in excess of par value | | | 6,605.7 | | | | 6,327.8 | | | | 8,074 | | | | 6,748 | |
| Accumulated deficit | | | (1,034.0 | ) | | | (1,135.9 | ) | |
| Retained earnings (deficit) | | | | 874 | | | | (293 | ) |
| Accumulated other comprehensive loss | | | (60.1 | ) | | | (297.8 | ) | | | (80 | ) | | | (121 | ) |
| Other | | | — | | | | (4.5 | ) | |
| | | | | | | | | | | |
| | | | 6,114.4 | | | | 5,468.7 | | | | 9,481 | | | | 6,942 | |
| Less treasury stock, at cost (5.7 million shares of common stock in 2006 and 2005) | | | (41.2 | ) | | | (41.2 | ) | |
| Less treasury stock, at cost (35 million shares of common stock at December 31, 2008 and 22 million shares of common stock at December 31, 2007) | | | | (1,041 | ) | | | (567 | ) |
| | | | | | | | | | | |
| Total stockholders’ equity | | | 6,073.2 | | | | 5,427.5 | | | | 8,440 | | | | 6,375 | |
| | | | | | | | | | | |
| Total liabilities and stockholders’ equity | | $ | 25,402.4 | | | $ | 29,442.6 | | | $ | 26,006 | | | $ | 25,061 | |
| | | | | | | | | | | |
See accompanying notes.
82
THE WILLIAMS COMPANIES, INC.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Accumulated
| | | | | | | | | | | | | | | Accumulated
| | | | | | | |
| | | | | Capital in
| | | | Other
| | | | | | | | | | | Capital in
| | Retained
| | Other
| | | | | | | |
| | | Common
| | Excess of
| | Accumulated
| | Comprehensive
| | | | Treasury
| | | | | Common
| | Excess of
| | Earnings
| | Comprehensive
| | | | Treasury
| | | |
| | | Stock | | Par Value | | Deficit | | Loss | | Other | | Stock | | Total | | | Stock | | Par Value | | (Deficit) | | Loss | | Other | | Stock | | Total | |
| | | (Dollars in millions) | | | (Dollars in millions, except per-share amounts) | |
| | |
Balance, December 31, 2003 | | $ | 524.0 | | | $ | 5,195.1 | | | $ | (1,426.8 | ) | | $ | (121.0 | ) | | $ | (28.0 | ) | | $ | (41.2 | ) | | $ | 4,102.1 | | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income — 2004 | | | — | | | | — | | | | 163.7 | | | | — | | | | — | | | | — | | | | 163.7 | | |
| Other comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized losses on cash flow hedges, net of reclassification adjustments | | | — | | | | — | | | | — | | | | (142.7 | ) | | | — | | | | — | | | | (142.7 | ) | |
| Net unrealized appreciation on marketable equity securities, net of reclassification adjustments | | | — | | | | — | | | | — | | | | 1.9 | | | | — | | | | — | | | | 1.9 | | |
| Foreign currency translation adjustments | | | — | | | | — | | | | — | | | | 15.8 | | | | — | | | | — | | | | 15.8 | | |
| Minimum pension liability adjustment | | | — | | | | — | | | | — | | | | 1.8 | | | | — | | | | — | | | | 1.8 | | |
| | | | | |
| Total other comprehensive loss | | | | | | | | | | | | | | | | | | | | | | | | | | | (123.2 | ) | |
| | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | 40.5 | | |
| Issuance of common stock and settlement of forward contracts as a result of FELINE PACS exchange | | | 33.1 | | | | 782.9 | | | | — | | | | — | | | | — | | | | — | | | | 816.0 | | |
| Cash dividends — Common stock ($.08 per share) | | | — | | | | — | | | | (43.4 | ) | | | — | | | | — | | | | — | | | | (43.4 | ) | |
| Allowance for and repayment of stockholders’ notes | | | — | | | | — | | | | — | | | | — | | | | 6.1 | | | | — | | | | 6.1 | | |
| Stock award transactions, including tax benefit | | | 6.7 | | | | 27.9 | | | | — | | | | — | | | | — | | | | — | | | | 34.6 | | |
| | | | | | | | | | | | | | | | | |
Balance, December 31, 2004 | | | 563.8 | | | | 6,005.9 | | | | (1,306.5 | ) | | | (244.2 | ) | | | (21.9 | ) | | | (41.2 | ) | | | 4,955.9 | | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income — 2005 | | | — | | | | — | | | | 313.6 | | | | — | | | | — | | | | — | | | | 313.6 | | |
| Other comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized losses on cash flow hedges, net of reclassification adjustments | | | — | | | | — | | | | — | | | | (65.4 | ) | | | — | | | | — | | | | (65.4 | ) | |
| Foreign currency translation adjustments | | | — | | | | — | | | | — | | | | 11.4 | | | | — | | | | — | | | | 11.4 | | |
| Minimum pension liability adjustment | | | | | | | — | | | | — | | | | .4 | | | | — | | | | | | | | .4 | | |
| | | | | |
| Total other comprehensive loss | | | | | | | | | | | | | | | | | | | | | | | | | | | (53.6 | ) | |
| | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | 260.0 | | |
| Issuance of common stock and settlement of forward contracts as a result of FELINE PACS exchange | | | 10.9 | | | | 261.9 | | | | — | | | | — | | | | — | | | | — | | | | 272.8 | | |
| Cash dividends — Common stock ($.25 per share) | | | — | | | | — | | | | (143.0 | ) | | | — | | | | — | | | | — | | | | (143.0 | ) | |
| Allowance for and repayment of stockholders’ notes | | | — | | | | — | | | | — | | | | — | | | | 17.4 | | | | — | | | | 17.4 | | |
| Stock award transactions, including tax benefit | | | 4.4 | | | | 60.0 | | | | — | | | | — | | | | — | | | | — | | | | 64.4 | | |
| | | | | | | | | | | | | | | | |
Balance, December 31, 2005 | | | 579.1 | | | | 6,327.8 | | | | (1,135.9 | ) | | | (297.8 | ) | | | (4.5 | ) | | | (41.2 | ) | | | 5,427.5 | | | $ | 579 | | | $ | 6,328 | | | $ | (1,136 | ) | | $ | (298 | ) | | $ | (5 | ) | | $ | (41 | ) | | $ | 5,427 | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income — 2006 | | | — | | | | — | | | | 308.5 | | | | — | | | | — | | | | — | | | | 308.5 | | | | — | | | | — | | | | 309 | | | | — | | | | — | | | | — | | | | 309 | |
| Other comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized gains on cash flow hedges, net of reclassification adjustments | | | — | | | | — | | | | — | | | | 394.2 | | | | — | | | | — | | | | 394.2 | | | | — | | | | — | | | | — | | | | 394 | | | | — | | | | — | | | | 394 | |
| Foreign currency translation adjustments | | | — | | | | — | | | | — | | | | (4.7 | ) | | | — | | | | — | | | | (4.7 | ) | | | — | | | | — | | | | — | | | | (4 | ) | | | — | | | | — | | | | (4 | ) |
| Minimum pension liability adjustment | | | — | | | | — | | | | — | | | | (.9 | ) | | | — | | | | — | | | | (.9 | ) | | | — | | | | — | | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) |
| | | | | | | |
| Total other comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | 388.6 | | | | | | | | | | | | | | | | | | | | | | | | | | | | 389 | |
| | | | | | | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | 697.1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | 698 | |
| Adjustment to initially apply SFAS No. 158, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | | — | | | | — | | | | — | | | | (3.5 | ) | | | — | | | | — | | | | (3.5 | ) | | | — | | | | — | | | | — | | | | (4 | ) | | | — | | | | — | | | | (4 | ) |
| Net actuarial loss | | | — | | | | — | | | | — | | | | (150.7 | ) | | | — | | | | — | | | | (150.7 | ) | | | — | | | | — | | | | — | | | | (150 | ) | | | — | | | | — | | | | (150 | ) |
| Minimum pension liability | | | — | | | | — | | | | — | | | | 5.3 | | | | — | | | | — | | | | 5.3 | | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | — | | | | 5 | |
| Other postretirement benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | | — | | | | — | | | | — | | | | (4.1 | ) | | | — | | | | — | | | | (4.1 | ) | | | — | | | | — | | | | — | | | | (4 | ) | | | — | | | | — | | | | (4 | ) |
| Net actuarial gain | | | — | | | | — | | | | — | | | | 2.1 | | | | — | | | | — | | | | 2.1 | | | | — | | | | — | | | | — | | | | 2 | | | | — | | | | — | | | | 2 | |
| Issuance of common stock from 5.5% debentures conversion (Note 12) | | | 20.2 | | | | 193.2 | | | | — | | | | — | | | | — | | | | — | | | | 213.4 | | | | 20 | | | | 193 | | | | — | | | | — | | | | — | | | | — | | | | 213 | |
| Cash dividends — Common stock ($.35 per share) | | | — | | | | — | | | | (206.6 | ) | | | — | | | | — | | | | — | | | | (206.6 | ) | | | — | | | | — | | | | (207 | ) | | | — | | | | — | | | | — | | | | (207 | ) |
| Repayment of stockholders’ notes | | | — | | | | — | | | | — | | | | — | | | | 4.5 | | | | — | | | | 4.5 | | | | — | | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | 5 | |
| Stock award transactions, including tax benefit | | | 3.5 | | | | 84.7 | | | | — | | | | — | | | | — | | | | — | | | | 88.2 | | |
| Stock-based compensation, including tax benefit | | | | 4 | | | | 84 | | | | — | | | | — | | | | — | | | | — | | | | 88 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2006 | | $ | 602.8 | | | $ | 6,605.7 | | | $ | (1,034.0 | ) | | $ | (60.1 | ) | | $ | — | | | $ | (41.2 | ) | | $ | 6,073.2 | | | | 603 | | | | 6,605 | | | | (1,034 | ) | | | (60 | ) | | | — | | | | (41 | ) | | | 6,073 | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income — 2007 | | | | — | | | | — | | | | 990 | | | | — | | | | — | | | | — | | | | 990 | |
| Other comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized losses on cash flow hedges, net of reclassification adjustments | | | | — | | | | — | | | | — | | | | (179 | ) | | | — | | | | — | | | | (179 | ) |
| Foreign currency translation adjustments | | | | — | | | | — | | | | — | | | | 53 | | | | — | | | | — | | | | 53 | |
| Pension benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net actuarial gain | | | | — | | | | — | | | | — | | | | 53 | | | | — | | | | — | | | | 53 | |
| Other postretirement benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | 1 | |
| Net actuarial gain | | | | — | | | | — | | | | — | | | | 9 | | | | — | | | | — | | | | 9 | |
| | | | | | | | | | | | | | | | | | | |
| Total other comprehensive loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | (63 | ) |
| | | | | |
| Allocation of other comprehensive loss to minority interest | | | | — | | | | — | | | | — | | | | 2 | | | | — | | | | — | | | | 2 | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | 929 | |
| Cash dividends — Common stock ($.39 per share) | | | | — | | | | — | | | | (233 | ) | | | — | | | | — | | | | — | | | | (233 | ) |
| FIN 48 adjustment (Note 5) | | | | — | | | | — | | | | (17 | ) | | | — | | | | — | | | | — | | | | (17 | ) |
| Purchase of treasury stock (Note 12) | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (526 | ) | | | (526 | ) |
| Stock-based compensation, including tax benefit | | | | 5 | | | | 143 | | | | — | | | | — | | | | — | | | | — | | | | 148 | |
| Other | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | — | | | | 1 | |
| | | | | | | | | | | | | | | | | |
Balance, December 31, 2007 | | | | 608 | | | | 6,748 | | | | (293 | ) | | | (121 | ) | | | — | | | | (567 | ) | | | 6,375 | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income — 2008 | | | | — | | | | — | | | | 1,418 | | | | — | | | | — | | | | — | | | | 1,418 | |
| Other comprehensive income: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized gains on cash flow hedges, net of reclassification adjustments | | | | — | | | | — | | | | — | | | | 455 | | | | — | | | | — | | | | 455 | |
| Foreign currency translation adjustments | | | | — | | | | — | | | | — | | | | (76 | ) | | | | | | | | | | | (76 | ) |
| Pension benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | | | — | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | 1 | |
| Net actuarial loss | | | | — | | | | — | | | | — | | | | (344 | ) | | | | | | | | | | | (344 | ) |
| Other postretirement benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | | | — | | | | — | | | | — | | | | 9 | | | | — | | | | — | | | | 9 | |
| Net actuarial loss | | | | — | | | | — | | | | — | | | | (9 | ) | | | — | | | | — | | | | (9 | ) |
| | | | | |
| Total other comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | 36 | |
| | | | | |
| Allocation of other comprehensive income to minority interest | | | | — | | | | — | | | | — | | | | 5 | | | | — | | | | — | | | | 5 | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,459 | |
| Cash dividends — Common stock ($.43 per share) | | | | — | | | | — | | | | (250 | ) | | | — | | | | — | | | | — | | | | (250 | ) |
| Issuance of common stock from 5.5% debentures conversion (Note 12) | | | | 2 | | | | 25 | | | | — | | | | — | | | | — | | | | — | | | | 27 | |
| Conversion of Williams Partners L.P. subordinated units to common units (Note 12) | | | | — | | | | 1,225 | | | | — | | | | — | | | | — | | | | — | | | | 1,225 | |
| Purchase of treasury stock (Note 12) | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (474 | ) | | | (474 | ) |
| Stock-based compensation, including tax benefit | | | | 3 | | | | 67 | | | | — | | | | — | | | | — | | | | — | | | | 70 | |
| Other | | | | — | | | | 9 | | | | (1 | ) | | | — | | | | — | | | | — | | | | 8 | |
| | | | | | | | | | | | | | | | | |
Balance, December 31, 2008 | | | $ | 613 | | | $ | 8,074 | | | $ | 874 | | | $ | (80 | ) | | $ | — | | | $ | (1,041 | ) | | $ | 8,440 | |
| | | | | | | | | | | | | | | | | |
See accompanying notes.
83
THE WILLIAMS COMPANIES, INC.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | | Years Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| OPERATING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 308.5 | | | $ | 313.6 | | | $ | 163.7 | | | $ | 1,418 | | | $ | 990 | | | $ | 309 | |
| Adjustments to reconcile to net cash provided by operations: | | | | | | | | | | | | | | | | | | | | | | | | |
| (Income) loss from discontinued operations | | | 24.3 | | | | 2.1 | | | | (70.5 | ) | |
| Cumulative effect of change in accounting principle | | | — | | | | 1.7 | | | | — | | |
| Reclassification of deferred net hedge gains related to sale of power business | | | | — | | | | (429 | ) | | | — | |
| Depreciation, depletion and amortization | | | 865.5 | | | | 740.0 | | | | 668.5 | | | | 1,310 | | | | 1,082 | | | | 866 | |
| Provision (benefit) for deferred income taxes | | | 169.2 | | | | (45.3 | ) | | | 123.0 | | |
| Provision for deferred income taxes | | | | 611 | | | | 370 | | | | 154 | |
| Provision for loss on investments, property and other assets | | | 25.5 | | | | 118.7 | | | | 86.7 | | | | 166 | | | | 162 | | | | 26 | |
| Net gain on dispositions of assets | | | (22.5 | ) | | | (58.3 | ) | | | (18.1 | ) | |
| Net (gain) loss on dispositions of assets and business | | | | (36 | ) | | | 16 | | | | (23 | ) |
| Gain on sale of contractual production rights | | | | (148 | ) | | | — | | | | — | |
| Early debt retirement costs | | | 31.4 | | | | .4 | | | | 282.1 | | | | 1 | | | | 19 | | | | 31 | |
| Minority interest in income of consolidated subsidiaries | | | 40.0 | | | | 25.7 | | | | 21.4 | | | | 174 | | | | 90 | | | | 40 | |
| Amortization of stock-based awards | | | 43.9 | | | | 12.7 | | | | 9.5 | | | | 31 | | | | 70 | | | | 44 | |
| Cash provided (used) by changes in current assets and liabilities: | | | | | | | | | | | | | | | | | | | | | | | | |
| Restricted cash | | | 4.2 | | | | (14.0 | ) | | | (14.1 | ) | |
| Accounts and notes receivable | | | 378.1 | | | | (240.9 | ) | | | 234.6 | | | | 329 | | | | (122 | ) | | | 386 | |
| Inventories | | | 31.3 | | | | (9.7 | ) | | | (18.3 | ) | | | (48 | ) | | | 29 | | | | 31 | |
| Margin deposits and customer margin deposits payable | | | 97.9 | | | | 85.5 | | | | 414.1 | | | | 88 | | | | (135 | ) | | | 98 | |
| Other current assets and deferred charges | | | (34.2 | ) | | | 5.9 | | | | 112.8 | | | | (76 | ) | | | (10 | ) | | | (30 | ) |
| Accounts payable | | | (183.9 | ) | | | 232.5 | | | | (118.5 | ) | | | (343 | ) | | | 26 | | | | (184 | ) |
| Accrued liabilities | | | (147.9 | ) | | | 22.9 | | | | (218.9 | ) | | | 7 | | | | (200 | ) | | | (110 | ) |
| Changes in current and noncurrent derivative assets and liabilities | | | 303.2 | | | | 173.9 | | | | (160.4 | ) | | | (121 | ) | | | 370 | | | | 303 | |
| Changes in noncurrent restricted cash | | | — | | | | — | | | | 86.5 | | |
| Other, including changes in noncurrent assets and liabilities | | | (51.5 | ) | | | 82.5 | | | | (112.0 | ) | | | (8 | ) | | | (91 | ) | | | (51 | ) |
| | | | | | | | | |
| Net cash provided by operating activities of continuing operations | | | 1,883.0 | | | | 1,449.9 | | | | 1,472.1 | | |
| Net cash provided by operating activities of discontinued operations | | | 6.6 | | | | — | | | | 15.8 | | |
| | | | | | | | | | | | | | | |
| Net cash provided by operating activities | | | 1,889.6 | | | | 1,449.9 | | | | 1,487.9 | | | | 3,355 | | | | 2,237 | | | | 1,890 | |
| | | | | | | | | | | | | | | |
| FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | |
| Proceeds from long-term debt | | | 1,299.4 | | | | — | | | | 75.0 | | | | 674 | | | | 684 | | | | 1,299 | |
| Payments of long-term debt | | | (776.7 | ) | | | (251.2 | ) | | | (3,263.2 | ) | | | (665 | ) | | | (806 | ) | | | (777 | ) |
| Proceeds from issuance of common stock | | | 34.3 | | | | 309.9 | | | | 20.6 | | | | 32 | | | | 56 | | | | 34 | |
| Proceeds from sale of limited partner units of consolidated partnership | | | 863.4 | | | | 111.0 | | | | — | | |
| Proceeds from sale of limited partner units of consolidated partnerships | | | | 362 | | | | 333 | | | | 863 | |
| Tax benefit of stock-based awards | | | 15.5 | | | | — | | | | — | | | | 21 | | | | 32 | | | | 16 | |
| Dividends paid | | | (206.6 | ) | | | (143.0 | ) | | | (43.4 | ) | | | (250 | ) | | | (233 | ) | | | (207 | ) |
| Purchase of treasury stock | | | | (474 | ) | | | (526 | ) | | | — | |
| Payments for debt issuance costs and amendment fees | | | (37.0 | ) | | | (29.6 | ) | | | (26.0 | ) | | | (4 | ) | | | (4 | ) | | | (37 | ) |
| Premiums paid on tender offer, early debt retirements and FELINE PACS exchange | | | (25.8 | ) | | | (.4 | ) | | | (246.9 | ) | |
| Premiums paid on early debt retirements and tender offer | | | | — | | | | (27 | ) | | | (26 | ) |
| Dividends and distributions paid to minority interests | | | (36.2 | ) | | | (20.7 | ) | | | (5.9 | ) | | | (122 | ) | | | (75 | ) | | | (36 | ) |
| Changes in restricted cash | | | (.6 | ) | | | (2.7 | ) | | | 21.7 | | |
| Changes in cash overdrafts | | | (25.3 | ) | | | 63.2 | | | | (21.4 | ) | | | — | | | | 52 | | | | (25 | ) |
| Other — net | | | (1.2 | ) | | | — | | | | (14.8 | ) | | | (6 | ) | | | 3 | | | | (1 | ) |
| | | | | | | | | |
| Net cash provided (used) by financing activities of continuing operations | | | 1,103.2 | | | | 36.5 | | | | (3,504.3 | ) | |
| Net cash used by financing activities of discontinued operations | | | — | | | | — | | | | (1.2 | ) | |
| | | | | | | | | | | | | | | |
| Net cash provided (used) by financing activities | | | 1,103.2 | | | | 36.5 | | | | (3,505.5 | ) | | | (432 | ) | | | (511 | ) | | | 1,103 | |
| | | | | | | | | | | | | | | |
| INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | | | | |
| Property, plant and equipment: | | | | | | | | | | | | | | | | | | | | | | | | |
| Capital expenditures | | | (2,509.2 | ) | | | (1,299.0 | ) | | | (787.4 | ) | | | (3,475 | ) | | | (2,816 | ) | | | (2,509 | ) |
| Net proceeds from dispositions | | | 22.9 | | | | 47.3 | | | | 12.0 | | | | 119 | | | | 12 | | | | 23 | |
| Proceeds from contract termination payment | | | 3.3 | | | | 87.9 | | | | — | | |
| Changes in accounts payable and accrued liabilities | | | 104.7 | | | | 65.1 | | | | — | | | | 81 | | | | (52 | ) | | | 105 | |
| Purchases of investments/advances to affiliates | | | (48.9 | ) | | | (116.1 | ) | | | (2.1 | ) | | | (111 | ) | | | (60 | ) | | | (49 | ) |
| Purchases of auction rate securities | | | (386.3 | ) | | | (224.0 | ) | | | — | | | | — | | | | (304 | ) | | | (386 | ) |
| Purchases of restricted investments | | | — | | | | — | | | | (471.8 | ) | |
| Proceeds from sales of businesses | | | — | | | | 31.4 | | | | 877.8 | | |
| Purchase of ARO trust investments | | | | (31 | ) | | | — | | | | — | |
| Proceeds from sales of auction rate securities | | | 414.1 | | | | 137.9 | | | | — | | | | — | | | | 353 | | | | 414 | |
| Proceeds from sale of restricted investments | | | — | | | | — | | | | 851.4 | | |
| Proceeds from sale of business | | | | 22 | | | | 471 | | | | — | |
| Proceeds from sale of contractual production rights | | | | 148 | | | | — | | | | — | |
| Proceeds from dispositions of investments and other assets | | | 62.3 | | | | 64.2 | | | | 94.1 | | | | 41 | | | | 92 | | | | 62 | |
| Proceeds received on sale of note from WilTel | | | — | | | | 54.7 | | | | — | | |
| Payments received on notes receivable from WilTel | | | — | | | | — | | | | 69.1 | | |
| Proceeds from Gulfstream recapitalization | | | — | | | | 310.5 | | | | — | | |
| Proceeds from sale of ARO trust investments | | | | 14 | | | | — | | | | — | |
| Other — net | | | 15.7 | | | | 20.9 | | | | (12.9 | ) | | | 9 | | | | 8 | | | | 19 | |
| | | | | | | | | | | | | | | |
| Net cash provided (used) by investing activities of continuing operations | | | (2,321.4 | ) | | | (819.2 | ) | | | 630.2 | | |
| Net cash used by investing activities of discontinued operations | | | — | | | | — | | | | (.8 | ) | |
| | | | | | | | | |
| Net cash provided (used) by investing activities | | | (2,321.4 | ) | | | (819.2 | ) | | | 629.4 | | |
| Net cash used by investing activities | | | | (3,183 | ) | | | (2,296 | ) | | | (2,321 | ) |
| | | | | | | | | | | | | | | |
| Increase (decrease) in cash and cash equivalents | | | 671.4 | | | | 667.2 | | | | (1,388.2 | ) | | | (260 | ) | | | (570 | ) | | | 672 | |
| Cash and cash equivalents at beginning of year | | | 1,597.2 | | | | 930.0 | | | | 2,318.2 | | | | 1,699 | | | | 2,269 | | | | 1,597 | |
| | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of year | | $ | 2,268.6 | | | $ | 1,597.2 | | | $ | 930.0 | | | $ | 1,439 | | | $ | 1,699 | | | $ | 2,269 | |
| | | | | | | | | | | | | | | |
See accompanying notes.
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THE WILLIAMS COMPANIES, INC.
| |
| Note 1. | Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies |
Description of Business
Operations of our company are located principally in the United States and are organized into the following reporting segments: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids (Midstream), and Power.Gas Marketing Services (Gas Marketing).
Exploration & Production includes natural gas development, production and gas management activities primarily in the Rocky Mountain and Mid-Continent regions of the United States and oil and natural gas interests in Argentina.
Gas Pipeline is comprised primarily of two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies. The Gas Pipeline operating segments have been aggregated for reporting purposes and includeincludes Northwest Pipeline CorporationGP (Northwest Pipeline), which extends from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington, and Transcontinental Gas Pipe Line CorporationCompany, LLC (Transco), formerly Transcontinental Gas Pipe Line Corporation, which extends from the Gulf of Mexico region to the northeastern United States. In addition, we own a 50 percent interest in Gulfstream.Gulfstream Natural Gas System L.L.C. (Gulfstream). Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida.
Midstream is comprised of natural gas gathering and processing and treating facilities in the Rocky Mountain and Gulf Coast regions of the United States, oil gathering and transportation facilities in the Gulf Coast region of the United States, majority-owned natural gas compression facilities in Venezuela, and assets in Canada, consisting primarily of a natural gas liquids extraction facility and a fractionation plant.
Power is an energy services provider that buys, sells, stores, and transports energy and energy-related commodities,Gas Marketing primarily power and natural gas, on a wholesale level. Power focuses on its objectives of minimizing financial risk, maximizing cash flow, meeting contractual commitments, executing new contracts to hedge its portfolio, and providing commodity marketing and supply services that supportsupports our natural gas businesses.businesses by providing marketing and risk management services, which include marketing and hedging the gas produced by Exploration & Production, and procuring fuel and shrink gas and hedging natural gas liquids sales for Midstream. Gas Marketing also provides similar services to third parties, such as producers. In addition, Gas Marketing manages various natural gas-related contracts such as transportation, storage, related hedges and proprietary trading positions.
Basis of Presentation
Prior period amounts reported for Exploration & Production have been adjusted to reflect the presentation of certain revenues and costs on a net basis. These adjustments reducedrevenuesand reducedcosts and operating expensesby the same amount, with no net impact on segment profit. The reductions were $72 million in 2007 and $77 million in 2006.
Discontinued operations
In accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), the accompanying consolidated financial statements and notes reflect the results of operations and financial position of our former power business as discontinued operations. (See Note 2.) These operations included a 7,500-megawatt portfolio of power-related contracts that was sold in 2007 and our natural gas-fired electric generating plant located in Hazleton, Pennsylvania (Hazleton) that was sold in March 2008, in addition to other power-related assets.
Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.
Certain amounts have been reclassified to conform to the current classifications.Master limited partnerships
In February 2005, we formed Williams Partners L.P., a limited partnership engaged in the business of gathering, transporting and processing natural gas and fractionating and storing natural gas liquids. We currently own approximately 22.523.6 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us.us, and incentive distribution rights. Considering the presumption of control of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the general partner in accordance with Emerging Issues Task Force (EITF) IssueNo. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” we consolidate Williams Partners L.P. is consolidated within our Midstream segment.
In January 2008, Williams Pipeline Partners L.P. completed its initial public offering of 16.25 million common units at a price of $20 per unit. In February 2008, the underwriters exercised their right to purchase an additional 1.65 million common units at the same price. The initial asset of the partnership is a 35 percent interest in Northwest Pipeline. Upon completion of these transactions, we now own approximately 47.7 percent of the interests in Williams Pipeline Partners L.P., including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. In accordance with EITF IssueNo. 04-5, we consolidate Williams Pipeline Partners L.P. within our Gas Pipeline segment due to our control through the general partner.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our corporate parent and our majority-owned or controlled subsidiaries and investments. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20 to 50 percent of the voting interest, or otherwise exercise significant influence over operating and financial policies of the company.
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Use of estimates
Management makesThe preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions include:
| | |
| | • | Impairment assessments of investments, long-lived assets and goodwill; |
| |
| | • | Litigation-related contingencies; |
| |
| | • | Valuations of derivatives; |
| |
| | • | Environmental remediation obligations;Hedge accounting correlations and probability; |
| |
| | • | Hedge accounting correlations and probability;Environmental remediation obligations; |
| |
| | • | Realization of deferred income tax assets; |
| |
| | • | Valuation of Exploration & Production’s reserves; |
| |
| | • | Asset retirement obligations; |
| |
| | • | Pension and postretirement valuation variables. |
These estimates are discussed further throughout these notes.
Cash and cash equivalents
CashOurcash and cash equivalentsbalance includes demandamounts primarily invested in funds with high-quality, short-term securities and time deposits, certificates of deposit, and other marketable securities with maturitiesinstruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
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THE WILLIAMS COMPANIES, INC.
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Restricted cash
Current restricted cash is included inRestricted cash withinother current assets and deferred chargesin the Consolidated Balance Sheet and consists primarily of collateral required by certain loan agreements for our Venezuelan operations, and escrow accounts established to fund payments required by Power’sour California settlement (seesettlement. (See Note 15),16.) Noncurrent restricted cash is included inother assets and an escrow account used to collectdeferred chargesin the Consolidated Balance Sheet and manage margin dollars.Restricted cash within noncurrent assets relates primarily to certain borrowings by our Venezuelan operations as previously mentioned and letters of credit. We do not expect this cash to be released within the next twelve months. The current and noncurrentrestricted cash is primarily invested in short-term money market accounts with financial institutions.
The classification ofrestricted cash is determined based on the expected term of the collateral requirement and not necessarily the maturity date of the investment vehicle.investment.
Auction rate securities
AuctionAn auction rate securities are instrumentssecurity is an instrument with a long-term underlying maturities,maturity, but for which an auction is conducted periodically, as specified, to reset the interest rate and allow investors to buy or sell the instruments. Because auctions generally occur more often than annually, and because we hold these investments in order to meet short-term liquidity needs, we classify auction rate securities as short-term and include them inother current assets and deferred charges on our Consolidated Balance Sheet. Consistent with our other securities that are classified asavailable-for-sale, ourinstrument. Our Consolidated Statement of Cash Flows reflects the gross amount of thepurchases of auction rate securitiesand theproceeds from sales of auction rate securities. At December 31, 2008, we are no longer purchasing auction rate securities. Our remaining auction rate securities balance as of December 31, 2008, was $7 million.
Accounts receivable
Accounts receivableare carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectibility is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
Inventory valuation
Allinventoriesare stated at the lower of cost or market. We determine the cost of certain natural gas inventories held by Transco using thelast-in, first-out (LIFO) cost method. We determine the cost of the remaining inventories primarily using the average-cost method. LIFO inventory at December 31, 2008, was $11 million.
Property, plant and equipment
Property, plant and equipmentis recorded at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values.
As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at Federal Energy Regulatory Commission (FERC)-prescribed rates. DepreciationSee Note 9 for depreciation rates used for major regulated gas plant facilities for all years presented, are as follows:
| | |
Category of Property
| | Depreciation Rates |
|
Gathering facilities | | 0% - 3.80% |
Storage facilities | | 1.05% - 2.50% |
Onshore transmission facilities | | 2.35% - 7.25% |
Offshore transmission facilities | | 0.85% - 1.50% |
facilities.
Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except as noted below for oil and gas exploration and production activities. TheSee Note 9 for the estimated useful lives are as follows:
| | |
| | Estimated
|
| | Useful Lives
|
Category of Property
| | (In years) |
|
Natural gas gathering and processing facilities | | 10 to 40 |
Power generation facilities | | 30 |
Transportation equipment | | 3 to 30 |
Building and improvements | | 5 to 45 |
Right of way | | 4 to 40 |
Office furnishings and computer software and hardware | | 3 to 20 |
associated with our nonregulated assets.
Gains or losses from the ordinary sale or retirement of property, plant and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded inother (income) expense — netincluded inoperating income.
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THE WILLIAMS COMPANIES, INC.
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Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized asproperty, plant, and equipment— net.
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells, as applicable, are capitalized as incurred. If proved reserves are not found, such costs are charged to expense. Other exploration costs, including lease rentals, are expensed as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred. Unproved properties are evaluated annually, or as conditions warrant, to determine any impairment in carrying value.Depreciation, depletion and amortizationis provided under the units of production method on a field basis.
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Proved properties, including developed and undeveloped, and costs associated with unproven reserves, are assessed for impairment using estimated future cash flows on a field basis. Estimating future cash flows involves the use of complex judgments such as estimation of the proved and unproven oil and gas reserve quantities, risk associated with the different categories of oil and gas reserves, timing of development and production, expected future commodity prices, capital expenditures, and production costs.
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included inother (income) expense— netincluded inoperating income, except for regulated entities, for which the liability is offset by a regulatory asset.
Goodwill
Goodwillrepresents the excess of cost over fair value of the assets of businesses acquired. It is evaluated annually for impairment by first comparing our management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. We havegoodwillof approximately $1 billion at December 31, 2006,2008 and 2005, at2007, attributable to our Exploration & Production segment.
When a reporting unit is sold or classified as held for sale, any goodwill of that reporting unit is included in its carrying value for purposes of determining any impairment or gain/loss on sale. If a portion of a reporting unit with goodwill is sold or classified as held for sale and that asset group represents a business, a portion of the reporting unit’s goodwill is allocated to and included in the carrying value of that asset group. None of the operations sold during 2005 and 2004the periods reported represented reporting units with goodwill or businesses within reporting units to which goodwill was required to be allocated.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgmentsand/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.
Subsequent to December 31, 2008, as a result of overall market and energy commodity price declines, we have witnessed periodic reductions in our total market capitalization below our December 31, 2008, consolidated stockholders’ equity balance. If our total market capitalization is below our consolidated stockholders’ equity balance at a future reporting date, we consider this an indicator of potential impairment of goodwill under recent SEC communications and our accounting considerations. We utilize market capitalization in corroborating our assessment of the fair value of our Exploration & Production reporting unit. Considering this, it is reasonably possible that we may be required to conduct an interim goodwill impairment evaluation, which could result in a material impairment of our goodwill.
Treasury stock
Treasury stockpurchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged tocapital in excess of par valueusing the average-cost method.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Derivative instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity. We execute most of these transactions on an organized commodity exchange or inover-the-counter markets in which quoted prices exist for active periods. For contracts with terms that exceed the time period for which actively quoted prices are available, we determine fair value by estimating commodity prices during the illiquid periods utilizing internally developed valuations incorporating information obtained from commodity prices in actively quoted markets, quoted prices in less active markets, prices reflected in current transactions, and other market fundamental analysis.
We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheet inderivative assetsandderivative liabilitiesas
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual contracts. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
The accounting for changes in the fair value of a commodity derivative is governed by Statement of Financial Accounting Standard (SFAS)SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133), as amended and depends on whether the derivative has been designated in a hedging relationship and whether we have elected the normal purchases and normal sales exception. The accounting for the change in fair value can be summarized as follows:
| | | |
Derivative Treatment | | Accounting Method |
|
| Normal purchases and normal sales exception | | Accrual accounting |
| Designated in a qualifying hedging relationship | | Hedge accounting |
| All other derivatives | | Mark-to-market accounting |
We have electedmay elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception. Some contracts had a fair value at the date of the election and are reflected on the balance sheet at their fair value on the date of the election less the amount of that fair value realized during settlement periods subsequent to the election. For other contracts, we made the election at the inception of the contract and thus there is no recorded fair value.
We have also designated a hedging relationship for certain commodity derivatives. Prior to September 2004, Power’s derivative contracts did not qualify for hedge accounting because of our stated intent to exit the Power business. In September 2004, we announced our decision to continue operating the Power business. As a result of that decision, Power’s derivative contracts became eligible for hedge accounting. Power elected cash flow hedge accounting on a prospective basis beginning October 1, 2004, for certain qualifying derivative contracts.
For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently inrevenues.
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported inother comprehensive income (loss)and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently inrevenues. Gains or losses deferred inaccumulated other comprehensive lossassociated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain inaccumulated other comprehensive lossuntil the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred inaccumulated other comprehensive lossis recognized inrevenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently inrevenues.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Certain gains and losses on derivative instruments included in the Consolidated Statement of Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
| | |
| | • | Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception; |
| |
| | • | The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges; |
| |
| | • | Realized gains and losses on all derivatives that settle financially; |
| |
| | • | Realized gains and losses on derivatives held for trading purposes; |
| |
| | • | Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement. |
Realized gains and losses on derivatives that require physical delivery, and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we evaluated the indicators in EITF IssueNo. 99-19 “Reporting Revenue Gross as a Principal versus as an Agent,” including whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
Assessment of energy-related contracts for lease classification
EITF01-8, “Determining Whether an Arrangement Contains a Lease,” became effective on July 1, 2003, and provides guidance for determining whether certain contracts such as transportation, transmission, storage, full requirements, and tolling agreements are executory service arrangements or leases pursuant to SFAS No. 13, “Accounting for Leases.” The consensus is applied prospectively to arrangements consummated or modified after July 1, 2003. Prior to July 1, 2003, we accounted for energy-related contracts as executory service arrangements and continue this accounting unless a contract is subsequently modified and evaluated to be a lease. For executory service arrangements, the monthly demand payments are expensed as incurred. Certain of Power’s tolling agreements will likely be considered leases under the consensus if the tolling agreements are ever modified. One tolling agreement was modified in 2004 and is accounted for as an operating lease. For tolling agreements that are modified and deemed to be operating leases, the monthly demand payments are expensed as incurred. If the monthly demand payments are not incurred on a straight-line basis, expense is nevertheless recognized on a straight-line basis. If such tolling agreements are modified and deemed to be capital leases, the net present value of the demand payments would be reported on the Consolidated Balance Sheet aslong-term debt and as an asset inproperty, plant and equipment — net.
Gas Pipeline revenues
Gas Pipeline revenues are primarily from services pursuant to long-term firm transportation and storage agreements. These agreements provide for a demand charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for demand charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services, and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.
In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized infrom the periodsale of gas upon settlement of the service is provided,transportation and revenues for salesexchange imbalances.
As a result of products are recognized in the period of delivery. Gas Pipeline is subject to FERC regulations and, accordingly,ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate cases. Gas Pipeline recordsproceedings with the FERC. We record estimates of rate refund liabilities considering Gas Pipelineour and other third-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.
Exploration & Production revenues
Revenues from the domestic production of natural gas in properties for which Exploration & Production has an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on Exploration & Production’s net working interest, that are
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are not significant.
Midstream revenues
Natural gas gathering and processing services are performed under volumetric-based fee contracts, keep-whole agreements and percent-of-liquids arrangements. Revenues under volumetric-based fee contracts are
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
recorded when services have been performed. Under keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the natural gas liquids (NGLs) extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
We have olefins extraction operations where we retain certain products extracted from the producers’ off-gas stream and we recognize revenues when the extracted products are sold and delivered to our purchasers. We also produce olefins from purchased feed-stock, and we recognize revenues when the olefins are sold and delivered.
We also market NGLs and olefins. Revenues from marketing NGLs and olefins are recognized when the products have been sold and delivered.
Gas Marketing revenues
Revenues for sales of natural gas are recognized when the product is sold and delivered.
All other than Gas Pipeline, Exploration & Production, and energy commodity risk management and trading activitiesrevenues
Revenues generally are recorded when services are performed or products have been delivered.
Impairment of long-lived assets and investments
We evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. WhenExcept for proved and unproved properties discussed below, when an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. Weoccurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
For assets identified to be disposed of in the future and considered held for sale in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Estimating future cash flows involves the use of complex judgments such as estimation of the proved and unproven oil and gas reserve quantities, risk associated with the different categories of oil and gas reserves, timing of development and production, expected future commodity prices, capital expenditures, and production costs.
Unproved properties include lease acquisition costs and costs of acquired unproven reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience or other information, is amortized over the average holding period. A majority of the costs of acquired unproven reserves are associated with areas to which proved developed producing reserves are also attributed. Generally, economic recovery of unproven reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of potentially recoverable reserves in areas with established production generally has greater probability
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than in areas with limited or no prior drilling activity. Costs of acquired unproven reserves are assessed annually, or as conditions warrant, for impairment using estimated future discounted cash flows on a field basis and considering our future drilling plans. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced another-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to beother-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. The use of alternate judgmentsand/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.
Capitalization of interest
We capitalize interest during construction on major projects during construction.with construction periods of at least three months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds as a component ofother income— net. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by unregulatednonregulated companies are based on the average interest rate on debt. The benefit of interest capitalized on internally generated funds for regulated entities is reported inother income — net belowoperating income.
Additionally, Exploration & Production capitalizes interest on those construction projects with construction periods of at least three months and a total project cost in excess of $1 million. Exploration & Production capitalizes interest on equity investments when the investee is undergoing construction in preparation for its planned principal operations.
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Employee stock-based awards
Prior to January 1, 2006, we accounted for stock-based awards to employees and nonmanagement directors (see Note 13) under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by Financial Accounting Standards Board (FASB) Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Compensation cost for stock options was not recognized in the Consolidated Statement of Income for the years prior to 2006 as all options granted had an exercise price equal to the market value of the underlying common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for restricted stock units. Effective January 1, 2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified-prospective method. Under this method, compensation cost recognized in 2006 includes: (1) compensation cost for all share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005,awards is based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, and (2) compensation cost for most share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The performance targets for certain performance-based restricted stock units have not been established and therefore expense is not currently recognized. Expense associated with these performance-based awards will be recognized in future periods when performance targets are established. Results for prior periods have not been restated.
value. Total stock-based compensation expense for the yearyears ending December 31, 2008, 2007, and 2006, was $43.9 million. This amount reflects a reduction$31 million, $70 million and $44 million, respectively, of $.3which $1 million, of previously recognized compensation cost for restricted stock units related to the estimated number of awards expected to be forfeited. This adjustment$9 million and $3 million, respectively, is not considered material for reporting as a cumulative effect of a changeincluded in accounting principle.income (loss) from discontinued operations. Measured but unrecognized stock-based compensation expense at December 31, 2006,2008, was approximately $50$57 million, which does not include the effect of estimated forfeitures of $1.9$3 million. This amount is comprised of approximately $13$7 million related to stock options and approximately $37$50 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.91.8 years.
As a result of adopting SFAS No. 123(R), ourincome from continuing operations before income taxes andnet income for the year ending December 31, 2006, are approximately $18.4 million and $11.3 million lower, respectively, than if we continued to account for share-based compensation under APB No. 25. For the year ending December 31, 2006, both basic and diluted earnings per share are $.02 lower due to the implementation of SFAS No. 123(R).
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The following table illustrates the effect onnet incomeandearnings per common share for the years ending December 31, 2005 and 2004, if we had applied the fair value recognition provisions of SFAS No. 123 to options granted. For purposes of this pro forma disclosure, the value of the options was estimated using a Black-Scholes option pricing model and amortized to expense over the vesting period of the options.
| | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2005 | | | 2004 | |
| | | (Dollars in millions, except per share amounts) | |
| |
| Net income, as reported | | $ | 313.6 | | | $ | 163.7 | |
| Add: Stock-based employee compensation expense included in the consolidated statement of income, net of related tax effects | | | 8.9 | | | | 8.9 | |
| Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects | | | (17.0 | ) | | | (25.1 | ) |
| | | | | | | | | |
| Pro forma net income | | $ | 305.5 | | | $ | 147.5 | |
| | | | | | | | | |
| Earnings per common share: | | | | | | | | |
| Basic — as reported | | $ | .55 | | | $ | .31 | |
| | | | | | | | | |
| Basic — pro forma | | $ | .54 | | | $ | .28 | |
| | | | | | | | | |
| Diluted — as reported | | $ | .53 | | | $ | .31 | |
| | | | | | | | | |
| Diluted — pro forma | | $ | .52 | | | $ | .28 | |
| | | | | | | | | |
Pro forma amounts for 2005 include compensation expense from awards of our company stock made in 2005, 2004, 2003, and 2002. Pro forma amounts for 2004 include compensation expense from awards made in 2004, 2003, 2002, and 2001. Also included in 2004 pro forma expense is $3.3 million of incremental expense associated with a stock option exchange program.
Income taxes
We include the operations of our subsidiaries in our consolidated tax return. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common share
Basic earnings (loss) per common shareis based on the sum of the weighted-average number of common shares outstanding and issuablevested restricted stock units.Diluted earnings (loss) per common shareincludes any dilutive effect of stock options, unvestednonvested restricted stock units and, for applicable periods presented, convertible debt, unless otherwise noted.
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Foreign currency translation
Certain of our foreign subsidiaries and equity method investees use their local currency as their functional currency. These foreign currencies include the Canadian dollar, British pound and Euro. Assets and liabilities of certain foreign subsidiaries and equity investees are translated at the spot rate in effect at the applicable reporting date, and the combined statements of operations and our share of the results of operations of our equity affiliates are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component ofother comprehensive income (loss).
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Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains and losses which are reflected in the Consolidated Statement of Income.
Issuance of equity of consolidated subsidiary
Sales of residual equity interests in a consolidated subsidiary are accounted for as capital transactions. No adjustments to capital are made for sales of preferential interests in a subsidiary. No gain or loss is recognized on these transactions.
Recent Accounting Standards
In September 2005, the FASB ratified EITF IssueNo. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF04-13). The consensus states that two or more inventory purchase and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined as a single exchange transaction for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” A nonmonetary exchange of inventory within the same line of business where finished goods inventory is transferred in exchange for the receipt of either raw materials or work in process inventory should be recognized at fair value by the entity transferring the finished goods inventory if fair value is determinable within reasonable limits and the transaction has commercial substance. All other nonmonetary exchanges of inventory within the same line of business should be recognized at the carrying amount of the inventory transferred. EITF04-13 is effective for new arrangements entered into, and modifications or renewals of existing arrangements, beginning in the first reporting period beginning after March 15, 2006. We applied this Issue during 2006 with no significant impact on our Consolidated Financial Statements.
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). With regard to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133) this Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only and principal-only strips are not subject to the requirements of SFAS No. 133, and requires the holder of an interest in securitized financial assets to determine whether the interest is a freestanding derivative or contains an embedded derivative requiring bifurcation. SFAS No. 155 also amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” (SFAS No. 140) to eliminate a restriction on the passive derivative financial instruments that a qualifying special purpose entity may hold. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The fair value election regarding hybrid financial instruments may also be applied upon adoption of SFAS No. 155 to hybrid financial instruments that had been bifurcated prior to adoption of SFAS No. 155. We applied the provisions of SFAS No. 155 beginning in January 2007 with no impact on our Consolidated Financial Statements.
In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets, an amendment of FASB Statement No. 140” (SFAS No. 156). This Statement amends SFAS No. 140 with respect to the accounting for separately recognized servicing assets and liabilities from undertaking an obligation to service a financial asset by entering into a servicing contract. SFAS No. 156 is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. We applied the provisions of SFAS No. 156 beginning in January 2007 with no impact on our Consolidated Financial Statements.
In April 2006, the FASB issued a Staff Position (FSP) on a previously issued Interpretation (FIN), FSP FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R).” When determining the variability of an entity in applying FIN 46(R), a reporting enterprise must analyze the design of the entity and consider the nature of the risks in the entity, and determine the purpose for which the entity was created and determine the variability the entity is designed to create and pass along to its interest holders. The FSP is
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effective beginning in the third quarter of 2006 on a prospective basis. We applied this FSP with no impact on our Consolidated Financial Statements.
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation clarifies the accounting for uncertainty in income taxes under FASB Statement No. 109, “Accounting for Income Taxes.” The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.
FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the Interpretation must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. We adopted FIN 48 beginning January 1, 2007, as required. The net impact of the cumulative effect of adopting FIN 48 is expected to be in the range of a $10 million to $20 million decrease in retained earnings.
In June 2006, the FASB ratified EITFNo. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF06-3). EITF06-3 addresses the income statement presentation of any tax collected from customers and remitted to a government authority and concludes the presentation of taxes on either a gross basis or a net basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22 “Disclosure of Accounting Policies.” This is effective for interim and annual reporting periods beginning after December 15, 2006 and will require the financial statement disclosure of any significant taxes recognized on a gross basis. We are reviewing the presentation in our Consolidated Financial Statements and will apply the disclosure provisions of EITF06-3 with our first quarter 2007 filing.
In September 2006, the FASBStandards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS No. 157 iswas effective for fiscal years beginning after November 15, 2007 and is generally applied prospectively. We will assess2007. In February 2008, the impactFASB issued FASB Staff Position (FSP)No. FAS 157-2, permitting entities to delay application of SFAS No. 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). On January 1, 2008, we applied SFAS No. 157 to our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy derivatives. See Note 14 for discussion of the adoption. Beginning January 1, 2009, we will prospectively apply SFAS No. 157 fair value measurement guidance to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis when such fair value measurements are required. Had we not elected to defer portions of SFAS No. 157, fair value measurements for nonfinancial items occurring in 2008 where SFAS No. 157 would have been applied include long-lived assets measured at fair value for impairment purposes, measuring the fair value of a reporting unit for purposes of assessing goodwill for impairment and the initial measurement at fair value of asset retirement obligations.
In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS No. 141(R)). SFAS No. 141(R) applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100 percent ownership in the acquiree. SFAS No. 141(R) also requires expensing of restructuring and acquisition-related costs as incurred and establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. SFAS No. 141(R) is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008. We will apply this standard for any business combinations after the effective date.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51” (SFAS No. 160). SFAS No. 160 establishes accounting and reporting standards for noncontrolling ownership interests in subsidiaries (previously referred to as minority interests). Noncontrolling ownership interests in consolidated subsidiaries will be presented in the
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consolidated balance sheet within stockholders’ equity as a separate component from the parent’s equity. Consolidated net income will now include earnings attributable to both the parent and the noncontrolling interests. Earnings per share will continue to be based on earnings attributable to only the parent company and does not change upon adoption of SFAS No. 160. SFAS No. 160 provides guidance on accounting for changes in the parent’s ownership interest in a subsidiary, including transactions where control is retained and where control is relinquished. SFAS No. 160 also requires additional disclosure of information related to amounts attributable to the parent for income from continuing operations, discontinued operations and extraordinary items and reconciliations of the parent and noncontrolling interests’ equity of a subsidiary. The Statement will be applied prospectively to transactions involving noncontrolling interests, including noncontrolling interests that arose prior to the effective date, as of the beginning of the fiscal year it is initially adopted. However, the presentation of noncontrolling interests within stockholders’ equity and the inclusion of earnings attributable to the noncontrolling interests in consolidated net income requires retrospective application to all periods presented. Beginning January 1, 2009, we will apply SFAS No. 160 prospectively with the exception of the presentation and disclosure requirements which must be applied retrospectively for all periods presented.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”currently establishes the disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 amends and expands the disclosure requirements of Statement 133 with enhanced quantitative, qualitative and credit risk disclosures. The Statement requires quantitative disclosure in a tabular format about the fair values of derivative instruments, gains and losses on derivative instruments and information about where these items are reported in the financial statements. Also required in the tabular presentation is a separation of hedging and nonhedging activities. Qualitative disclosures include outlining objectives and strategies for using derivative instruments in terms of underlying risk exposures, use of derivatives for risk management and other purposes and accounting designation, and an understanding of the volume and purpose of derivative activity. Credit risk disclosures provide information about credit risk related contingent features included in derivative agreements. SFAS No. 161 also amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to clarify that disclosures about concentrations of credit risk should include derivative instruments. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We plan to apply this Statement beginning in 2009. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. The application of this Statement will increase the disclosures in our Consolidated Financial Statements.
In June 2008, the FASB issued FSPNo. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”. FSP No.EITF 03-6-1 requires that unvested share-based payment awards containing nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) be considered participating securities and included in the computation of earnings per share (EPS) pursuant to the two-class method of FASB Statement No. 128, “Earnings per Share.” FSP No.EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented shall be adjusted retrospectively to conform to this FSP. Early application is not permitted. This FSP will not have a material impact on our EPS attributable to the common stockholders.
In June 2008, the FASB issued EITF IssueNo. 07-5, “Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock”(EITF 07-5).EITF 07-5 clarifies how to determine whether certain instruments or embedded features are indexed to an entity’s own stock.EITF 07-5 provides that an entity should evaluate the instrument’s settlement provisions and contingent exercise provisions, if any, to determine whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock.EITF 07-5 concludes that contingent exercise and settlement provisions in equity-linked financial instruments (or embedded features) are consistent with being indexed to an entity’s own stock if they are based on variables that would be inputs to a fair value option or forward pricing model and they do not increase the instruments’ exposure to those variables. The
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final consensus requires that an entity apply the guidance in this Issue in its first fiscal year beginning after December 15, 2008, including interim periods within those fiscal years. Early application is prohibited. We have outstanding convertible debentures. This Issue will not have an impact on our Consolidated Financial Statements.
In September 2006,2008, the FASB issuedEITF 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”(EITF 08-5). The objective of this Issue is to determine an issuer’s unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. The issuer of a liability with a third-party credit enhancement that is inseparable from the liability shall not include the effect of the credit enhancement in the fair value measurement of the liability. An issuer shall disclose the existence of a third-party credit enhancement on its issued liability. In accordance withEITF 08-5, an issuer in considering their own credit in the fair value measurement of a liability would ignore any third-party guarantee, letter of credit, or other form of credit enhancement. This Issue shall be effective on a prospective basis in the first reporting period beginning on or after December 15, 2008. The effect of initially applying the guidance in this Issue shall be included in the change in fair value in the period of adoption. Earlier application is permitted. We will applyEITF 08-5 beginning January 1, 2009, and this Issue will not initially have a material impact on the valuation of our derivative liabilities.
In November 2008, the FASB issuedEITF 08-6, “Accounting for Equity Method Investments Considerations.” The Issue clarifies that an equity method investor is required to continue to recognize an other-than temporary impairment of their investment in accordance with APB Opinion No. 18. Also, an equity method investor should not separately test an investee’s underlying assets for impairment. However, an equity method investor should recognize their share of an impairment charge recorded by an investee. This Issue will be effective on a prospective basis in fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. Earlier application by an entity that has previously adopted an alternative accounting policy would not be permitted. Beginning January 1, 2009, we will apply the guidance provided in this Consensus as required.
In December 2008, the FASB issued FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1)No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”. This FSP addressesamends FASB Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits”, to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. FSP No. FAS 132(R)-1 applies to an employer that is subject to the planneddisclosure requirements of Statement 132(R). An employer is required to disclose information about how investment allocation decisions are made, including factors that are pertinent to an understanding of investment policies and strategies. An employer should disclose separately for pension plans and other postretirement benefit plans the fair value of each major maintenancecategory of plan assets as of each annual reporting date for which a statement of financial position is presented. Asset categories should be based on the nature and risks of assets in an employer’s plan(s). An employer is required to disclose information that enables users of financial statements to assess the inputs and prohibitsvaluation techniques used to develop fair value measurements of plan assets at the useannual reporting date. For fair value measurements using significant unobservable inputs (Level 3), an employer should disclose the effect of the“accrue-in-advance” method of accounting for these activities measurements on changes in annual and interim reporting periods. The FSP continues to allow the direct expense, built-in overhaul and deferral methods. FSP AUG AIR-1 requires disclosure of the method of accounting for planned major maintenance activities as well as information related to the change from the“accrue-in-advance” method to another method. This FSP is effectiveplan assets for the firstperiod. An employer should provide users of financial statements with an understanding of significant concentrations of risk in plan assets. The disclosures about plan assets required by FSP No. FAS 132(R)-1 shall be provided for fiscal year beginningyears ending after December 15, 2006 and should be applied retrospectively.2009. Upon initial application, the provisions of FSP No. FAS 132(R)-1 are not required for earlier periods that are otherwise presented for comparative purposes. Earlier application of the provisions of FSP No. FAS 132(R)-1 is permitted. We adoptedwill assess the application of this FSPStatement on our disclosures in January 2007 with no significant impact on our Consolidated Financial Statements.
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| Note 2. | Discontinued Operations |
The summarized results of discontinued operations and summarized assets and liabilities of discontinued operations primarily reflect our former power business except where noted otherwise. In December 2006,November 2007, we sold substantially all of our power business for approximately $496 million in cash. In 2008, we received an additional $22 million of proceeds, including the FASB issued FSP EITF00-19-2, “Accounting for Registration Payment Arrangements” (FSP EITF00-19-2). The FSP specifiesfinal purchase price adjustments and $8 million from the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provisionsale of a financial instrument or other agreement, should be recognized and measured separately in accordance with FASB SFAS No. 5, “Accounting for Contingencies” and related literature. FSP EITF00-19-2 further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable generally accepted accounting principles without regard to the contingent obligation to transfer consideration. The FSP applies immediately to registration payment arrangements and theHazleton.
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financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. Whereas, for registration payment arrangements and the financial instruments subject to those arrangements entered into prior to its issuance, the FSP applies to our financial statements for the fiscal year beginning in 2007. We adopted the provisions of FSP EITF00-19-2 beginning in January 2007 with no impact on our Consolidated Financial Statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, with a few exceptions, is irrevocable and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. Early adoption is permitted as of the beginning of a fiscal year provided the entity makes that choice in the first 120 days of the fiscal year and elects to simultaneously adopt the provisions of SFAS No. 157. At the effective date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. We will assess the impact of SFAS No. 159 on our Consolidated Financial Statements.
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Note 2. | Discontinued Operations |
The businesses discussed below represent components that have been sold as of December 31, 2006, and are classified as discontinued operations. Therefore, their results of operations (including any impairments, gains or losses), financial position and cash flows have been reflected in the consolidated financial statements and notes as discontinued operations.
Summarized Results of Discontinued Operations
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (Millions) | |
| |
| Revenues | | $ | 5 | | | $ | 2,436 | | | $ | 2,437 | |
| | | | | | | | | | | | | |
| Income (loss) from discontinued operations before income taxes | | $ | 163 | | | $ | 392 | | | $ | (58 | ) |
| (Impairments) and gain (loss) on sales | | | 8 | | | | (162 | ) | | | — | |
| (Provision) benefit for income taxes | | | (87 | ) | | | (87 | ) | | | 20 | |
| | | | | | | | | | | | | |
| Income (loss) from discontinued operations | | $ | 84 | | | $ | 143 | | | $ | (38 | ) |
| | | | | | | | | | | | | |
The following table presents the summarized results of discontinued operations for the years ended December 31, 2006, 2005, and 2004.
LossIncome (loss) from discontinued operations before income taxesfor the year ended December 31, 2004,2008, includes charges$140 million of approximately $153 million to increase our accrued liabilitygains from the favorable resolution of matters involving pipeline transportation rates associated with certainour former Alaska operations and $54 million of income from a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank litigation matters.Bank. (See Note 15.16.) TheThese gains are partially offset by a $10 million charge from a settlement primarily related to the sale of natural gas liquids pipeline systems in 2002 and a charge of $11 million associated with an oil purchase contract related to our former Alaska refinery.
provision forIncome (loss) from discontinued operations before income taxesfor the year ended December 31, 2004, is less than2007, includes a gain of $429 million (reported inrevenuesof discontinued operations) associated with the federal statutory ratereclassification of deferred net hedge gains fromaccumulated other comprehensive incometo earnings in second-quarter 2007. This reclassification was based on the determination that the hedged forecasted transactions were probable of not occurring due primarily to the effect of net Canadian tax benefits realized from the sale of the Canadian straddle plantsour power business. This gain is partially offset by unrealized mark-to-market losses of approximately $23 million.Income (loss) from discontinued operations before income taxesalso includes the United States tax effectresults of earnings associated with these assets.
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Millions) | |
| |
| Revenues | | $ | — | | | $ | — | | | $ | 353.4 | |
| | | | | | | | | | | | | |
| Loss from discontinued operations before income taxes | | $ | (39.3 | ) | | $ | (3.9 | ) | | $ | (121.3 | ) |
| Gain on sales | | | — | | | | .5 | | | | 200.5 | |
| Benefit (provision) for income taxes | | | 15.0 | | | | 1.3 | | | | (8.7 | ) |
| | | | | | | | | | | | | |
| Income (loss) from discontinued operations | | $ | (24.3 | ) | | $ | (2.1 | ) | | $ | 70.5 | |
| | | | | | | | | | | | | |
our former power business operations.
Income (loss) from discontinued operations before income taxesfor the year ended December 31, 2006, Activities
During 2006, we recordedincludes charges of $19.2$19 million for an adverse arbitration award related to our former chemical fertilizer business, and a $6 million accrual for a loss contingency in connection with a former exploration business, and $15 million associated with an oil purchase contract related to our former Alaska refinery. Partially offsetting these charges was $13 million of income related to the reduction of contingent obligations associated with our former distributive power business.Income (loss) from discontinued operations before income taxesalso includes the results of our former power business operations.
(Impairments) and gain (loss) on salesfor the year ended December 31, 2007, includes a pre-tax loss of approximately $37 million on the sale of substantially all of our power business. We also recognized impairments of $111 million related to the carrying value of certain derivative contracts for which we had previously elected the normal purchases and normal sales exception under SFAS No. 133, and, accordingly, were no longer recording at fair value, and $14 million related to Hazleton. These impairments were based on our comparison of the carrying value to the estimate of fair value less cost to sell.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
business. In addition, we made a $14.7 million accrual associated with an oil purchase contract related to our former Alaska refinery.
2004 Completed TransactionsSummarized Assets and Liabilities of Discontinued Operations
| | | | | | | | | |
| | | December 31,
| | | December 31,
| |
| | | 2008 | | | 2007 | |
| | | (Millions) | |
| |
| Derivative assets | | $ | 1 | | | $ | 114 | |
| Accounts receivable — net | | | 5 | | | | 55 | |
| Other current assets | | | — | | | | 3 | |
| | | | | | | | | |
| Total current assets | | | 6 | | | | 172 | |
| | | | | | | | | |
| Property, plant and equipment — net | | | — | | | | 8 | |
| Other noncurrent assets | | | — | | | | 5 | |
| | | | | | | | | |
| Total noncurrent assets | | | — | | | | 13 | |
| | | | | | | | | |
| Total assets | | $ | 6 | | | $ | 185 | |
| | | | | | | | | |
| Derivative liabilities | | $ | 1 | | | $ | 114 | |
| Other current liabilities | | | — | | | | 61 | |
| | | | | | | | | |
| Total current liabilities | | | 1 | | | | 175 | |
| | | | | | | | | |
| Total liabilities | | $ | 1 | | | $ | 175 | |
| | | | | | | | | |
Canadian straddle plants
On July 28, 2004, we completedThe December 31, 2008 and 2007, balances forderivative assetsandderivative liabilitiesrepresent contracts remaining to be assigned to the salepurchaser of our former power business, entirely offset by reciprocal positions with that same party. We continue to pursue assignment of the Canadian straddle plants for approximately $544 million and recognized a $189.8 million pre-tax gain on the sale. These assets were previously written down to estimated fair value, resulting in impairmentsremaining contracts which are with one counterparty as of $41.7 million during 2003 and $36.8 million in 2002. In 2004, the fair value of the assets increased substantially due primarily to renegotiation of certain customer contracts and a general improvement in the market for processing assets. These operations were part of the Midstream segment.
Alaska refining, retail and pipeline operations
On MarchDecember 31, 2004, we completed the sale of our Alaska refinery, retail and pipeline operations for approximately $304 million. We received $279 million in cash at the time of sale and $25 million in cash during the second quarter of 2004. Based on information we obtained throughout the sales negotiations process, we recorded impairments of $8 million in 2003 and $18.4 million in 2002. We recognized a $3.6 million pre-tax gain on the sale during first quarter 2004. These operations were part of the previously reported Petroleum Services segment.
We are party to a pending matter involving pipeline transportation rates charged to our former Alaska refinery in prior periods. While we have no loss exposure in this matter, favorable resolution could result in a refund.2008.
| |
| Note 3. | Investing Activities |
Investing Income
Investing income for the years ended December 31, 2006, 2005 and 2004, is as follows:
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Years Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Equity earnings* | | $ | 98.9 | | | $ | 65.6 | | | $ | 49.9 | | | $ | 137 | | | $ | 137 | | | $ | 99 | |
| Loss from investments* | | | — | | | | (109.1 | ) | | | (35.5 | ) | |
| Income from investments* | | | | 1 | | | | — | | | | — | |
| Impairments of cost-based investments | | | (20.4 | ) | | | (2.2 | ) | | | (28.5 | ) | | | (4 | ) | | | (1 | ) | | | (20 | ) |
| Interest income and other | | | 94.5 | | | | 69.4 | | | | 62.1 | | | | 57 | | | | 121 | | | | 89 | |
| | | | | | | | | | | | | | | |
| Total | | $ | 173.0 | | | $ | 23.7 | | | $ | 48.0 | | |
| Total investing income | | | $ | 191 | | | $ | 257 | | | $ | 168 | |
| | | | | | | | | | | | | | | |
| | |
| * | | Items also included insegment profit. (See Note 17.18.) |
Loss from investments for the year ended December 31, 2005, includes:
| | |
| • | An $87.2 million impairment of our investment in Longhorn Partners Pipeline L.P. (Longhorn), which is included in our Other segment; |
|
| • | A $23 million impairment of our investment in Aux Sable Liquid Products, L.P. (Aux Sable), which is included in our Power segment. |
Loss from investments for the year ended December 31, 2004, includes:
| | |
| • | A $10.8 million impairment of our Longhorn investment; |
|
| • | $6.5 million net unreimbursed Longhorn recapitalization advisory fees; |
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| • | A $16.9 million impairment of our investment in Discovery Producer Services, L.L.C. (Discovery), which is included in our Midstream segment. |
Impairments of cost-based investmentsfor the year ended December 31, 2006, includes a $16.4$16 million impairment of a Venezuelan investment primarily due to a decline in reserve estimates. In 2006, our 10 percent direct working interest in an operating contract was converted to a 4 percent equity interest in a Venezuelan corporation which owns and operates oil and gas activities. Our 4 percent equity interest is reported as a cost method investment; previously, we accounted for our working interest using the proportionate consolidation method.
Impairments of cost-based investmentsInterest income and otherfor the yearyears ended December 31, 2004,2008 and 2007, includes a $20.8$10 million impairmentand $14 million, respectively, of our investment in an Indonesian toll road, primarily due to increased uncertaintygains from sales of the Indonesian economy.cost-based investments.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Investments
Investments at December 31, 2006 and 2005, are as follows:
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | December 31, | |
| | | (Millions) | | | 2008 | | 2007 | |
| | | (Millions) | |
| Equity method | | | | | | | | | |
| | |
| Equity method: | | | | | | | | | |
| Gulfstream Natural Gas System, L.L.C. — 50% | | $ | 387.5 | | | $ | 395.4 | | | $ | 525 | | | $ | 439 | |
| Discovery Producer Services, L.L.C. — 60%* | | | 221.2 | | | | 227.9 | | | | 184 | | | | 215 | |
| Petrolera Entre Lomas S.A. — 40.8% | | | 58.8 | | | | 51.9 | | | | 73 | | | | 65 | |
| ACCROVEN — 49.3% | | | 57.4 | | | | 60.0 | | | | 69 | | | | 62 | |
| Other | | | 89.5 | | | | 95.9 | | | | 96 | | | | 95 | |
| | | | | | | | | | | |
| | | | 814.4 | | | | 831.1 | | | | 947 | | | | 876 | |
| Cost method | | | 51.6 | | | | 56.7 | | | | 24 | | | | 25 | |
| | | | | | | | | | | |
| | | $ | 866.0 | | | $ | 887.8 | | | $ | 971 | | | $ | 901 | |
| | | | | | | | | | | |
| | |
| * | | We own 20% directly and 40% indirectly throughOur 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 Discovery’s limited liability company, which provide the other member of Discovery significant participatory rights such that we own approximately 22.5%.do not control the investment. |
The differenceDifferences between the carrying value of our equity investments and the underlying equity in the net assets of the investees is primarily related to impairments previously recognized.
Dividends and distributions, including those discussedpresented below, received from companies accounted for by the equity method were $115.6$167 million in 20062008 and $447.4$118 million in 2005.2007. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | (Millions) | |
| |
| Gulfstream Natural Gas System, L.L.C. | | $ | 58 | | | $ | 34 | |
| Discovery Producer Services, L.L.C. | | | 56 | | | | 36 | |
| Aux Sable Liquid Products L.P. | | | 28 | | | | 22 | |
| Petrolera Entre Lomas S.A. | | | 7 | | | | 12 | |
Gulfstream
In 2005,addition, we received a $310.5contributed $90 million distribution fromin 2008 and $38 million in 2007 to Gulfstream Natural Gas System, L.L.C. (Gulfstream) following its debt offering. We also received dividends from Gulfstream of $41.5 million in 2006 and $60.5 million in 2005.
Discovery
During 2005, our Midstream subsidiary acquired an additional 16.67 percent in Discovery, which was later reduced by 6.67 percent due to a nonaffiliated member exercising its purchase option. After these transactions, we hold a 60 percent interest in Discovery. We continue to account for this investment under the equity method due to
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the voting provisions of Discovery’s limited liability company which provide the other member of Discovery significant participatory rights such that we do not control the investment.
Additionally, we contributed $40.7 million during 2005 to Discovery for planned capital expenditures. Each owner contributed an amount equal to their respective ownership percentage, thus having no impact on the overall ownership allocation. We received distributions from Discovery of $27.2 million in 2006 and $31.3 million in 2005, which reduced the carrying value of our investment.
Longhorn
Based on management’s outlook for Longhorn at the end of the second quarter 2005, we assessed our equity investment in Longhorn to determine if there had been another-than-temporary decline in its fair value. As a result, we recorded an impairment of $49.1 million. In the fourth quarter of 2005, management of Longhorn decided to pursue a strategy of the sale of Longhorn. Based on initial indications from potential buyers, we determined that our Longhorn investment would require full impairment. Therefore, in fourth quarter 2005, we recorded a $38.1 million impairment to write off the remaining investment in Longhorn.
We continue to have an equity ownership interest in Longhorn, including 94.7 percent of the Class B Interests and 21.3 percent of the Common Interests, even though the management of Longhorn completed an asset sale of the pipeline during the third quarter of 2006. Summarized results of operations of equity method investments in 2006, as presented below, reflect the impact of Longhorn’s loss on this sale. As a result of the sale, we received full payment of the $10 million secured bridge loan that we provided Longhorn during 2005.
Aux Sable
During 2005, we decided to solicit sales offers for our equity investment in Aux Sable, a natural gas liquids extraction and fractionation facility. Based on initial indications of potential sales proceeds, management concluded that there was another-than-temporary decline in fair value below carrying value. Accordingly, we recorded an impairment of $23 million.
Summarized Financial Position and Results of Operations of Equity Method Investments
Financial position at December 31:
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| | | (Millions) | |
| |
| Current assets | | $ | 296.5 | | | $ | 470.5 | |
| Noncurrent assets | | | 3,301.7 | | | | 3,674.4 | |
| Current liabilities | | | 198.0 | | | | 362.0 | |
| Noncurrent liabilities | | | 1,311.5 | | | | 1,225.6 | |
Results of operations for the years ended December 31:
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Millions) | |
| |
| Gross revenue | | $ | 970.4 | | | $ | 1,337.5 | | | $ | 1,064.7 | |
| Operating income | | | 401.2 | | | | 236.3 | | | | 185.0 | |
| Net income (loss) | | | (14.6 | ) | | | 105.3 | | | | 107.8 | |
.
Guarantees on Behalf of Investees
We have guaranteed commercial letters of credit totaling $20 million on behalf of ACCROVEN. These expire in January 20082010 and have no carrying value.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
We have provided guarantees on behalf of certain entities in which we have an equity ownership interest. These generally guarantee operating performance measures and the maximum potential future exposure cannot be determined. There are no expiration dates associated with these guarantees. No amounts have been accrued at December 31, 20062008 and 2005.2007.
| |
Note 4. | Asset Sales and Other Accruals |
Significant gains or losses from asset sales and other accruals or adjustments reflected inother (income) expense — net withinsegment costs and expenses for the years noted are as follows:
| | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Millions) | |
| |
Exploration & Production | | | | | | | | | | | | |
| Gains on sales of certain natural gas properties | | $ | — | | | $ | (29.6 | ) | | $ | — | |
| Loss provision related to an ownership dispute | | | — | | | | — | | | | 15.4 | |
Midstream | | | | | | | | | | | | |
Accrual for Gulf Liquids litigation contingency. Associated with this contingency is an interest expense accrual of $22 million, which is included ininterest accrued (see Note 15) | | | 72.7 | | | | — | | | | — | |
| Arbitration award on a Gulf Liquids insurance claim dispute | | | — | | | | — | | | | (93.6 | ) |
Power | | | | | | | | | | | | |
| Accrual for litigation contingencies | | | 4.8 | | | | 82.2 | | | | — | |
| Reduction of contingent obligations associated with our former distributive power generation business | | | (12.7 | ) | | | — | | | | — | |
Other | | | | | | | | | | | | |
| Environmental accrual related to the Augusta refinery facility | | | — | | | | — | | | | 11.8 | |
Additional Items
Costs and operating expenses within our Gas Pipeline segment reported in 2005 includes:
| | |
| • | An adjustment to reduce costs by $12.1 million to correct the carrying value of certain liabilities recorded in prior periods; |
|
| • | Adjustments of $37.3 million reflected as increases in costs and operating expenses related to $32.1 million of prior period accounting and valuation corrections for certain inventory items and an accrual of $5.2 million for contingent refund obligations. |
Selling, general and administrative expenses within our Gas Pipeline segment in 2005 includes:
| | |
| • | An adjustment to reduce costs by $5.6 million to correct the carrying value of certain liabilities recorded in prior periods; |
|
| • | A $17.1 million reduction in pension expense for the cumulative impact of a correction of an error attributable to 2003 and 2004. (See Note 7.) |
10098
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| Note 4. | Asset Sales, Impairments and Other Accruals |
The following table presents significant gains or losses from asset sales, impairments and other accruals or adjustments reflected inother (income) expense— netwithinsegment costs and expenses.
| | | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (Millions) | |
| |
Exploration & Production | | | | | | | | | | | | |
| Gain on sale of contractual right to an international production payment | | $ | (148 | ) | | $ | — | | | $ | — | |
| Impairment of certain natural gas producing properties | | | 143 | | | | — | | | | — | |
Gas Pipeline | | | | | | | | | | | | |
| Income from change in estimate related to a regulatory liability | | | — | | | | (17 | ) | | | — | |
| Income from payments received for a terminated firm transportation agreement on Grays Harbor lateral | | | — | | | | (18 | ) | | | — | |
| Gain on sale of certain south Texas assets | | | (10 | ) | | | — | | | | — | |
Midstream | | | | | | | | | | | | |
| Income from favorable litigation outcome | | | — | | | | (12 | ) | | | — | |
| Impairment of Carbonate Trend pipeline | | | 6 | | | | 10 | | | | — | |
| Gulf Liquids litigation contingency accrual (see Note 16) | | | (32 | ) | | | — | | | | 73 | |
| Involuntary conversion gain related to Ignacio plant | | | (12 | ) | | | — | | | | — | |
Gas Marketing Services | | | | | | | | | | | | |
| Accrual for litigation contingencies | | | — | | | | 20 | | | | — | |
Other (income) expense — netwithinsegment costs and expensesalso includes net foreign currency exchange gains of $48 million in 2008, $5 million in 2007, and $5 million in 2006. The increase in 2008 primarily relates to the remeasurement of current assets held in U.S. dollars within our Canadian operations in the Midstream segment.
Impairment of certain natural gas producing properties
Based on a comparison of the estimated fair value to the carrying value, Exploration & Production recorded an impairment charge of $129 million in December 2008 related to properties in the Arkoma basin. Our impairment analysis included an assessment of undiscounted and discounted future cash flows, which considered year-end natural gas reserve quantities. Exploration & Production had previously recorded a $14 million impairment charge in 2008 due to unfavorable drilling results in the Arkoma basin.
Additional Item
In fourth-quarter 2008, Exploration & Production recorded a $34 million accrual for Wyoming severance taxes, which is reflected incosts and operating expenseswithinsegment costs and expenses. Associated with this charge is an interest expense accrual of $4 million, which is included ininterest accrued.(See Note 16.)
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| Note 5. | Provision for Income Taxes |
Theprovision for income taxesfrom continuing operations includes:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Current: | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal | | $ | (9.0 | ) | | $ | 225.0 | | | $ | 11.0 | | | $ | 179 | | | $ | 29 | | | $ | (9 | ) |
| State | | | 2.7 | | | | 2.8 | | | | (13.7 | ) | | | 24 | | | | 9 | | | | 3 | |
| Foreign | | | 43.4 | | | | 31.4 | | | | 11.0 | | | | 35 | | | | 46 | | | | 43 | |
| | | | | | | | | | | | | | | |
| | | | 37.1 | | | | 259.2 | | | | 8.3 | | | | 238 | | | | 84 | | | | 37 | |
| Deferred: | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal | | | 140.9 | | | | (52.9 | ) | | | 75.1 | | | | 466 | | | | 422 | | | | 146 | |
| State | | | 3.3 | | | | 15.6 | | | | 38.7 | | | | (11 | ) | | | (4 | ) | | | 4 | |
| Foreign | | | 25.0 | | | | (8.0 | ) | | | 9.2 | | | | 20 | | | | 22 | | | | 24 | |
| | | | | | | | | | | | | | | |
| | | | 169.2 | | | | (45.3 | ) | | | 123.0 | | | | 475 | | | | 440 | | | | 174 | |
| | | | | | | | | | | | | | | |
| Total provision | | $ | 206.3 | | | $ | 213.9 | | | $ | 131.3 | | | $ | 713 | | | $ | 524 | | | $ | 211 | |
| | | | | | | | | | | | | | | |
Reconciliations from theprovision for income taxesfrom continuing operations at the federal statutory rate to the realizedprovision for income taxesare as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Provision at statutory rate | | $ | 188.7 | | | $ | 186.0 | | | $ | 78.6 | | | $ | 717 | | | $ | 480 | | | $ | 195 | |
| Increases (decreases) in taxes resulting from: | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes (net of federal benefit) | | | 6.5 | | | | 21.5 | | | | 27.9 | | | | 8 | | | | 4 | | | | 7 | |
| Foreign operations — net | | | 25.3 | | | | 6.7 | | | | 6.1 | | | | — | | | | 18 | | | | 23 | |
| Utilization/valuation/expiration of charitable contributions | | | (9.3 | ) | | | 8.4 | | | | 13.8 | | |
| Federal income tax litigation | | | (40.0 | ) | | | 3.6 | | | | 1.6 | | | | (5 | ) | | | — | | | | (40 | ) |
| Non-deductible convertible debenture expenses | | | 9.5 | | | | — | | | | — | | | | — | | | | — | | | | 10 | |
| Adjustment of excess deferred taxes | | | 7.4 | | | | (20.2 | ) | | | — | | |
| Non-deductible penalties | | | — | | | | 17.7 | | | | (.9 | ) | |
| Other — net | | | 18.2 | | | | (9.8 | ) | | | 4.2 | | | | (7 | ) | | | 22 | | | | 16 | |
| | | | | | | | | | | | | | | |
| Provision for income taxes | | $ | 206.3 | | | $ | 213.9 | | | $ | 131.3 | | | $ | 713 | | | $ | 524 | | | $ | 211 | |
| | | | | | | | | | | | | | | |
State income taxes (net of federal benefit) were reduced by $46 million in 2008 due to a reduction in our estimate of the effective deferred state rate reflective of a change in the mix of jurisdictional attribution of taxable income.
Utilization of foreign operating loss carryovers reduced the provision for income taxes by $13 million, $5 million and $3 million in 2008, 2007 and $13 million in 2006, and 2005, respectively. During 2004, the utilization of foreign tax credits reduced the provision for income taxes by $12 million.
Income from continuing operations before income taxes and cumulative effect of change in accounting principleincludes $141$196 million, $59$169 million, and $51$144 million of internationalforeign income in 2008, 2007, and 2006, 2005, and 2004, respectively.
We provide for income taxes using the asset and liability method as required by SFAS No. 109, “Accounting for Income Taxes.” As a result of additional analysis of our tax basis and book basis asset and liabilities, we recorded a tax provision of $7.4 million and a tax benefit of $20.2 million in 2006 and 2005, respectively, to adjust the overall deferred income tax liabilities on the Consolidated Balance Sheet.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various tax filing positions, we record a liabilityapply the two-step process of recognition and measurement as required by FASB Interpretation No. 48, “Accounting for probable tax contingencies.Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). We adopted FIN 48 effective January 1, 2007. In association with this liability, we record an
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
estimate of related interest and tax exposure as a component of our current tax provision. The impact of this accrual is included withinother — net in our reconciliation of the tax provision to the federal statutory rate.
One of our wholly owned subsidiaries, Transco Coal Gas Company, was engaged in a dispute with the Internal Revenue Service (IRS) in which the principle issue was the recapture of certain income tax credits associated with
the construction and operation of a coal gasification plant in North Dakota by Great Plains Gasification Associates, a partnership in which Transco Coal Gas Company was a partner in the 1980’s. The IRS took alternative positions that alleged a disposition date for purposes of tax credit recapture that was earlier than the position taken in the partnership tax return. After settlement negotiations failed, the matter was tried before the U.S. Tax Court in February 2005. On December 27, 2006, the Tax Court ruled that the partnership utilized the appropriate disposition date for purposes of tax credit recapture.
Significant components ofdeferred tax liabilitiesanddeferred tax assets as of December 31, 2006,2008, and 2005,2007, are as follows:
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Millions) | | | (Millions) | |
| |
| Deferred tax liabilities: | | | | | | | | | | | | | | | | |
| Property, plant and equipment | | $ | 2,898.5 | | | $ | 2,718.9 | | | $ | 3,568 | | | $ | 3,192 | |
| Derivatives — net | | | 223.4 | | | | 61.3 | | | | 263 | | | | — | |
| Investments | | | 210.2 | | | | 158.6 | | | | 163 | | | | 176 | |
| Other | | | 100.4 | | | | 96.7 | | | | 112 | | | | 89 | |
| | | | | | | | | | | |
| Total deferred tax liabilities | | | 3,432.5 | | | | 3,035.5 | | | | 4,106 | | | | 3,457 | |
| | | | | | | | | | | |
| Deferred tax assets: | | | | | | | | | | | | | | | | |
| Accrued liabilities | | | | 581 | | | | 433 | |
| Derivatives — net | | | | — | | | | 173 | |
| Foreign carryovers | | | | 3 | | | | 50 | |
| Minimum tax credits | | | 145.6 | | | | 163.8 | | | | — | | | | 8 | |
| Accrued liabilities | | | 510.2 | | | | 285.2 | | |
| Receivables | | | 17.3 | | | | 39.3 | | |
| Federal carryovers | | | 182.8 | | | | 286.0 | | |
| Foreign carryovers | | | 36.1 | | | | 30.4 | | |
| Other | | | 33.9 | | | | — | | | | 55 | | | | 53 | |
| | | | | | | | | | | |
| Total deferred tax assets | | | 925.9 | | | | 804.7 | | | | 639 | | | | 717 | |
| | | | | | | | | | | |
| Less valuation allowance | | | 36.1 | | | | 37.1 | | | | 15 | | | | 57 | |
| | | | | | | | | | | |
| Net deferred tax assets | | | 889.8 | | | | 767.6 | | | | 624 | | | | 660 | |
| | | | | | | | | | | |
| Overall net deferred tax liabilities | | $ | 2,542.7 | | | $ | 2,267.9 | | | $ | 3,482 | | | $ | 2,797 | |
| | | | | | | | | | | |
Thevaluation allowanceat December 31, 2006,2008 and December 31, 2007, serves to reduce the recognized tax benefit associated with foreign carryovers to an amount that will, more likely than not, be realized. Thevaluation allowanceat December 31, 2005 servesWe do not expect to reduce the recognizedbe able to utilize our $15 million of foreign deferred tax benefit associated with charitable contributionassets.
The reductions in foreign carryovers and foreign carryoversthe valuation allowance were primarily due to an amount that will, more likely than not, be realized.the restructuring of the European operations of our former power business.
Undistributed earnings of certain consolidated foreign subsidiaries at December 31, 2006,2008, totaled approximately $198$377 million. No provision for deferred U.S. income taxes has been made for these subsidiaries because we intend to permanently reinvest such earnings in foreign operations.
Cash payments for income taxes (net of refunds) were $155 million, $384 million, and $79 million in 2008, 2007, and 2006, respectively. Cash tax payments include settlements with taxing authorities associated with prior period audits of $47 million, $94 million, and $42 million in 2008, 2007 and 2006, respectively.
102101
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Cash paymentsAs of December 31, 2008, we had approximately $79 million of unrecognized tax benefits. If recognized, approximately $70 million, net of federal tax expense, would be recorded as a reduction of income tax expense. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | (Millions) | |
| |
| Balance at beginning of period | | $ | 76 | | | $ | 93 | |
| Additions based on tax positions related to the current year | | | 3 | | | | — | |
| Additions for tax positions for prior years | | | 8 | | | | 5 | |
| Reductions for tax positions of prior years | | | (8 | ) | | | (19 | ) |
| Settlement with taxing authorities | | | — | | | | (3 | ) |
| Lapse of applicable statute of limitations | | | — | | | | — | |
| | | | | | | | | |
| Balance at end of period | | $ | 79 | | | $ | 76 | |
| | | | | | | | | |
We recognize related interest and penalties as a component of income tax expense. Approximately $2 million and $60 million of interest and penalties were included in the provision for income taxes (net of refunds) were $79 million, $230during 2008 and 2007, respectively. Approximately $81 million and $8$86 million in 2006, 2005,of interest and 2004, respectively. Cashpenalties primarily relating to uncertain tax payments include settlements with taxing authorities associated with prior period auditspositions have been accrued as of $42 millionDecember 31, 2008 and $204 million in 2006 and 2005,2007, respectively.
AtAs of December 31, 2008, the Internal Revenue Service (IRS) examinations of our consolidated U.S. income tax returns for 2006 federal net operating loss carryoversand 2007 were in process. IRS examinations for 1997 through 2005 have been completed at the field level but the years remain open for certain unresolved issues. The statute of limitations for most states expires one year after expiration of the IRS statute.
Generally, tax returns for our Venezuelan, Argentine, and Canadian entities are $509 million. We expectopen to utilize our net operating loss carryovers prior to expiration in 2022audit from 2003 through 2025. We also expect to utilize $13 million of charitable contribution carryovers prior to their expiration in 2007 through 2010. We2008. Certain Canadian entities are currently under examination.
During the next twelve months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to be able to utilizehave a material impact on our $36.1 million foreign deferred tax assets related to carryovers.
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). We adopted the Interpretation beginning January 1, 2007. The impact of this adoption is more fully described in Note 1.financial position.
| |
| Note 6. | Earnings Per Common Share from Continuing Operations |
Basic and diluted earnings per common share for the years ended December 31, 2006, 20052008, 2007 and 2004,2006, are:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Dollars in millions, except per-share | | | (Dollars in millions, except per-share amounts; shares in thousands) | |
| | | amounts; shares in thousands) | |
| Income from continuing operations available to common stockholders for basic and diluted earnings per common share(1) | | | $ | 1,334 | | | $ | 847 | | | $ | 347 | |
| | | | | | | | |
| Income from continuing operations available to common stockholders for basic and diluted earnings per share(1) | | $ | 332.8 | | | $ | 317.4 | | | $ | 93.2 | | |
| | | | | | | | | |
| Basic weighted-average shares(2) | | | 595,053 | | | | 570,420 | | | | 529,188 | | |
| Basic weighted-average shares(2)(3) | | | | 581,342 | | | | 596,174 | | | | 595,053 | |
| Effect of dilutive securities: | | | | | | | | | | | | | | | | | | | | | | | | |
| Unvested restricted stock units(3) | | | 1,029 | | | | 2,890 | | | | 2,631 | | |
| Nonvested restricted stock units | | | | 1,334 | | | | 1,627 | | | | 1,029 | |
| Stock options | | | 4,440 | | | | 4,989 | | | | 3,792 | | | | 3,439 | | | | 4,743 | | | | 4,440 | |
| Convertible debentures | | | 8,105 | | | | 27,548 | | | | — | | |
| Convertible debentures(3) | | | | 6,604 | | | | 7,322 | | | | 8,105 | |
| | | | | | | | | | | | | | | |
| Diluted weighted-average shares | | | 608,627 | | | | 605,847 | | | | 535,611 | | | | 592,719 | | | | 609,866 | | | | 608,627 | |
| | | | | | | | | | | | | | | |
| Earnings per common share from continuing operations: | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | .56 | | | $ | .55 | | | $ | .18 | | | $ | 2.30 | | | $ | 1.42 | | | $ | .58 | |
| | | | | | | | | | | | | | | |
| Diluted | | $ | .55 | | | $ | .53 | | | $ | .18 | | | $ | 2.26 | | | $ | 1.40 | | | $ | .57 | |
| | | | | | | | | | | | | | | |
102
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| (1) | | The years ended December 31, 2008, 2007 and 2006, and 2005, include $3.0$2 million, $3 million and $10.2$3 million of interest expense, net of tax, associated with our convertible debentures. (See Note 12.) These amounts have been added back toincome from continuing operations available to common stockholdersto calculate diluted earnings per common share. (See discussion of antidilutive items below.) |
| |
| (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 20.220 million shares of common stock related to a conversion offer for our 5.5 percent convertible debentures. In February 2005 and October 2004, we issued 10.9 million and 33.1 million, respectively, common shares associated with our FELINE PACS units. |
|
(3) | | The unvested restricted stock units outstanding at December 31, 2006, will vest over the period from January 2007 to December 2009. |
Approximately 27.5 million weighted-average shares related to the assumed conversion of convertible debentures, as well as the related interest, have been excluded from the computation of diluted earnings per common share for the year ended December 31, 2004. Inclusion of these shares would have an antidilutive effect on diluted earnings per common share. If no other components used to calculate diluted earnings per common share change, we estimate the assumed conversion of convertible debentures would have become dilutive and therefore would be included in diluted earnings per common share at anincome from continuing operations available to common stockholdersamount of $198.1 million for the year ended December 31, 2004.
103
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The table below includes information related to stock options that were outstanding at the end of each respective year but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
| Options excluded (millions) | | | 3.6 | | | | 4.7 | | | | 8.5 | | | | 6.4 | | | | .8 | | | | 3.6 | |
| Weighted-average exercise prices of options excluded | | $ | 36.14 | | | $ | 35.22 | | | $ | 28.21 | | | | $26.41 | | | | $40.07 | | | | $36.14 | |
| Exercise price ranges of options excluded | | $ | 26.79 - $42.29 | | | $ | 22.68 - $42.29 | | | $ | 14.61 - $42.29 | | | | $16.40 - $42.29 | | | | $36.66 -$42.29 | | | | $26.79 - $42.29 | |
| Fourth quarter weighted-average market price | | $ | 25.77 | | | $ | 22.41 | | | $ | 14.41 | | | | $16.37 | | | | $35.14 | | | | $25.77 | |
| |
| Note 7. | Employee Benefit Plans |
We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect to receive annuity payments, a lump sum payment or a combination of lump sum and annuity payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for thesethe subsidized retiree medical benefits, except for participants that were employees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups. Certain of these other postretirement benefit plans, particularly the subsidized retiree medical benefit plans, provide for retiree contributions and contain other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for these plans anticipates future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases.
SFAS No. 158 Adoption
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158). This Statement requires sponsors of defined benefit pension and other postretirement benefit plans to recognize the funded status of their pension and other postretirement benefit plans in the statement of financial position, measure the fair value of plan assets and benefit obligations as of the date of the fiscal year-end statement of financial position, and provide additional disclosures. On December 31, 2006, we adopted the recognition and disclosure provisions of SFAS No. 158, the effect of which has been reflected in the accompanying consolidated financial statements as of December 31, 2006, as described below. The adoption had no impact on the consolidated financial statements at December 31, 2005 or 2004. SFAS No. 158’s provisions regarding the change in the measurement date of postretirement benefit plans are not applicable as we already use a measurement date of December 31. There is no effect on our Consolidated Statement of Income for the year ended December 31, 2006, or for any periods presented related to the adoption of SFAS No. 158, nor will our future operating results be affected by the adoption.
Prior to the adoption of SFAS No. 158, accounting rules allowed for the delayed recognition of certain actuarial gains and losses caused by differences between actual and assumed outcomes, as well as charges or credits caused by plan changes impacting the benefit obligations which were attributed to participants’ prior service. These unrecognized net actuarial gains or losses and unrecognized prior service costs or credits represented the difference between the plans’ funded status and the amount recognized on the Consolidated Balance Sheet. In accordance with SFAS No. 158, we recorded adjustments toaccumulated other comprehensive loss, net of income taxes, to recognize the funded status of our pension and other postretirement benefit plans on our Consolidated Balance Sheet. For our FERC-regulated gas pipelines, we recorded the adjustment tonet regulatory liabilitiesfor our other postretirement benefit plans. These
104103
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
adjustments represent the previously unrecognized net actuarial gains and losses and unrecognized prior service costs or credits. The detail of the effect of adopting SFAS No. 158 is provided in the following table.
The adjustments recorded toaccumulated other comprehensive lossandnet regulatory liabilitieswill be recognized as components ofnet periodic pension expenseornet periodic other postretirement benefit expenseand amortized over future periods in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” in the same manner as prior to the adoption of SFAS No. 158. Actuarial gains and losses that arise in subsequent periods and are not recognized asnet periodic pensionorother postretirement benefit expensein the same period will now be recognized inother comprehensive income (loss)andnet regulatory liabilities. These amounts will be recognized subsequently as a component ofnet periodic pensionorother postretirement benefit expense following the same basis as the amounts recognized inaccumulated other comprehensive lossandnet regulatory liabilitiesupon adoption of SFAS No. 158.
The effects of adopting SFAS No. 158 on our Consolidated Balance Sheet at December, 31, 2006, are presented in the following tables. The disclosures in this note exclude the impact of a pension plan of an equity method investee.
| | | | | | | | | | | | | |
| | | Prior to
| | | Effect of
| | | After
| |
| | | SFAS No. 158
| | | SFAS No. 158
| | | SFAS No. 158
| |
| | | Adoption(1) | | | Adoption(1) | | | Adoption(1) | |
| | | | | | (Millions) | | | | |
| |
| Balances related to pension plans within: | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | |
| Noncurrent assets | | $ | 330.8 | | | $ | (216.7 | ) | | $ | 114.1 | |
| Liabilities: | | | | | | | | | | | | |
| Current liabilities | | | — | | | | 1.0 | | | | 1.0 | |
| Net regulatory liabilities | | | 10.5 | | | | 2.2 | | | | 12.7 | |
| Noncurrent liabilities | | | 18.9 | | | | 20.2 | | | | 39.1 | |
| Deferred income tax liabilities | | | (3.1 | ) | | | (91.6 | ) | | | (94.7 | ) |
| Stockholders’ equity: | | | | | | | | | | | | |
| Accumulated other comprehensive loss | | | (4.9 | ) | | | (148.5 | ) | | | (153.4 | ) |
| Balances related to other postretirement benefits plans within: | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | |
| Noncurrent assets | | $ | 13.6 | | | $ | (13.6 | ) | | $ | — | |
| Liabilities: | | | | | | | | | | | | |
| Current liabilities | | | 10.6 | | | | (1.4 | ) | | | 9.2 | |
| Net regulatory liabilities | | | (8.0 | ) | | | 12.8 | | | | 4.8 | |
| Noncurrent liabilities | | | 133.2 | | | | (10.5 | ) | | | 122.7 | |
| Deferred income tax liabilities | | | — | | | | (12.5 | ) | | | (12.5 | ) |
| Stockholders’ equity: | | | | | | | | | | | | |
| Accumulated other comprehensive loss | | | — | | | | (2.0 | ) | | | (2.0 | ) |
| | |
(1) | | Amounts in brackets represent a reduction within the line item balance included on the Consolidated Balance Sheet. |
Prior to the adoption of SFAS No. 158, we had computed an additional minimum pension liability of $10.2 million. The effect of recognizing this additional minimum pension liability is included asaccumulated other comprehensive lossof $4.9 million (net of taxes of $3.1 million) andnet regulatory liabilitiesof $2.2 million under the “Prior to SFAS No. 158 Adoption” column within the previous table.
105
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Accumulated other comprehensive lossat December 31, 2006 includes the following:
| | | | | | | | | | | | | | | | | |
| | | | | | Other Postretirement
| |
| | | Pension Benefits | | | Benefits | |
| | | Gross | | | Net of Tax | | | Gross | | | Net of Tax | |
| | | (Millions) | |
| |
| Amounts not yet recognized in net periodic benefit expense: | | | | | | | | | | | | | | | | |
| Unrecognized prior service cost | | $ | (5.7 | ) | | $ | (3.5 | ) | | $ | (6.7 | ) | | $ | (4.1 | ) |
| Unrecognized net actuarial gains (losses) | | | (242.4 | ) | | | (149.9 | ) | | | (7.8 | ) | | | 2.1 | |
| Amounts expected to be recognized in net periodic benefit expense (income) in 2007: | | | | | | | | | | | | | | | | |
| Prior service cost (credit) | | $ | (.4 | ) | | $ | (.3 | ) | | $ | 1.1 | | | $ | .7 | |
| Net actuarial (gains) losses | | | 16.5 | | | | 10.2 | | | | — | | | | (.1 | ) |
Net regulatory liabilitiesincludes unrecognized prior service credits of $4.6 million and unrecognized net actuarial gains of $8.2 million associated with our FERC-regulated gas pipelines. These amounts have not yet been recognized innet periodic other postretirement benefit expense. The prior service credit included innet regulatory liabilitiesand expected to be recognized innet periodic other postretirement benefit expensein 2007 is $1.5 million. No actuarial gains included innet regulatory liabilitiesare expected to be recognized innet periodic other postretirement benefit expensein 2007.
106
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Benefit Obligations
The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated. It also presents a reconciliation of the funded status of these benefit plans to the amounts recorded in the Consolidated Balance Sheet at December 31, 2005. The annual measurement date for our plans is December 31. The sale of our power business in 2007 did not have a significant impact on our employee benefit plans. (See Note 2.)
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | Other
| |
| | | | | Other Postretirement
| | | | | Postretirement
| |
| | | Pension Benefits | | Benefits | | | Pension Benefits | | Benefits | |
| | | 2006 | | 2005 | | 2006 | | 2005 | | | 2008 | | 2007 | | 2008 | | 2007 | |
| | | | | (Millions) | | | | | (Millions) | |
| |
| Change in benefit obligation: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Benefit obligation at beginning of year | | $ | 897.4 | | | $ | 893.0 | | | $ | 375.4 | | | $ | 268.4 | | | $ | 896 | | | $ | 931 | | | $ | 284 | | | $ | 312 | |
| Service cost | | | 22.1 | | | | 21.5 | | | | 3.2 | | | | 3.3 | | | | 23 | | | | 23 | | | | 2 | | | | 3 | |
| Interest cost | | | 50.9 | | | | 47.6 | | | | 17.3 | | | | 20.3 | | | | 60 | | | | 54 | | | | 18 | | | | 17 | |
| Plan participants’ contributions | | | — | | | | — | | | | 4.7 | | | | 4.3 | | | | — | | | | — | | | | 5 | | | | 5 | |
| Settlement benefits paid | | | — | | | | (4.0 | ) | | | — | | | | — | | |
| Benefits paid | | | (52.4 | ) | | | (58.2 | ) | | | (24.0 | ) | | | (24.0 | ) | | | (70 | ) | | | (64 | ) | | | (23 | ) | | | (23 | ) |
| Plan amendments | | | — | | | | — | | | | — | | | | 51.2 | | |
| Medicare Part D subsidy | | | | — | | | | — | | | | 2 | | | | — | |
| Plan amendment | | | | — | | | | — | | | | (38 | ) | | | — | |
| Actuarial (gain) loss | | | 13.3 | | | | (2.5 | ) | | | (64.2 | ) | | | 51.9 | | | | 126 | | | | (48 | ) | | | 23 | | | | (30 | ) |
| | | | | | | | | | | | | | | | | | | |
| Benefit obligation at end of year | | | 931.3 | | | | 897.4 | | | | 312.4 | | | | 375.4 | | | | 1,035 | | | | 896 | | | | 273 | | | | 284 | |
| | | | | | | | | | | | | | | | | | | |
| Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of year | | | 887.6 | | | | 835.5 | | | | 163.6 | | | | 158.9 | | | | 1,074 | | | | 1,005 | | | | 192 | | | | 180 | |
| Actual return on plan assets | | | 126.8 | | | | 56.4 | | | | 21.6 | | | | 9.5 | | | | (360 | ) | | | 92 | | | | (62 | ) | | | 15 | |
| Employer contributions | | | 43.3 | | | | 57.9 | | | | 14.6 | | | | 14.9 | | | | 61 | | | | 41 | | | | 14 | | | | 15 | |
| Plan participants’ contributions | | | — | | | | — | | | | 4.7 | | | | 4.3 | | | | — | | | | — | | | | 5 | | | | 5 | |
| Benefits paid | | | (52.4 | ) | | | (58.2 | ) | | | (24.0 | ) | | | (24.0 | ) | | | (70 | ) | | | (64 | ) | | | (23 | ) | | | (23 | ) |
| Settlement benefits paid | | | — | | | | (4.0 | ) | | | — | | | | — | | |
| | | | | | | | | | | | | | | | | | | |
| Fair value of plan assets at end of year | | | 1,005.3 | | | | 887.6 | | | | 180.5 | | | | 163.6 | | | | 705 | | | | 1,074 | | | | 126 | | | | 192 | |
| | | | | | | | | | | | | | | | | | | |
| Funded status — overfunded (underfunded) | | $ | 74.0 | | | | (9.8 | ) | | $ | (131.9 | ) | | | (211.8 | ) | | $ | (330 | ) | | $ | 178 | | | $ | (147 | ) | | $ | (92 | ) |
| | | | | | | | | | | | | | | |
| Unrecognized net actuarial loss | | | | | | | 309.7 | | | | | | | | 74.4 | | |
| Unrecognized prior service cost | | | | | | | 5.1 | | | | | | | | 1.7 | | |
| | | | | | | |
| Prepaid (accrued) benefit cost | | | | | | $ | 305.0 | | | | | | | $ | (135.7 | ) | |
| | | | | | | |
| Accumulated benefit obligation | | $ | 871.6 | | | $ | 831.4 | | | | | | | | | | | $ | 959 | | | $ | 838 | | | | | | | | | |
| | | | | | | | | | | |
The net overfunded/underfunded status of our pension plans and other postretirement benefit plans presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:
| | | | | | | | | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | (Millions) | |
| |
| Overfunded pension plans: | | | | | | | | |
Noncurrent assets | | $ | — | | | $ | 203 | |
| Underfunded pension plans: | | | | | | | | |
Current liabilities | | | 1 | | | | 1 | |
Noncurrent liabilities | | | 329 | | | | 24 | |
| Underfunded other postretirement benefit plans: | | | | | | | | |
Current liabilities | | | 8 | | | | 9 | |
Noncurrent liabilities | | | 139 | | | | 83 | |
107104
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Amounts recognized in the Consolidated Balance Sheet at December 31, 2005 consist of:
| | | | | | | | | |
| | | | | | Other
| |
| | | Pension
| | | Postretirement
| |
| | | Benefits | | | Benefits | |
| | | (Millions) | |
| |
| Prepaid benefit cost | | $ | 312.6 | | | $ | — | |
| Accrued benefit cost | | | (16.8 | ) | | | (135.7 | ) |
| Regulatory asset | | | 2.3 | | | | — | |
| Accumulated other comprehensive loss (before tax) | | | 6.9 | | | | — | |
| | | | | | | | | |
| Prepaid (accrued) benefit cost | | $ | 305.0 | | | $ | (135.7 | ) |
| | | | | | | | | |
The net underfunded/overfunded status of our pension plans presented in the previous table is recognized in the December 31, 2006, Consolidated Balance Sheet innoncurrent assetsas $114.1 million for our overfunded pension plans and incurrent liabilitiesas $1.0 million and innoncurrent liabilities as $39.1 million for our underfunded pension plans. The underfunded status of our other postretirement benefit plans presented in the previous table is recognized in the December 31, 2006, Consolidated Balance Sheet incurrent liabilitiesas $9.2 million and innoncurrent liabilitiesas $122.7 million. The plan assets within our other postretirement benefit plans are intended to be used for the payment of benefits for certain groups of participants. Thecurrent liabilitiesfor the other postretirement benefit plans represent the actuarial present valuecurrent portion of benefits includedexpected to be payable in the benefit obligation payable in 2007subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.
Theregulatory assetshown in 2005 in the table above is the portion of the additional minimum pension liability recognized by our FERC-regulated gas pipelines. As required by FERC accounting guidelines, our FERC-regulated gas pipelines were required to record the effect of an additional minimum pension liability to aregulatory assetinstead ofaccumulated other comprehensive loss.
The 2006 2008 benefit obligationactuarial lossof $13.3$126 million for our pension plans included in the table of changes in benefit obligation is due primarily to the impact of actual results differing from assumed results such as compensation and participant deaths, offset bydecreases in the net impact of changes in assumptionsdiscount rate utilized to calculate the benefit obligation includingand changes to the discount rate, mortality and expected form ofassumptions. The 2007 benefit payments. The 2005obligationactuarial gainof $2.5$48 million for our pension plans included in the table of changes in benefit obligation reflects a gain of approximately $68 million for the cumulative impact of a correction of an error determined to have occurred in 2003 and 2004. The error was associated with our third-party actuarial computation of the benefit obligation which resulted in the identification of errors in certain Transco participant data involving annuity contract information utilized for 2003 and 2004. This gain is offset substantially by the impact of changes to the discount rates utilized to determine the benefit obligation. The 2006actuarial gainof $64.2 million for our other postretirement benefit plans included in the table of changes in benefit obligation is due primarily to the impact of changes in the discount rate assumptions utilized to calculate the benefit obligation including claims costs, health care cost trend rates and the discount rate, as well as actual results differing from assumed results such as participant deaths and terminations prior to retirement.obligation. The 20052008 benefit obligationactuarial lossof $51.9$23 million for our other postretirement benefit plans included in the table of changes in benefit obligation is due primarily to the impact of changesthe decrease in assumptions utilizedthe discount rate used to calculate the benefit obligation includingand changes to the health care cost trend rates,mortality assumptions. The 2008 other postretirement benefitsplan amendmentof $38 million is due to an increase in the retirees’ cost-sharing percentage within our subsidized retiree medical benefit plans. The 2007 benefit obligationactuarial gainof $30 million for our other postretirement benefit plans is due primarily to the impact of the increase in the discount rate used to calculate the benefit obligation and estimated cost savings related toa decrease in the Medicare Prescription Drug Act.number of eligible participants in the plan.
At December 31, 2008, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets. At December 31, 2007, only our unfunded nonqualified pension plans had projected benefit obligations and accumulated benefit obligations in excess of plan assets. The projected benefit obligation of the unfunded nonqualified pension plans was $25 million and the accumulated benefit obligation was $22 million at December 31, 2007. There are no assets for these plans.
The current accounting rules for the determination ofnet periodic pension andother postretirement benefit expenseallow for the delayed recognition of gains and losses caused by differences between actual and assumed outcomes for items such as estimated return on plan assets, or caused by changes in assumptions for items such as discount rates or estimated future compensation levels. Theunrecognized net actuarial lossgain (loss)presented in the previous tablesfollowing table and recorded inaccumulated other comprehensive lossandnet regulatory liabilitiesassetsat December 31, 2006, represents the cumulative net deferred lossesgain (loss) from these types of differences or changes which have not yet been recognized in the Consolidated Statement of Income. A portion of thenet actuarial gain (loss)is amortized over the participants’ average remaining future years of service, which is approximately 12 years for both our pension plans and our other postretirement benefit plans.
Pre-tax amounts not yet recognized innet periodic benefit expenseat December 31 are as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | Other
| |
| | | | | | Postretirement
| |
| | | Pension Benefits | | | Benefits | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | (Millions) | |
| |
Amounts included inaccumulated other comprehensive loss: | | | | | | | | | | | | | | | | |
| Prior service (cost) credit | | $ | (5 | ) | | $ | (6 | ) | | $ | 12 | | | $ | (5 | ) |
| Net actuarial gain (loss) | | | (708 | ) | | | (156 | ) | | | (8 | ) | | | 7 | |
Amounts included innet regulatory assetsassociated with our FERC-regulated gas pipelines: | | | | | | | | | | | | | | | | |
| Prior service credit | | | N/A | | | | N/A | | | $ | 24 | | | $ | 3 | |
| Net actuarial gain (loss) | | | N/A | | | | N/A | | | | (57 | ) | | | 26 | |
108105
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
been recognized in the Consolidated Statement of Income. A portion of the net unrecognized gains and losses are amortized over the participants’ average remaining future years of service, which is approximately 12 years for our pension plans and 13 years for our other postretirement benefit plans.
We have multiple pension plans that are aggregated as prescribed for reporting purposes including both overfunded and underfunded pension plans.
Information for pension plans with a projected benefit obligation in excess of plan assets:
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
| | | (Millions) | |
| |
| Projected benefit obligation | | $ | 479.8 | | | $ | 428.6 | |
| Fair value of plan assets | | | 439.7 | | | | 359.7 | |
Information for pension plans with an accumulated benefit obligation in excess of plan assets:
| | | | | | | | | |
| | | December 31, | |
| | | 2006 | | | 2005 | |
| | | (Millions) | |
| |
| Accumulated benefit obligation | | $ | 18.9 | | | $ | 16.7 | |
| Fair value of plan assets | | | — | | | | — | |
Net Periodic Pension and Other Postretirement Benefit Expense (Income)and Items Recognized in Other Comprehensive Income (Loss)
Net periodic pension expense (income)andother postretirement benefit expenseand other changes in plan assets and benefit obligations recognized inother comprehensive income (loss)before taxes for the years ended December 31, 2008, 2007, and 2006, 2005, and 2004, consistsconsist of the following:
| | | | | | | | | | | | | |
| | | Pension Benefits | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Millions) | |
| |
| Components of net periodic pension expense (income): | | | | | | | | | | | | |
| Service cost | | $ | 22.1 | | | $ | 21.5 | | | $ | 24.0 | |
| Interest cost | | | 50.9 | | | | 47.6 | | | | 50.5 | |
| Expected return on plan assets | | | (66.8 | ) | | | (71.1 | ) | | | (64.9 | ) |
| Amortization of prior service credit | | | (.6 | ) | | | (.4 | ) | | | (1.5 | ) |
| Recognized net actuarial (gain) loss | | | 20.6 | | | | (4.9 | ) | | | 9.4 | |
| Regulatory asset amortization (deferral) | | | (.2 | ) | | | .6 | | | | 2.0 | |
| Settlement/curtailment expense | | | — | | | | 2.7 | | | | .1 | |
| | | | | | | | | | | | | |
| Net periodic pension expense (income) | | $ | 26.0 | | | $ | (4.0 | ) | | $ | 19.6 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Other
| |
| | | Pension Benefits | | | Postretirement Benefits | |
| | | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| | | (Millions) | |
| |
| Components of net periodic benefit expense: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 23 | | | $ | 23 | | | $ | 22 | | | $ | 2 | | | $ | 3 | | | $ | 3 | |
| Interest cost | | | 60 | | | | 54 | | | | 51 | | | | 18 | | | | 17 | | | | 17 | |
| Expected return on plan assets | | | (79 | ) | | | (73 | ) | | | (67 | ) | | | (13 | ) | | | (12 | ) | | | (11 | ) |
| Amortization of prior service cost (credit) | | | 1 | | | | — | | | | (1 | ) | | | — | | | | — | | | | — | |
| Amortization of net actuarial loss | | | 13 | | | | 19 | | | | 21 | | | | — | | | | — | | | | — | |
| Amortization of regulatory asset | | | — | | | | 1 | | | | — | | | | 5 | | | | 5 | | | | 7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net periodic benefit expense | | $ | 18 | | | $ | 24 | | | $ | 26 | | | $ | 12 | | | $ | 13 | | | $ | 16 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized inother comprehensive income (loss): | | | | | | | | | | | | | | | | | | | | | | | | |
| Net actuarial (gain) loss | | $ | 565 | | | $ | (68 | ) | | | | | | $ | 15 | | | $ | (15 | ) | | | | |
| Prior service credit | | | — | | | | — | | | | | | | | (16 | ) | | | — | | | | | |
| Amortization of net actuarial loss | | | (13 | ) | | | (19 | ) | | | | | | | — | | | | — | | | | | |
| Amortization of prior service cost | | | (1 | ) | | | — | | | | | | | | (1 | ) | | | (2 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized inother comprehensive income (loss) | | | 551 | | | | (87 | ) | | | | | | | (2 | ) | | | (17 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total recognized innet periodic benefit expenseandother comprehensive income (loss) | | $ | 569 | | | $ | (63 | ) | | | | | | $ | 10 | | | $ | (4 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with our FERC-regulated gas pipelines are recognized innet regulatory assetsat December 31, 2008, and includenet actuarial lossof $83 million,prior service creditof $22 million, andamortization of prior service creditof $1 million. At December 31, 2007, amounts recognized innet regulatory liabilitiesincludednet actuarial gainof $18 million andamortization of prior service creditof $2 million.
Pre-tax amounts expected to be amortized innet periodic benefit expensein 2009 are as follows:
| | | | | | | | | |
| | | | | | Other
| |
| | | Pension
| | | Postretirement
| |
| | | Benefits | | | Benefits | |
| | | (Millions) | |
| |
Amounts included inaccumulated other comprehensive loss: | | | | | | | | |
| Prior service cost (credit) | | $ | 1 | | | $ | (2 | ) |
| Net actuarial loss | | | 45 | | | | — | |
Amounts included innet regulatory assetsassociated with our FERC-regulated gas pipelines: | | | | | | | | |
| Prior service credit | | | N/A | | | $ | (5 | ) |
| Net actuarial loss | | | N/A | | | | 3 | |
109106
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | |
| | | Other Postretirement Benefits | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | | | | (Millions) | | | | |
| |
| Components of net periodic other postretirement benefit expense: | | | | | | | | | | | | |
| Service cost | | $ | 3.2 | | | $ | 3.3 | | | $ | 3.2 | |
| Interest cost | | | 17.3 | | | | 20.3 | | | | 18.8 | |
| Expected return on plan assets | | | (11.0 | ) | | | (11.5 | ) | | | (12.4 | ) |
| Amortization of transition obligation | | | — | | | | — | | | | 2.7 | |
| Amortization of prior service cost (credit) | | | (.4 | ) | | | (4.3 | ) | | | .6 | |
| Recognized net actuarial loss | | | — | | | | 3.2 | | | | — | |
| Regulatory asset amortization | | | 7.1 | | | | 6.8 | | | | 6.7 | |
| | | | | | | | | | | | | |
| Net periodic other postretirement benefit expense | | $ | 16.2 | | | $ | 17.8 | | | $ | 19.6 | |
| | | | | | | | | | | | | |
Net periodic pension expense (income)for 2005 includes a $17.1 million reduction to expense to record the cumulative impact of a correction of an error determined to have occurred in 2003 and 2004. The error was associated with our third-party actuarial computation of annualnet periodic pension expensewhich resulted from the identification of errors in certain Transco participant data involving annuity contract information utilized for 2003 and 2004. The adjustment is reflected as $16.1 million withinrecognized net actuarial (gain) lossand $1.0 million withinregulatory asset amortization (deferral).
The differences in the amount of actuarially determinednet periodic benefit expensefor our other postretirement benefit expenseplans and the other postretirement benefit costs recovered in rates for our FERC-regulated gas pipelines are deferred as a regulatory asset or liability. At December 31, 2006,2008, we have anet regulatory assetassets of $8.5$26 million for Transco and a regulatory liability of $13.3 million for Northwest Pipeline related to these deferrals. Atat December 31, 2005,2007, we had anet regulatory assetliabilities of $24.3$28 million for Transco and a regulatory liability of $10.8 million at Northwest Pipeline related to these deferrals. These amounts will be reflected in future rates based on Transco and Northwest Pipeline’sthe gas pipelines’ rate structures.
Key Assumptions
The weighted-average assumptions utilized to determine benefit obligations as of December 31, 2006,2008, and 2005,2007, are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Other
| | | | | Other
| |
| | | | | Postretirement
| | | | | Postretirement
| |
| | | Pension Benefits | | Benefits | | | Pension Benefits | | Benefits | |
| | | 2006 | | 2005 | | 2006 | | 2005 | | | 2008 | | 2007 | | 2008 | | 2007 | |
| |
| Discount rate | | | 5.80 | % | | | 5.65 | % | | | 5.80 | % | | | 5.60 | % | | | 6.08 | % | | | 6.41 | % | | | 6.00 | % | | | 6.40 | % |
| Rate of compensation increase | | | 5.00 | | | | 5.00 | | | | N/A | | | | N/A | | | | 5.00 | | | | 5.00 | | | | N/A | | | | N/A | |
The weighted-average assumptions utilized to determinenet periodic pension and other postretirement benefit expensefor the years ended December 31, 2006, 2005,2008, 2007, and 2004,2006, are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Other | | | | | Other
| |
| | | Pension Benefits | | Postretirement Benefits | | | Pension Benefits | | Postretirement Benefits | |
| | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | | 2008 | | 2007 | | 2006 | |
| |
| Discount rate | | | 5.65 | % | | | 5.86 | % | | | 6.25 | % | | | 5.60 | % | | | 5.63 | % | | | 6.25 | % | | | 6.41 | % | | | 5.80 | % | | | 5.65 | % | | | 6.40 | % | | | 5.80 | % | | | 5.60 | % |
| Expected long-term rate of return on plan assets | | | 7.75 | | | | 8.50 | | | | 8.50 | | | | 6.95 | | | | 7.45 | | | | 8.50 | | | | 7.75 | | | | 7.75 | | | | 7.75 | | | | 7.00 | | | | 6.97 | | | | 6.95 | |
| Rate of compensation increase | | | 5.00 | | | | 5.00 | | | | 5.00 | | | | N/A | | | | N/A | | | | N/A | | | | 5.00 | | | | 5.00 | | | | 5.00 | | | | N/A | | | | N/A | | | | N/A | |
110
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The discount rates for our pension and other postretirement benefit plans were determined separately based on an approach specific to our plans and their respective expected benefit cash flows. With the assistance of our third-party actuary, the plans were analyzed andplans. The year-end discount rates based onwere determined considering a yield curve comprised of high-quality corporate bonds published by a large securities firm were matched to a highly correlated published index of high-quality corporate bonds. Based on an analysis performed between eachand the timing of the plans’ yield curve discount rates and the index, a formula was developed to determine the December 31, 2006, discount rates based upon the year-end published index.expected benefit cash flows of each plan.
The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy Statement, and the capital market projections provided by our independent investment consultant for the asset classifications in which the portfolio is invested and the target weightings of each asset classification.
The expected return on plan assets component ofnet periodic benefit expenseis calculated using the market-related value of plan assets. For assets held in our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect amortization of gains or losses associated with the difference between the expected return on plan assets and the actual return on plan assets over a five-year period. The market-related value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.
The mortality assumptions used to determine the obligations for our pension and other postretirement benefit plans are related to the experience of the plans and to our third-party actuary’sthe best estimate of expected plan mortality. The selected mortality tables are among the most recent tables available.
107
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The assumed health care cost trend rate for 20072009 is 9.38.6 percent, and systematically decreases to 5.55.1 percent by 2013.2018. The health care cost trend rate assumption has a significant effect on the amounts reported. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
| | | | | | | | | | | | | | | | | |
| | | Point increase | | Point decrease | | | Point increase | | Point decrease | |
| | | (Millions) | | | (Millions) | |
| |
| Effect on total of service and interest cost components | | $ | 3.3 | | | $ | (4.1 | ) | | $ | 3 | | | $ | (4 | ) |
| Effect on postretirement benefit obligation | | | 60.5 | | | | (48.1 | ) | |
| Effect on other postretirement benefit obligation | | | | 53 | | | | (42 | ) |
Medicare Prescription Drug Act
In December 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. The Act introduced a prescription drug benefit under Medicare (Medicare Part D) beginning in 2006 as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Our health care plans for retirees include prescription drug coverage. Prior to 2005, our plans were amended to coordinate and pay secondary to any part of Medicare, including prescription drug benefits covered by Medicare Part D, which resulted in a decrease in the benefit obligation of $75.5 million. Beginning in 2005, the net reduction to the obligation was being amortized over approximately seven years which was the participants’ average remaining years of service to full eligibility for benefits. It is reflected in theamortization of prior service creditin the table of components ofnet periodic other postretirement benefit expensefor 2005.
Due to anticipated difficulties to administer our plans as previously amended to coordinate and pay secondary to Medicare Part D in 2006, we amended our plans in June 2005 to generally provide primary prescription drug coverage and apply for the federal subsidy in 2006. As a result of the amendment, generally our plans are designed to be actuarially equivalent to the standard coverage under Medicare Part D. The amendment increased our benefit obligation by $51.2 million at June 30, 2005, and is reflected as aplan amendmentin the table of changes in benefit obligation for 2005. Beginning in the third quarter of 2005, the increase to the obligation is being amortized over the participants’ average remaining years of service to full eligibility for benefits, which is approximately seven years.Net periodic other postretirement benefit expensefor 2005, reflects an increase of $7.1 million, including an increase inrecognized net actuarial lossof $.3 million, an increase inservice costof $.3 million, an increase ininterest costof $2.6 million, and an increase inamortization of prior service creditof $3.9 million, resulting from the plan amendment. We are continuing to evaluate coordination with Medicare Part D as a strategy to decrease our benefit obligation in the future and will closely monitor the development of systems and capabilities of third-party administrators to coordinate prescription drug benefits with the Centers for Medicare & Medicaid Services.
111
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Plan Assets
The investment policy for our pension and other postretirement benefit plans articulates an investment philosophy in accordance with ERISA, which governs the investment of the assets in a diversified portfolio. The investment strategy for the assets of the pension plans and approximately one half of the assets of the other postretirement benefit plans include maximizing returns with reasonable and prudent levels of risk. The investment returns on the approximate one half of remaining assets of the other postretirement benefit plans is subject to federal income tax,tax; therefore, the investment strategy also includes investing in a tax efficient manner.
The following table presents the weighted-average asset allocations at December 31, 2006,2008, and 20052007 and target asset allocationallocations at December 31, 2006,2008, by asset category.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Other
| | | | | Other
| |
| | | Pension Benefits | | Postretirement Benefits | | | Pension Benefits | | Postretirement Benefits | |
| | | 2006 | | 2005 | | Target | | 2006 | | 2005 | | Target | | | 2008 | | 2007 | | Target | | 2008 | | 2007 | | Target | |
| |
| Equity securities | | | 82 | % | | | 81 | % | | | 84 | % | | | 77 | % | | | 78 | % | | | 80 | % | | | 78 | % | | | 84 | % | | | 84 | % | | | 71 | % | | | 79 | % | | | 80 | % |
| Debt securities | | | 12 | | | | 13 | | | | 16 | | | | 12 | | | | 13 | | | | 20 | | | | 17 | | | | 12 | | | | 16 | | | | 17 | | | | 12 | | | | 20 | |
| Other | | | 6 | | | | 6 | | | | — | | | | 11 | | | | 9 | | | | — | | | | 5 | | | | 4 | | | | — | | | | 12 | | | | 9 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Included in equity securities are investments in commingled funds that invest entirely in equity securities and comprise 3824 percent at December 31, 2008, and 3740 percent at December 31, 2007, of the pension plans’ weighted-average assets, and 13 percent at December 31, 2006,2008, and 2005, respectively, and 2729 percent and 26 percentat December 31, 2007, of the other postretirement benefit plans’ weighted-average assets at December 31, 2006,assets. During 2008, a commingled fund held within the pension plans and 2005, respectively.the other postretirement benefit plans was replaced with direct investments in certain equity securities. Other assets are comprised primarily of cash and cash equivalents for the pension plans and other postretirement benefit plans.equivalents.
The assets are invested in accordance with the target allocations identified in the previous table. The investment policy provides for minimum and maximum ranges for the broad asset classes in the previous table. Additional target allocations are identified for specific classes of equity securities. The asset allocation ranges established by the investment policy are based upon a long-term investment perspective. The ranges are more heavily weighted toward equity securities since the liabilities of the pension and other postretirement benefit plans are long-term in nature and historically equity securities have significantly outperformed other asset classes over long periods of time. In December 2008, the Investment Committee voted to increase the percentage of assets allocated to debt securities and cash and cash equivalents, included within the other category in the previous table, to approximately30-35 percent, as allowed in the investment policy. The reallocation is expected to be completed during the first quarter of 2009. The Investment Committee monitors the markets and asset allocations and at any time may adjust the allocation to debt securities and cash and cash equivalents downward, closer to the target asset allocation shown in the previous table.
Equity security investments are restricted to high-quality, readily marketable securities that are actively traded on the major U.S. and foreign national exchanges. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled investment
108
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
vehicle in which the pension plans’ trust invests. No more than five percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation. The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions or other leveraging strategies. Investment strategies using options or futures are also not authorized.
Debt security investments are restricted to high-quality, marketable securities that include U.S. Treasury, federal agencies and U.S. Government guaranteed obligations, and investment grade corporate issues. The overall rating of the debt security assets is required to be at least “A”, according to the Moody’s or Standard & Poor’s rating system. No more than five percent of the total portfolio at the time of purchase may be invested in the debt securities of any one issuer. U.S. Government guaranteed and agency securities are exempt from this provision.
During 2006,2008, 11 active investment managers and one passive investment manager managed substantially all of the pension and other postretirement benefit plans’ funds, eachfunds. Each of whomthe managers had responsibility for managing a specific portion of these assets.
112
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Periodically, an asset and liability study is performed to determine the optimal asset mix to meet future benefit obligations. The most recent pension asset and liability study was performed in 2001.
Plan Benefit Payments and Employer Contributions
The followingFollowing are the expected benefits to be paid by the planplans and the expected federal prescription drug subsidy to be received in the next ten years. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Federal
| | | | | | | Federal
| |
| | | | | Other
| | Prescription
| | | | | Other
| | Prescription
| |
| | | Pension
| | Postretirement
| | Drug
| | | Pension
| | Postretirement
| | Drug
| |
| | | Benefits | | Benefits | | Subsidy | | | Benefits | | Benefits | | Subsidy | |
| | | | | (Millions) | | | | | (Millions) | |
| |
| 2007 | | $ | 45.5 | | | $ | 21.3 | | | $ | (2.0 | ) | |
| 2008 | | | 39.6 | | | | 21.9 | | | | (1.9 | ) | |
| 2009 | | | 35.7 | | | | 22.2 | | | | (2.1 | ) | | $ | 44 | | | $ | 17 | | | $ | (2 | ) |
| 2010 | | | 33.7 | | | | 22.3 | | | | (2.2 | ) | | | 38 | | | | 18 | | | | (2 | ) |
| 2011 | | | 34.5 | | | | 21.5 | | | | (2.3 | ) | | | 38 | | | | 18 | | | | (2 | ) |
| 2012-2016 | | | 240.3 | | | | 105.8 | | | | (13.4 | ) | |
| 2012 | | | | 42 | | | | 18 | | | | (2 | ) |
| 2013 | | | | 42 | | | | 18 | | | | (2 | ) |
| 2014 - 2018 | | | | 263 | | | | 96 | | | | (13 | ) |
We expect to contribute approximately $41$61 million to our pension plans and approximately $16 million to our other postretirement benefit plans in 2007.2009.
Defined Contribution Plans
We also maintain defined contribution plans for the benefit of substantially all of our employees. Generally, plan participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the plan’splans’ guidelines. We match employees’ contributions up to certain limits. Costs recognized for these plansOur matching contributions charged to expense were $18.7$24 million, $22 million, and $19 million in 2008, 2007, and 2006, $16.8 million in 2005, and $16.9 million in 2004. Onerespectively. A fund within one of our defined contribution plans was amended as of July 1, 2005, to convert one of the funds within the plan tois a nonleveraged employee stock ownership plan (ESOP). The 2005 compensation cost related to the ESOP of $.7 million is included in the $16.8 million of contributions, previously mentioned above, and represents the contribution made in consideration for employee services rendered in 2005. It is measured by the amount of cash contributed to the ESOP. The shares held by the ESOP are treated as outstanding when computing earnings per share and the dividends on the shares held by the ESOP are recorded as a component of retained earnings. ForSince 2006 and future years, there arehave been no contributions to this ESOP, other than dividend reinvestment, as contributions for purchase of our stock is now restrictedare no longer allowed within this defined contribution plan.
Inventoriesat December 31, 2006, and 2005, are as follows:
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| | | (Millions) | |
| |
| Natural gas liquids | | $ | 77.9 | | | $ | 100.0 | |
| Natural gas in underground storage | | | 77.6 | | | | 90.4 | |
| Materials, supplies and other | | | 85.9 | | | | 82.2 | |
| | | | | | | | | |
| | | $ | 241.4 | | | $ | 272.6 | |
| | | | | | | | | |
113109
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Inventoriesdetermined using the LIFO cost method were approximately 11 percent and 8 percent ofinventoriesat December 31, 20062008, and 2005, respectively. The remaining2007, are as follows:
| | | | | | | | | |
| | | 2008 | | | 2007 | |
| | | (Millions) | |
| |
| Natural gas liquids | | $ | 56 | | | $ | 66 | |
| Natural gas in underground storage | | | 97 | | | | 45 | |
| Materials, supplies and other | | | 107 | | | | 98 | |
| | | | | | | | | |
| | | $ | 260 | | | $ | 209 | |
| | | | | | | | | |
inventoriesInventorieswereare primarily determined using the average-cost method.
Ifinventoriesvalued using the LIFO cost method at December 31, 2006 and 2005, were valued at current replacement cost, the amounts would increase by $22 million and $59 million, respectively.
Natural gas in underground storagereflects a $32.1 million charge recorded in 2005 for prior period accounting and valuation corrections.
| |
| Note 9. | Property, Plant and Equipment |
Property, plant and equipment — netat December 31, 2006,2008 and 2005,2007, is as follows:
| | | | | | | | | |
| | | 2006 | | | 2005 | |
| | | (Millions) | |
| |
| Cost: | | | | | | | | |
| Exploration & Production | | $ | 5,918.2 | | | $ | 4,458.9 | |
| Gas Pipeline | | | 9,127.3 | | | | 8,371.1 | |
| Midstream Gas & Liquids(1) | | | 4,545.5 | | | | 4,351.4 | |
| Power | | | 155.3 | | | | 154.9 | |
| Other | | | 245.6 | | | | 235.5 | |
| | | | | | | | | |
| | | | 19,991.9 | | | | 17,571.8 | |
| Accumulated depreciation, depletion and amortization | | | (5,811.2 | ) | | | (5,162.6 | ) |
| | | | | | | | | |
| | | $ | 14,180.7 | | | $ | 12,409.2 | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | Estimated
| | | Depreciation
| | | | | | | |
| | | Useful Life(b)
| | | Rates(b)
| | | | | | | |
| | | (Years) | | | (%) | | | 2008 | | | 2007 | |
| | | | | | | | | (Millions) | |
| |
| Nonregulated | | | | | | | | | | | | | | | | |
| Oil and gas properties | | | (a) | | | | | | | $ | 8,749 | | | $ | 6,844 | |
| Natural gas gathering and processing facilities | | | 3 - 40 | | | | | | | | 5,394 | | | | 4,781 | |
| Construction in progress | | | (d) | | | | | | | | 1,169 | | | | 908 | |
| Other(c) | | | 2 - 45 | | | | | | | | 770 | | | | 702 | |
| Regulated | | | | | | | | | | | | | | | | |
| Natural gas transmission facilities | | | | | | | .01 - 7.25 | | | | 8,441 | | | | 8,208 | |
| Construction in progress | | | | | | | (d) | | | | 120 | | | | 72 | |
| Other | | | | | | | .01 - 50 | | | | 1,293 | | | | 1,272 | |
| | | | | | | | | | | | | | | | | |
| Total property, plant and equipment, at cost | | | | | | | | | | | 25,936 | | | | 22,787 | |
| Accumulated depreciation, depletion & amortization | | | | | | | | | | | (7,871 | ) | | | (6,806 | ) |
| | | | | | | | | | | | | | | | | |
| Property, plant and equipment — net | | | | | | | | | | $ | 18,065 | | | $ | 15,981 | |
| | | | | | | | | | | | | | | | | |
| | |
(1)(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. (SeeSee Note 11.)11 of Notes to Consolidated Financial Statements. |
|
| (d) | | Construction in progress balances not yet subject to depreciation. |
Depreciation, depletion and amortizationexpense forproperty, plant and equipment — netwas $865.1$1.3 billion in 2008, $1.1 billion in 2007, and $863 million in 2006, $739 million in 2005, and $667.4 million in 2004.2006.
Property,Regulated property, plant and equipment — netincludes approximately $685 million at December 31, 2006, and $374 million at December 31, 2005, of construction in progress which is not yet subject to depreciation. In addition, property of Exploration & Production includes approximately $414 million at December 31, 2006, and $443 million at December 31, 2005, of capitalized costs related to properties with unproven reserves not yet subject to depletion.
Property, plant and equipment — netincludes approximately $1.1 billion at December 31, 2006,2008 and $1.2 billion at December 31, 2005,2007 related to amounts in excess of the original cost of the regulated facilities within Gas Pipeline as a result of our prior
110
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.
Asset Retirement Obligations
In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143.” The Interpretation clarifies that the term “conditional asset retirement” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform anOur asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
114
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
We adopted the Interpretation on December 31, 2005. In accordance with the Interpretation, we estimated future retirement obligations for certain assets previously considered to have an indeterminate life. As a result, we recorded an increase inother liabilities and deferred incomeof $29.4 million, an increase inproperty, plant and equipment — netof $12.2 million, and acumulative effect of change in accounting principleof $1.7 million (net of $1.0 million of taxes). We also recorded a $14.5 million regulatory asset inother assets and deferred chargesfor retirement costs expected to be recovered through regulated rates. Had we implemented the Interpretation at the beginning of 2003, the financial statement impact at December 31, 2004 would not be substantially different than the impact at December 31, 2005.
The asset retirement obligation at December 31, 20062008 and 2005 is $3332007 are $644 million and $93$399 million, respectively. The increaseincreases in the obligationobligations in 2006 is2008 are primarily due primarily to obtaining additional information that revisedrevisions in our estimation of our asset retirement obligation for certain assetsobligations in our Midstream and Gas Pipeline segments and increased asset additions in our Exploration &and Production Gas Pipeline and Midstream segments. Factors affected by the additional information included estimated settlement dates, estimated settlement costs and inflation rates.segment.
The accrued obligations relate to producing wells, underground storage caverns, offshore platforms, fractionation facilities, gas gathering well connections and pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug both producing wells and storage caverns and remove any related surface equipment, remove surface equipment and restore land at fractionation facilities, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
SFAS No. 143 requires measurements of asset retirement obligations to include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. We have no examples of credit-worthy third parties in the energy industry who are willing to assume this type of risk for a determinable price. Therefore, because we cannot reasonably estimate such a market-risk premium, we excluded it from our estimates of ARO liabilities.
Pursuant to its 2008 rate case settlement, Transco deposits a portion of its collected rates into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations. Transco is also required to make annual deposits into the trust through 2012. The trust is reported as a component ofother assets and deferred chargesand has a carrying value of $13 million as of December 31, 2008.
| |
| Note 10. | Accounts Payable and Accrued Liabilities |
Under our cash-management system, certain cash accounts reflected negative balances to the extent checks written have not been presented for payment. These negative balances represent obligations and have been reclassified toaccounts payable.Accounts payableincludes approximately $44$95 million of these negative balances at December 31, 2006,2008, and $69$96 million at December 31, 2005.
On May 26, 2004, we were released from certain historical indemnities, primarily related to environmental remediation, for an agreement to pay $117.5 million. We had previously deferred $113 million of a gain on sale related to these indemnities. At the date of sale, the deferred revenue and identified obligations related to the indemnities totaled $102 million. The carrying value of this obligation is $33.9 million at December 31, 2006, and $51.3 million at December 31, 2005. The obligation will be settled with a payment of $35 million on July 1, 2007.
Accrued liabilitiesat December 31, 2006,2008, and 2005,2007, are as follows:
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Millions) | | | (Millions) | |
| |
| Taxes other than income taxes | | | $ | 223 | | | $ | 169 | |
| Interest | | $ | 243.3 | | | $ | 245.0 | | | | 185 | | | | 208 | |
| Employee costs | | | 165.8 | | | | 147.2 | | | | 168 | | | | 174 | |
| Taxes other than income taxes | | | 151.9 | | | | 141.4 | | |
| Accrual for Gulf Liquids litigation contingency | | | 94.7 | * | | | — | | |
| Income taxes | | | 80.8 | | | | 58.2 | | | | 165 | | | | 75 | |
| Accrual for Power litigation contingencies | | | 43.4 | | | | 52.2 | | |
| Accrual for Gulf Liquids litigation contingency* | | | | 51 | | | | 94 | |
| Guarantees and payment obligations related to WilTel | | | 41.1 | | | | 42.7 | | | | 38 | | | | 39 | |
| Structured indemnity settlement | | | 33.9 | | | | 19.4 | | |
| Other | | | 386.5 | | | | 417.0 | | |
| Estimated rate refund liability | | | | 14 | | | | 96 | |
| Other, including other loss contingencies | | | | 326 | | | | 303 | |
| | | | | | | | | | | |
| | | $ | 1,241.4 | | | $ | 1,123.1 | | | $ | 1,170 | | | $ | 1,158 | |
| | | | | | | | | | | |
| | |
| * | | Includes $22interest of $14 million of interestin 2008 and $25 million in 2007. |
115111
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| Note 11. | Debt, Leases and Banking Arrangements |
Long-Term Debt
Long-term debtat December 31, 20062008 and 2005,2007, is:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Weighted-
| | | | | | | Weighted-
| | | | | |
| | | Average
| | | | | | | Average
| | | | | |
| | | Interest
| | December 31, | | | Interest
| | December 31, | |
| | | Rate(1) | | 2006 | | 2005 | | | Rate(1) | | 2008(2) | | 2007 | |
| | | | | (Millions) | | | | | (Millions) | |
| |
Secured(2)(3) | | | | | | | | | | | | | | | | | | | | | | | | |
| 6.62%-9.45%, payable through 2016 | | | 8.0 | % | | $ | 171.7 | | | $ | 195.7 | | | | 8.0 | % | | $ | 123 | | | $ | 148 | |
| Adjustable rate, payable through 2016 | | | 6.2 | % | | | 74.4 | | | | 572.2 | | | | 3.9 | % | | | 54 | | | | 64 | |
| Capital lease obligations | | | 9.3 | % | | | 2.5 | | | | 2.8 | | | | 6.0 | % | | | 5 | | | | 10 | |
| Unsecured | | | | | | | | | | | | | | | | | | | | | | | | |
5.5%-10.25%, payable through 2033 | | | 7.6 | % | | | 7,690.4 | | | | 6,867.3 | | | | 7.6 | % | | | 7,447 | | | | 7,103 | |
| Adjustable rate, due 2008 | | | 6.7 | % | | | 75.0 | | | | 75.0 | | |
| Other, payable through 2007 | | | 6.0 | % | | | .1 | | | | .1 | | |
| Revolving credit loans | | | | — | | | | — | | | | 250 | |
| Adjustable rate, payable through 2012 | | | | 1.2 | % | | | 250 | | | | 325 | |
| | | | | | | | | | | |
| Total long-term debt, including current portion | | | | | | | 8,014.1 | | | | 7,713.1 | | | | | | | | 7,879 | | | | 7,900 | |
| Long-term debt due within one year | | | | | | | (392.1 | ) | | | (122.6 | ) | | | | | | | (196 | ) | | | (143 | ) |
| | | | | | | | | | | |
| Long-term debt | | | | | | $ | 7,622.0 | | | $ | 7,590.5 | | | | | | | $ | 7,683 | | | $ | 7,757 | |
| | | | | | | | | | | |
| | |
| (1) | | At December 31, 2006.2008. |
| |
| (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 $246.1$177 million and $212 million at December 31, 2006,2008 and 2007, respectively, collateralized by certain fixed assets of two of our Venezuelan subsidiaries with a net book value of $380$324 million and $351 million at December 31, 2006.2008 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 Transco’s $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. |
Revolving credit and letter of credit facilities (credit facilities)
In May 2006, we obtainedWe have an unsecured, three-year, $1.5 billion revolving credit facility replacing our $1.275 billion secured revolving credit facility. The new unsecured facility contains similar terms and financial covenants as the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt and sale-leaseback transactions. The facility is guaranteed by Williams Gas Pipeline Company, LLC and we guarantee obligationswith a maturity date of Williams Partners L.P. for up to $75 million.May 1, 2012. Northwest Pipeline and Transco each have access to $400 million and Williams Partners L.P. has access to $75 million under the credit facility to the extent not otherwise utilized by us. Lehman Commercial Paper Inc., which is committed to fund up to $70 million of our $1.5 billion credit facility, filed for bankruptcy in 2008. We expect that our ability to borrow under the credit facility is reduced by this committed amount. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by the above. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin. We are required to pay a commitment fee (currently .25 percent annually)0.125 percent) based on the unused portion of the credit facility.
112
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the credit agreement include the following:
| | |
| | • | Our ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2006,2008, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, is approximately 5340 percent. |
| |
| | • | Ratio of debt to capitalization must be no greater than 55 percent for Northwest Pipeline and Transco. At December 31, 2006, we2008, they are in compliance with this covenant as ourtheir ratio of debt to capitalization, as calculated under this covenant, is approximately 4436 percent for Northwest Pipeline and 3226 percent for Transco. |
116
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
| • | Our ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement. Through December 31, 2006, we are in compliance with this covenant as we exceed the compliance level by approximately 50 percent. |
Our $500We have unsecured $400 million, $100 million and $700 million credit facilities. The $400 million credit facility matures in April 2009, the $100 million credit facility matures in May 2009 and the $700 million credit facility matures in September 2010. These credit facilities provide for both borrowings and issuing letters of credit but are expected to be used primarily for issuing letters of credit. We are required to pay the funding bank fixed fees at a weighted-average interest rate of 3.64 percent, 3.64 percent and 2.29 percent for the $500$400 million, $100 million and $700 million credit facilities, respectively, on the total committed amount of the facilities. In addition, we pay interest on any borrowings at a fluctuating rate comprised of either a base rate or LIBOR.
The funding bank, an affiliate of Citibank N.A., syndicated its associated credit risk through a private offering that allows for the resale of certain restricted securities to qualified institutional buyers. To facilitate the syndication of these credit facilities, the bank established trusts funded by the institutional investors. The assets of the trusts serve as collateral to reimburse the bank for our borrowings in the event that the credit facilities are delivered to the investors as described below. Thus, we have no asset securitization or collateral requirements under the credit facilities. Upon the occurrence of certain credit events, letters of credit under the agreement become cash collateralized creating a borrowing under the credit facilities. Concurrently, the funding bank can deliver the credit facilities to the institutional investors, whereby the investors replace the funding bank as lender under the credit facilities. Upon such occurrence, we will pay:
| | | | | | | | | | | | | | | | | |
| | | $500 Million Facility | | | $700 Million Facility | |
| | | $400 million | | | $100 million | | | $500 million | | | $200 million | |
| |
| Interest Rate | | | 3.57 percent | | | | LIBOR | | | | 4.35 percent | | | | LIBOR | |
| Facility Fixed Fee | | 3.19 percent | | 2.29 percent |
Williams Partners L.P. has an unsecured $450 million credit facility with a maturity date of December 2012. This $450 million credit facility is comprised initially of a $200 million credit facility available for borrowings and letters of credit and a $250 million term loan. Under certain conditions, the credit facility may be increased up to an additional $100 million. The parent company and certain affiliates of Lehman Brothers Commercial Bank, who is committed to fund up to $12 million of this credit facility, filed for bankruptcy in 2008. They expect that their ability to borrow under this credit facility is reduced by this committed amount. The committed amounts of the other participating banks under this agreement remain in effect and are not impacted by this reduction. Interest on borrowings under this agreement will be payable at rates per annum equal to either (1) a fluctuating base rate equal to the lender’s prime rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. At December 31, 2006,2008, they had a $250 million term loan outstanding and no loans areamounts outstanding under ourthe $200 million credit facilities. Letters offacility. Significant financial covenants under this credit issued under our credit facilities are:
| | | | | |
| | | Letters of Credit at
| |
| | | December 31, 2006 | |
| | | (Millions) | |
| |
| $500 million unsecured credit facilities | | $ | 370.1 | |
| $700 million unsecured credit facilities | | $ | 525.0 | |
| $1.5 billion unsecured credit facility | | $ | 28.8 | |
agreement include the following:
Exploration & Production’s Credit Agreement
Exploration & Production has recently entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Margin requirements, if any, under this new facility are dependent on the level of hedging and on natural gas reserves value.
Issuances and retirements
On May 28, 2003, we issued $300 million of 5.5 percent junior subordinated convertible debentures due 2033. These notes, which are callable after seven years, are convertible at the option of the holder into our common stock at a conversion price of approximately $10.89 per share. In November 2005, we initiated an offer to convert these debentures to shares of our common stock. In January 2006, we converted approximately $220.2 million of the debentures. (See Note 12.)
In April 2006, Transco issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
| | |
| • | 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. |
117113
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.
In June 2006, Northwest Pipeline
| | |
| • | 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. |
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.
At December 31, 2008, no loans are outstanding under our credit facilities. Letters of credit issued $175under our credit facilities are:
| | | | | |
| | | Letters of Credit at
| |
| | | December 31, 2008 | |
| | | (Millions) | |
| |
| $500 million unsecured credit facilities | | $ | — | |
| $700 million unsecured credit facilities | | $ | 220 | |
| $1.5 billion unsecured credit facility | | $ | 71 | |
Exploration & Production’s credit agreement
Exploration & Production has an unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. The agreement extends through December 2013. Under the credit agreement, Exploration & Production is not required to post collateral as long as the value of its domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money positions on hedges entered into under the credit agreement. Exploration & Production is subject to additional covenants under the credit agreement including restrictions on hedge limits, the creation of liens, the incurrence of debt, the sale of assets and properties, and making certain payments, such as dividends, under certain circumstances.
Issuances and retirements
On January 15, 2008, Transco retired $100 million of 6.25 percent senior unsecured notes due January 15, 2008, with proceeds borrowed under our $1.5 billion unsecured credit facility.
On April 15, 2008, Transco retired a $75 million adjustable rate unsecured note due April 15, 2008, with proceeds borrowed under our $1.5 billion unsecured credit facility.
On May 22, 2008, Transco issued $250 million aggregate principal amount of 76.05 percent senior unsecured notes due 20162018 to certain institutional investors in a Rule 144A private debt placement. A portion of these proceeds was used to repay Transco’s $100 million and $75 million loans from January 2008 and April 2008, respectively, under our $1.5 billion unsecured credit facility. In October 2006,September 2008, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
On May 22, 2008, Northwest Pipeline issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement. These proceeds were used to repay Northwest Pipeline’s $250 million loan from December 2007 under our $1.5 billion unsecured credit facility. In September 2008, Northwest Pipeline completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
114
In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. 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 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of 7.25 percent senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Aggregate minimum maturities oflong-term debt(excluding capital leases and unamortized discount and premium) for each of the next five years are as follows:
| | | | | |
| | | (Millions) | |
| |
| 2007 | | $ | 391.4 | |
| 2008 | | | 238.0 | |
| 2009 | | | 53.1 | |
| 2010 | | | 217.3 | |
| 2011 | | | 1,168.0 | |
| | | | | |
| | | (Millions) | |
| |
| 2009(1) | | $ | 192 | |
| 2010 | | | — | |
| 2011 | | | 927 | |
| 2012 | | | 1,203 | |
| 2013 | | | — | |
| | |
| (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. |
Cash payments for interest (net of amounts capitalized) were as follows: 2008 — $592 million; 2007 — $634 million; and 2006 — $611 million; 2005 — $625 million; and 2004 — $849 million.
Leases-Lessee
Future minimum annual rentals under noncancelable operating leases as of December 31, 2006,2008, are payable as follows:
| | | | | | | | | |
| | | (Millions) | | | (Millions) | |
| |
| 2007 | | $ | 225.4 | | |
| 2008 | | | 227.0 | | |
| 2009 | | | 205.9 | | | $ | 69 | |
| 2010 | | | 185.8 | | | | 53 | |
| 2011 | | | 179.8 | | | | 26 | |
| 2012 | | | | 23 | |
| 2013 | | | | 19 | |
| Thereafter | | | 1,120.9 | | | | 45 | |
| | | | | | | |
| Total | | $ | 2,144.8 | | | $ | 235 | |
| | | | | | | |
The above amounts include obligations of approximately $1.9 billion related to a tolling agreement at Power that is accounted for as an operating lease as a result of changes to the contract terms in 2004 after implementation of EITF01-8. (See Note 1.) Under the tolling agreement, Power has the exclusive right to capacity and fuel conversion services as well as ancillary services associated with electric generation facilities that are currently in
118
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
operation in southern California. Current annual rentals under this tolling agreement range from approximately $157 million to $169 million through 2017, with approximately $70 million remaining to be paid in 2018. Certain transactions resulting from the tolling agreements are accounted for as operating subleases. Total rentals to be received from these operating subleases are approximately $1.1 billion with approximately 4 years remaining on the agreements as of December 31, 2006.
Total rent expense was $242$87 million in 2006, $2262008 and $68 million in 20052007 and $206 million in 2004.2006. Rent expense at Power,reported as discontinued operations, primarily related to thea tolling agreement, was $148 million and $175 million (including $11 million of contingent rentals) in 2007 and 2006, and $161 million (including ($1) million of contingent rentals)respectively. Rent expense in 2005. Power’s rent expensediscontinued operations was offset by approximately $276 million in 2007 and $264 million (including $8 million of contingent rental income) in 2006 and $172 million (including $7 million of contingent rental income) in 2005 resulting from sales and other transactions made possible by the tolling agreement. Contingent rentals are primarily based on utilization of the leased property or changesThis tolling agreement was included in the capacity and availabilitysale of theour power generating facility.business in 2007. (See Note 2.)
| |
| Note 12. | Stockholders’ Equity |
In July 2007, our Board of Directors authorized the repurchase of up to $1 billion of our common stock. During 2007, we purchased 16 million shares for $526 million (including transaction costs) at an average cost of $33.08 per share. During 2008, we purchased 13 million shares of our common stock for $474 million (including transaction costs) at an average cost of $36.76 per share. We completed our $1 billion stock repurchase program in July 2008. Our overall average cost per share was $34.74. This stock repurchase is recorded intreasury stockon our Consolidated Balance Sheet.
In November 2005, we initiated an offer to convert our 5.5 percent junior subordinated convertible debentures into our common stock. In January 2006, we converted approximately $220.2$220 million of the debentures in exchange for 20.220 million
115
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
shares of common stock, a $26 million cash premium, and $2 million of accrued interest. During 2008, $27 million of debentures were exchanged for 2 million shares of common stock. At December 31, 2008, approximately $53 million of 5.5 percent junior subordinated convertible debentures, convertible into approximately 5 million shares of common stock, are outstanding.
At December 31, 2007, we held all of Williams Partners L.P.’s seven million subordinated units outstanding. In February 2008, these subordinated units were converted into common units of Williams Partners L.P. due to the achievement of certain financial targets that resulted in the early termination of the subordination period. While these subordinated units were outstanding, other issuances of partnership units by Williams Partners L.P. had preferential rights and the proceeds from these issuances in excess of the book basis of assets acquired by Williams Partners L.P. were therefore reflected as minority interest on our Consolidated Balance Sheet rather than as equity. Due to the conversion of the subordinated units, these original issuances of partnership units no longer have preferential rights and now represent the lowest level of equity securities issued by Williams Partners L.P. In accordance with our policy regarding the issuance of equity of a $25.8 million cash premium,consolidated subsidiary, such issuances of nonpreferential equity are accounted for as capital transactions and $1.5 millionno gain or loss is recognized. Therefore, as a result of accrued interest.the first-quarter conversion, we recognized a decrease to minority interest and a corresponding increase to stockholders’ equity of approximately $1.2 billion.
We maintain a Stockholder Rights Plan, as amended and restated on September 21, 2004, and further amended May 18, 2007, and October 12, 2007, under which each outstanding share of our common stock has a right (as defined in the plan) attached. Under certain conditions, each right may be exercised to purchase, at an exercise price of $50 (subject to adjustment), one two-hundredth of a share of Series A Junior Participating Preferred Stock. The rights may be exercised only if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or more of our common stock or commences an offer for 15 percent or more of our common stock. The plan contains a mechanism to divest of shares of common stock if such stock in excess of 14.9 percent was acquired inadvertently or without knowledge of the terms of the rights. The rights, which until exercised do not have voting rights, expire in 2014 and may be redeemed at a price of $.01 per right prior to their expiration, or within a specified period of time after the occurrence of certain events. In the event a person becomes the owner of more than 15 percent of our common stock, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, our common stock having a value equal to two times the exercise price of the right. In the event we are engaged in a merger, business combination, or 50 percent or more of our assets, cash flow or earnings power is sold or transferred, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the right.
| |
| Note 13. | Stock-Based Compensation |
Plan Information
The Williams Companies, Inc. 2002 Incentive Plan (the Plan) wasOn May 17, 2007, our stockholders approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004. The Plana plan that provides for common-stock-based awards to both employees and nonmanagement directors. Upon approval by the stockholders, all prior stock plans were terminated resulting in no further grants being made from those plans. However, awards outstanding in those prior plans remain in those plans with their respectiveThe plan generally contains terms and provisions.
provisions consistent with the previous plans. The Planplan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options and restricted stock units.reserves 19 million shares for issuance. Restricted stock units represent deferredare valued at market value on the grant date of the award and generally vest over three years. The purchase price per share awardsfor stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of the grant and can be subject to timeand/or performance-basedaccelerated vesting requirements. Awards may be granted for no consideration other than prior andif certain future servicesstock prices or based on certainif specific financial performance targets beingare achieved. Stock options generally expire 10 years after grant. At December 31, 2006, 41.72008, 33 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 2016 million shares were available for future grants. At December 31, 2005, 452007, 37 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 21.619 million shares were available for future grants.
119116
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorizes up to 2 million shares of our common stock to be available for sale under the plan. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of: (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the Plan was approved by the stockholders. The first offering under the ESPP commenced on October 1, 2007 and ended on December 31, 2007. Subsequent offering periods are from January through June and from July through December. Generally, all employees are eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an employee to purchase during each offering period is limited to 750 shares. The purchase price of the stock is 85 percent of the lower closing price of either the first or the last day of the offering period. The ESPP requires a one-year holding period before the stock can be sold. Employees purchased 242 thousand shares at an average price of $17.80 per share during 2008. Approximately 1.7 million and 2 million shares were available for purchase under the ESPP at December 31, 2008 and 2007, respectively .
Stock Options
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
The following summary reflects stock option activity and related information for the year ending December 31, 2006.2008.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Weighted-
| | | | | | | Weighted-
| | | |
| | | | | Average
| | Aggregate
| | | | | Average
| | Aggregate
| |
| | | | | Exercise
| | Intrinsic
| | | | | Exercise
| | Intrinsic
| |
Stock Options | | Options | | Price | | Value | | | Options | | Price | | Value | |
| | | (Millions) | | | | (Millions) | | | (Millions) | | | | (Millions) | |
| |
| Outstanding at December 31, 2005 | | | 20.4 | | | $ | 16.63 | | | | | | |
| Outstanding at December 31, 2007 | | | | 13.2 | | | $ | 16.62 | | | | | |
| Granted | | | 1.2 | | | $ | 21.66 | | | | | | | | 1.0 | | | $ | 36.50 | | | | | |
| Exercised | | | (2.9 | ) | | $ | 11.72 | | | $ | 36.4 | | | | (2.3 | ) | | $ | 14.45 | | | $ | 49 | |
| | | | | | | |
| Cancelled | | | (1.0 | ) | | $ | 32.05 | | | | | | | | (.4 | ) | | $ | 33.44 | | | | | |
| | | | | | | |
| Outstanding at December 31, 2006 | | | 17.7 | | | $ | 16.96 | | | $ | 198.7 | | |
| Outstanding at December 31, 2008 | | | | 11.5 | | | $ | 18.10 | | | $ | 35 | |
| | | | | | | | | | | | | |
| Exercisable at December 31, 2006 | | | 13.2 | | | $ | 16.90 | | | $ | 157.9 | | |
| Exercisable at December 31, 2008 | | | | 9.6 | | | $ | 15.44 | | | $ | 35 | |
| | | | | | | | | | | | | |
The total intrinsic value of options exercised during the years ended December 31, 2008, 2007, and 2006 2005, and 2004 was $36.4$49 million, $42.2$74 million, and $42.4$36 million, respectively.
The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2006.2008.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Stock Options Outstanding | | | Stock Options Exercisable | |
| | | | | | | | | Weighted-
| | | | | | | | | Weighted-
| |
| | | | | | Weighted-
| | | Average
| | | | | | Weighted-
| | | Average
| |
| | | | | | Average
| | | Remaining
| | | | | | Average
| | | Remaining
| |
| | | | | | Exercise
| | | Contractual
| | | | | | Exercise
| | | Contractual
| |
Range of Exercise Prices | | Options | | | Price | | | Life | | | Options | | | Price | | | Life | |
| | | (Millions) | | | | | | (Years) | | | (Millions) | | | | | | (Years) | |
| |
| $2.27 to $10.00 | | | 8.4 | | | $ | 7.05 | | | | 5.9 | | | | 7.1 | | | $ | 6.52 | | | | 5.7 | |
| $10.38 to $16.40 | | | .9 | | | $ | 15.43 | | | | 4.5 | | | | .9 | | | $ | 15.49 | | | | 4.5 | |
| $17.10 to $31.58 | | | 5.4 | | | $ | 21.22 | | | | 6.9 | | | | 2.2 | | | $ | 22.81 | | | | 4.7 | |
| $33.51 to $42.29 | | | 3.0 | | | $ | 37.59 | | | | 1.7 | | | | 3.0 | | | $ | 37.59 | | | | 1.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 17.7 | | | $ | 16.96 | | | | 5.4 | | | | 13.2 | | | $ | 16.90 | | | | 4.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
The estimated fair value at date of grant of options for our common stock granted in 2006, 2005, and 2004, using the Black-Scholes option pricing model, is as follows:
| | | | | | | | | | | | | |
| | | 2006 | | | 2005 | | | 2004 | |
| |
| Weighted-average grant date fair value of options for our | | | | | | | | | | | | |
| common stock granted during the year | | $ | 8.36 | | | $ | 6.70 | | | $ | 4.54 | |
| | | | | | | | | | | | | |
| Weighted-average assumptions: | | | | | | | | | | | | |
| Dividend yield | | | 1.4 | % | | | 1.6 | % | | | 0.4 | % |
| Volatility | | | 36.3 | % | | | 33.3 | % | | | 50.0 | % |
| Risk-free interest rate | | | 4.7 | % | | | 4.1 | % | | | 3.3 | % |
| Expected life (years) | | | 6.5 | | | | 6.5 | | | | 5.0 | |
120117
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Stock Options Outstanding | | | Stock Options Exercisable | |
| | | | | | | | | Weighted-
| | | | | | | | | Weighted-
| |
| | | | | | Weighted-
| | | Average
| | | | | | Weighted-
| | | Average
| |
| | | | | | Average
| | | Remaining
| | | | | | Average
| | | Remaining
| |
| | | | | | Exercise
| | | Contractual
| | | | | | Exercise
| | | Contractual
| |
Range of Exercise Prices | | Options | | | Price | | | Life | | | Options | | | Price | | | Life | |
| | | (Millions) | | | | | | (Years) | | | (Millions) | | | | | | (Years) | |
| |
| $2.27 to $12.92 | | | 4.7 | | | $ | 7.12 | | | | 4.1 | | | | 4.7 | | | $ | 7.12 | | | | 4.1 | |
| $12.93 to $23.72 | | | 3.8 | | | $ | 19.51 | | | | 6.0 | | | | 3.5 | | | $ | 19.32 | | | | 5.8 | |
| $23.73 to $34.52 | | | 1.1 | | | $ | 28.11 | | | | 7.5 | | | | .5 | | | $ | 27.79 | | | | 6.6 | |
| $34.53 to $42.29 | | | 1.9 | | | $ | 37.06 | | | | 5.4 | | | | .9 | | | $ | 37.64 | | | | 1.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 11.5 | | | $ | 18.10 | | | | 5.3 | | | | 9.6 | | | $ | 15.44 | | | | 4.6 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
The estimated fair value at date of grant of options for our common stock granted in 2008, 2007, and 2006, using the Black-Scholes option pricing model, is as follows:
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| |
| Weighted-average grant date fair value of options for our common stock granted during the year | | $ | 12.83 | | | $ | 9.09 | | | $ | 8.36 | |
| | | | | | | | | | | | | |
| Weighted-average assumptions: | | | | | | | | | | | | |
| Dividend yield | | | 1.2 | % | | | 1.5 | % | | | 1.4 | % |
| Volatility | | | 33.4 | % | | | 28.7 | % | | | 36.3 | % |
| Risk-free interest rate | | | 3.5 | % | | | 4.6 | % | | | 4.7 | % |
| Expected life (years) | | | 6.5 | | | | 6.3 | | | | 6.5 | |
The expected dividend yield is based on the average annual dividend yield as of the grant date. Expected volatility is based on the historical volatility of our stock and the implied volatility of our stock based on traded options. In calculating historical volatility, returns during calendar year 2002 were excluded as the extreme volatility during that time is not reasonably expected to be repeated in the future. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.
Cash received from stock option exercises was $34.3$32 million, $39.4$56 million and $21.6$34 million during 2006, 20052008, 2007 and 2004,2006, respectively. The tax benefit realized from stock options exercised during 2006, 20052008 was $17 million, $27 million for 2007, and 2004 was $13.9$14 million $14.2 million and $13.7 million, respectively.for 2006.
Nonvested Restricted Stock Units
Restricted stock units are generally valued at market value on the grant date of the award and generally vest over three years. Restricted stock unit expense, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2006.2008.
| | | | | | | | | |
| | | | | | Weighted-
| |
| | | | | | Average
| |
Restricted Stock Units | | Shares | | | Fair Value* | |
| | | (Millions) | | | | |
| |
| Nonvested at December 31, 2005 | | | 2.8 | | | $ | 14.60 | |
| Granted | | | 1.7 | | | $ | 23.39 | |
| Forfeited | | | (.2 | ) | | $ | 17.76 | |
| Vested | | | (.6 | ) | | $ | 11.63 | |
| | | | | | | | | |
| Nonvested at December 31, 2006 | | | 3.7 | | | $ | 20.57 | |
| | | | | | | | | |
118
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | |
| | | | | | Weighted-
| |
| | | | | | Average
| |
Restricted Stock Units | | Shares | | | Fair Value* | |
| | | (Millions) | | | | |
| |
| Nonvested at December 31, 2007 | | | 4.4 | | | $ | 27.78 | |
| Granted | | | 1.4 | | | $ | 30.13 | |
| Forfeited | | | (.2 | ) | | $ | 27.52 | |
| Vested | | | (1.2 | ) | | $ | 27.51 | |
| | | | | | | | | |
| Nonvested at December 31, 2008 | | | 4.4 | | | $ | 22.91 | |
| | | | | | | | | |
| | |
| * | | Performance-based shares are valued at theend-of-period market price until certification that the performance objectives have been completed. Upon certification, these shares are valued at that day’s end-of-period market price. All other shares are valued at the grant-date market price. |
Other restricted stock unit information
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
| Weighted-average grant date fair value of restricted stock units granted during the year, per share | | $ | 23.39 | | | $ | 19.35 | | | $ | 10.54 | | | $ | 30.13 | | | $ | 30.79 | | | $ | 23.39 | |
| | | | | | | | | | | | | | | |
| Total fair value of restricted stock units vested during the year ($’s in millions) | | $ | 14.5 | | | $ | 13.7 | | | $ | 18.6 | | | $ | 48 | | | $ | 33 | | | $ | 15 | |
| | | | | | | | | | | | | | | |
Performance-based share awards issuedshares granted under the Plan represent 3433 percent of nonvested restricted stock units outstanding at December 31, 2006.2008. These awardsgrants are generally earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based awards will begrants is recognized in future periods whenafter performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original awardgrant amount.
| |
| Note 14. | Fair Value Measurements |
Adoption of SFAS No. 157
SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. On January 1, 2008, we applied SFAS No. 157 for our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy derivatives. Upon applying SFAS No. 157, we changed our valuation methodology to consider our nonperformance risk in estimating the fair value of our liabilities. The initial adoption of SFAS No. 157 had no material impact on our Consolidated Financial Statements. In February 2008, the FASB issued FSPFAS 157-2, permitting entities to delay application of SFAS No. 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, we will apply SFAS No. 157 fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed at fair value on a recurring basis. SFAS No. 157 requires two distinct transition approaches: (1) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (2) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable, for all other instruments. Upon adopting SFAS No. 157, we applied a prospective transition as we did not have financial instrument transactions that required a cumulative-effect adjustment to beginning retained earnings.
119
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fair value is the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered from the perspective of a market participant. We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
| | |
| • | Level 1 — Quoted prices 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 management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. Instruments in this category primarily include OTC options. |
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
120
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table sets forth by level within the fair value hierarchy our assets and liabilities that are measured at fair value on a recurring basis.
Fair Value Measurements at December 31, 2008 Using:
| | | | | | | | | | | | | | | | | |
| | | 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) | |
| |
| Assets: | | | | | | | | | | | | | | | | |
| Energy derivatives | | $ | 680 | | | $ | 1,223 | | | $ | 547 | | | $ | 2,450 | |
| Other assets | | | 13 | | | | — | | | | 7 | | | | 20 | |
| | | | | | | | | | | | | | | | | |
| Total assets | | $ | 693 | | | $ | 1,223 | | | $ | 554 | | | $ | 2,470 | |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Energy derivatives | | $ | 615 | | | $ | 1,313 | | | $ | 40 | | | $ | 1,968 | |
| | | | | | | | | | | | | | | | | |
| Total liabilities | | $ | 615 | | | $ | 1,313 | | | $ | 40 | | | $ | 1,968 | |
| | | | | | | | | | | | | | | | | |
Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures and options. OTC contracts include forwards, swaps and options.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value also incorporates the time value of money and credit risk factors including the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash deposits and letters of credit) and our nonperformance risk on our liabilities.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Contracts for which fair value can be estimated from executed transactions or broker quotes corroborated by other market data are generally classified within Level 2. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Our derivatives portfolio is largely comprised ofexchange-traded products or like products and the tenure of our derivatives portfolio is short with 99 percent expiring in the next 36 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis by management.
Certain instruments trade in less active markets with lower availability of pricing information requiring valuation models using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The fair value of options is estimated using an industry standard Black-Scholes option pricing model. Certain inputs into the model are generally observable, such as commodity prices and interest rates, whereas other model inputs, such as implied volatility by location, is unobservable and requires judgment in estimating. The instruments
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included in Level 3 at December 31, 2008, predominantly consist of options that primarily hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled.
The following table sets forth a reconciliation of changes in the fair value of net derivatives and other assets classified as Level 3 in the fair value hierarchy.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Year Ended December 31, 2008
| | | | | | | | | |
| | | Net Derivatives | | | Other Assets | |
| | | (Millions) | |
| |
| Balance as of January 1, 2008 | | $ | (14 | ) | | $ | 10 | |
| Realized and unrealized gains (losses): | | | | | | | | |
Included inincome from continuing operations | | | 88 | | | | (3 | ) |
Included inother comprehensive income | | | 486 | | | | — | |
| Purchases, issuances, and settlements | | | (51 | ) | | | — | |
| Transfers into Level 3 | | | 3 | | | | — | |
| Transfers out of Level 3 | | | (5 | ) | | | — | |
| | | | | | | | | |
| Balance as of December 31, 2008 | | $ | 507 | | | $ | 7 | |
| | | | | | | | | |
Unrealized gains (losses) included inincome from continuing operationsrelating to instruments still held at December 31, 2008 | | $ | — | | | $ | — | |
| | | | | | | | | |
Realized and unrealized gains (losses) included inincome from continuing operationsfor the above period are reported inrevenuesin our Consolidated Statement of Income. Reclassification of fair value into and out of Level 3 is made at the end of each quarter.
| |
Note 14.15. | Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk |
Financial Instruments
Fair-value methods
We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:
Cash and cash equivalents and restricted cash: The carrying amounts of cash equivalents reported in the balance sheet approximate fair value due to the short-term maturity of these instruments.
Other securities, notesNotes and other noncurrent receivables, structured indemnity settlement obligation, margin deposits, and customer margin deposits payable: The carrying amounts reported in the balance sheet approximate fair value as these instruments have interest rates approximating market. Othermarket.
Cost-based investments and other securitiesin the table below consists of: This includes cost-based investments, auction rate securities, ARO Trust investments andheld-to-maturity securities. These are carried at fair value with the exception of certain international investments that are not publicly traded. In 2007, auction rate securities and held-to-maturity securities are reported inother current assets and deferred chargesin the Consolidated Balance Sheet. In 2008, auction rate securities are classified withininvestmentsin the Consolidated Balance Sheet due to auction failures. The ARO Trust investments are classified as available-for-sale and are reported inother assets and deferred chargesin the Consolidated Balance Sheet. (See Note 9.)
Long-term debt: The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with
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similar terms and credit ratings. At December 31, 20062008 and 2005,2007, approximately 8795 percent and 8990 percent, respectively, of our long-term debt was publicly traded. We use the expertise of outside investment banking firms to assist with the estimate of the fair value of our long-term debt.
Guarantees: Theguaranteesrepresented in the table below consistsconsist primarily of guarantees we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on certain lease performance obligations. To estimate the fair value of the guarantees, the estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate for each guarantee based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rates are published by Moody’s Investors Service.
Energy derivatives: Energy derivatives include:include futures, forwards, swaps, and options. See Note 14 for discussion of valuation of our energy derivatives.
| | |
| • | Futures contracts; |
|
| • | Forward contracts; |
|
| • | Swap agreements; |
|
| • | Option contracts. |
The fair value of energy derivatives is determined based on the nature of the underlying transaction and the market in which the transaction is executed. We execute most of these transactions on an organized commodity exchange or inover-the-counter markets in which quoted prices exist for active periods. For contracts with terms that exceed the time period for which actively quoted prices are available, we determine fair value by estimating commodity prices during the illiquid periods utilizing internally developed valuations incorporating information obtained from commodity prices in actively quoted markets, quoted prices in less active markets, prices reflected in current transactions, and other market fundamental analysis.
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Carrying amounts and fair values of our financial instruments
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | Carrying
| | | | Carrying
| | | | | Carrying
| | | | Carrying
| | | |
Asset (Liability) | | Amount | | Fair Value | | Amount | | Fair Value | | | Amount | | Fair Value | | Amount | | Fair Value | |
| | | (Millions) | | | (Millions) | |
| |
| Cash and cash equivalents | | $ | 2,268.6 | | | $ | 2,268.6 | | | $ | 1,597.2 | | | $ | 1,597.2 | | | $ | 1,439 | | | $ | 1,439 | | | $ | 1,699 | | | $ | 1,699 | |
| Restricted cash (current and noncurrent) | | | 126.1 | | | | 126.1 | | | | 129.4 | | | | 129.4 | | | | 133 | | | | 133 | | | | 127 | | | | 127 | |
| Other securities | | | 103.2 | | | | 103.2 | | | | 122.9 | | | | 122.9 | | |
| Cost-based investments and other securities | | | | 37 | | | | 20 | (a) | | | 45 | | | | 20 | (a) |
| Notes and other noncurrent receivables | | | 3.6 | | | | 3.6 | | | | 26.6 | | | | 26.6 | | | | 2 | | | | 2 | | | | 4 | | | | 4 | |
| Cost based investments (see Note 3) | | | 51.6 | | | | (a | ) | | | 56.7 | | | | (a | ) | |
| Long-term debt, including current portion (see Note 11)(b) | | | (8,011.6 | ) | | | (8,480.0 | ) | | | (7,710.3 | ) | | | (8,599.4 | ) | |
| Structured indemnity settlement obligation (see Note 10) | | | (33.9 | ) | | | (33.9 | ) | | | (51.3 | ) | | | (51.3 | ) | |
| Margin deposits | | | 59.3 | | | | 59.3 | | | | 349.2 | | | | 349.2 | | | | 8 | | | | 8 | | | | 76 | | | | 76 | |
| Long-term debt, including current portion(b) | | | | (7,874 | ) | | | (6,285 | ) | | | (7,890 | ) | | | (8,729 | ) |
| Guarantees | | | | (38 | ) | | | (32 | ) | | | (40 | ) | | | (34 | ) |
| Customer margin deposits payable | | | (128.7 | ) | | | (128.7 | ) | | | (320.7 | ) | | | (320.7 | ) | | | (30 | ) | | | (30 | ) | | | (10 | ) | | | (10 | ) |
| Guarantees | | | (41.6 | ) | | | (34.8 | ) | | | (43.3 | ) | | | (43.3 | ) | |
| Net energy derivatives: | | | | | | | | | | | | | | | | | |
| Net energy derivatives(c): | | | | | | | | | | | | | | | | | |
| Energy commodity cash flow hedges | | | 365.1 | | | | 365.1 | | | | (5.5 | ) | | | (5.5 | ) | | | 458 | | | | 458 | | | | (268 | ) | | | (268 | ) |
| Other energy derivatives | | | 69.8 | | | | 69.8 | | | | 106.9 | | | | 106.9 | | | | 24 | | | | 24 | | | | (100 | ) | | | (100 | ) |
| Other derivatives(c) | | | 1.5 | | | | 1.5 | | | | .9 | | | | .9 | | |
| | |
| (a) | | TheseExcludes certain international investments in companies that are primarily in nonpubliclynot publicly traded companies for whichand therefore it is not practicable to estimate fair value. (See Note 3.) |
| |
| (b) | | Excludes capital leases. (See Note 11.) |
| |
| (c) | | ConsistsA portion of nonenergy cash flow hedges.these derivatives is included in assets and liabilities of discontinued operations. (See Note 2.) |
Energy Derivatives
Our energy derivative contracts include the following:
Futures contracts: Futures contracts are standardized commitments through an organized commodity exchange to either purchase or sell a commodity at a future date for a specified price. Futures are generally settled in cash, but may be settled through delivery of the underlying commodity. The fair value of these contacts is generally determined using quoted prices.
Forward contracts: Forward contracts areover-the-counter commitments to either purchase or sell a commodity at a future date for a specified price, which involve physical delivery of energy commodities, and may contain either fixed or variable pricing terms. Forward contracts are generally valued based on prices of the underlying energy commodities over the contract life and contractual or notional volumes with the resulting expected future cash flows discounted to a present value using a risk-free market interest rate.
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Swap agreements: Swap agreements require us to make payments to (or receive payments from) counterparties based upon the differential between a fixed and variable price or between variable prices of energy commodities at different locations. Swap agreements are generally valued based on prices of the underlying energy commodities over the contract life and contractual or notional volumes with the resulting expected future cash flows discounted to a present value using a risk-free market interest rate.
Option contracts: Physical and financial option contracts give the buyer the right to exercise the option and receive the difference between a predetermined strike price and a market price at the date of exercise. An option to purchase and an option to sell can be combined in an instrument called a collar to set a minimum and maximum transaction price. These
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contracts are generally valued based on option pricing models considering prices of the underlying energy commodities over the contract life, volatility of the commodity prices, contractual volumes, estimated volumes under option and other arrangements, and a risk-free market interest rate.
Energy commodity cash flow hedges
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases and sales of natural gas and electricityforecasted sales of NGLs attributable to commodity price risk. Certain of these derivatives have been designated as cash flow hedges under SFAS No. 133.
Our Power segment sells electricity produced by our electric generation facilities, obtained contractually through tolling agreements or obtained through marketplace transactions at different locations throughout the United States. We also buy electricity and capacity to serve our full requirements agreements in the Southeast. To reduce exposure to a decrease in revenues and increase in costs from fluctuations in electricity prices, we enter into fixed-price forward physical sales and purchase contracts and financial option contracts to mitigate the price risk on forecasted electricity sales and purchases.
Our electric generation facilities and tolling agreements require natural gas for the production of electricity. To reduce our exposure to increasing costs of natural gas due to changes in market prices, we enter into natural gas futures contracts, swap agreements, fixed-price forward physical purchases and financial option contracts to mitigate the price risk on anticipated purchases of natural gas.
Power’s cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item, changes in the creditworthiness of counterparties, and the hedging derivative contract having an initial fair value upon designation.
Our Exploration & Production segment produces, buys and sells natural gas at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in natural gas market prices, we hedge price risk by enteringenter into natural gas futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales and purchases of natural gas. We have also enterentered into basis swap agreements to reduce the locational price risk associated with our producing basins. Exploration & Production’s cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.
Our Midstream segment produces, buys and sells NGLs at different locations throughout the United States. Our Midstream segment also buys the required fuel and shrink needed to generate NGLs. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices, we may hedge price risk by entering into NGL swap agreements, financial forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs. Midstream’s cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Midstream does not have any commodity-related cash flow hedges at December 31, 2008.
Changes in the fair value of our cash flow hedges are deferred in other comprehensive income and are reclassified intorevenuesin the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During 2006,2008, we reclassified approximately $1$2 million of net gainslosses from other comprehensive income to earnings as a result of the discontinuance of cash flow hedges because the forecasted transaction did not occur by the end of the originally specified time period. In second-quarter 2007, we recognized a net gain of $429 million (reported inrevenuesof discontinued operations) associated with the reclassification of deferred net hedge gains of our former power business fromaccumulated other comprehensive income/lossto earnings. This reclassification was based on the determination that the hedged forecasted transactions were probable of not occurring. See Note 2 for further discussion. Approximately $20$2 million and $2$14 million of net gainslosses from hedge ineffectiveness are included inrevenues in the Consolidated Statement of Income during 20062008 and 2005,2007, respectively. For 20062008 and 2005,2007, there are no derivative gains or losses excluded from the assessment of hedge effectiveness. As of December 31, 2006,2008, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to ninefour years. Based on recorded values at December 31, 2006,2008, approximately $9$189 million of net gains (net of income tax provision of $6 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2006. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized in 2007 will likely differ from these values. These gains or losses will offset net losses or gains that
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tax provision of $115 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2008. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized in 2009 will likely differ from these values. These gains or losses will offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
Power elected hedge accounting for certain of its nontrading derivatives in the fourth quarter of 2004 after our Board decided in September 2004 to retain the Power business. Before this election, net changes in the fair value of these derivatives were recognized as revenues in the Consolidated Statement of Income.
Other energy derivatives
Our Power segment hasGas Marketing Services and Exploration & Production segments have other energy derivatives that have not been designated or do not qualify as SFAS No. 133 hedges. As such, the net change in their fair value is recognized inrevenuesin the Consolidated Statement of Income. Even though they do not qualify for hedge accounting (seederivative instruments and hedging activitiesin Note 1 for a description of hedge accounting), certain of these derivatives hedge Power’sour future cash flows on an economic basis.
In addition, our Exploration & Production segment enters into natural gas basis swap agreements that are not designated in a hedging relationship under SFAS No. 133. The fair value of these contracts is approximately $22 million as of December 31, 2006.
Other energy-related contracts
We also hold significant nonderivative energy-related contracts, such as storage and transportation agreements, in our Power portfolios.Gas Marketing Services portfolio. These have not been included in the financial instruments table above or in our Consolidated Balance Sheet because they are not derivatives as defined by SFAS No. 133.
Guarantees
In addition to the guarantees and payment obligations discussed elsewhere in these footnotes (see Notes 3 and 15)16), we have issued guarantees and other similar arrangements with off-balance sheet risk as discussed below.
In connection with agreements executed prior to our acquisition of Transco to resolvetake-or-pay and other contract claims and to amend gas purchase contracts, Transco entered into certain settlements with producers whichthat may require the indemnification of certain claims for additional royalties that the producers may be required to pay as a result of such settlements. Transco, through its agent, Power,Gas Marketing Services, continues to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions that have no carrying value. Producers have received certain demands and may receive other demands, which could result in claims pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and Transco. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined. However, management believes that the probability of material payments is remote.
In connection with the 1993 public offering of units in the Williams Coal Seam Gas Royalty Trust (Royalty Trust), our Exploration & Production segment entered into a gas purchase contract for the purchase of natural gas in which the Royalty Trust holds a net profits interest. Under this agreement, we guarantee a minimum purchase price that the Royalty Trust will realize in the calculation of its net profits interest. We have an annual option to discontinue this minimum purchase price guarantee and pay solely based on an index price. The maximum potential future exposure associated with this guarantee is not determinable because it is dependent upon natural gas prices and production volumes. No amounts have been accrued for this contingent obligation as the index price continues to substantially exceed the minimum purchase price.
We are required by certain foreign lenders to ensure that the interest rates received by them under various loan agreements are not reduced by taxes by providing for the reimbursement of any domestic taxes required to be paid
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by the foreign lender. The maximum potential amount of future payments under these indemnifications is based on the related borrowings. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications.
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We have provided guarantees in the event of nonpayment by our previously owned communications subsidiary, WilTel, on certain lease performance obligations that extend through 2042. The maximum potential exposure is approximately $46$42 million at December 31, 2006,2008, and $47$44 million at December 31, 2005.2007. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is approximately $41$38 million at December 31, 2006.2008.
Former managing directors of Gulf Liquids are involved in litigation related to the construction of gas processing plants. Gulf Liquids has indemnity obligations to the former managing directors for legal fees and potential losses that may result from this litigation. Claims against these former managing directors have been settled and dismissed after payments on their behalf by directors and officers insurers. Some unresolved issues remain between us and these insurers, but no amounts have been accrued for any potential liability.
We have guaranteed the performance of a former subsidiary of our wholly owned subsidiary MAPCO Inc., under a coal supply contract. This guarantee was granted by MAPCO Inc. upon the sale of its former subsidiary to a third-party in 1996. The guaranteed contract provides for an annual supply of a minimum of 2.25 million tons of coal. Our potential exposure is dependent on the difference between current market prices of coal and the pricing terms of the contract, both of which are variable, and the remaining term of the contract. Given the variability of the terms, the maximum future potential payments cannot be determined. We believe that our likelihood of performance under this guarantee is remote. In the event we are required to perform, we are fully indemnified by the purchaser of MAPCO Inc.’s former subsidiary. This guarantee expires in December 2010 and has no carrying value.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents consist ofare primarily invested in funds with high-quality, short-term securities placed with various major financial institutions with credit ratings atand instruments that are issued or above BBBguaranteed by Standard & Poor’s or Baa1 by Moody’s Investors Service.the U.S. government.
Accounts and notes receivable
The following table summarizes concentration of receivables including those related to discontinued operations (see Note 2), net of allowances, by product or service at December 31, 20062008 and 2005:2007:
| | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Millions) | | | (Millions) | |
| |
| Receivables by product or service: | | | | | | | | | | | | | | | | |
| Sale or transportation of natural gas and related products | | $ | 894.7 | | | $ | 1,142.6 | | |
| Sale of natural gas and related products and services | | | $ | 653 | | | $ | 882 | |
| Transportation of natural gas and related products | | | | 158 | | | | 177 | |
| Joint interest | | | | 86 | | | | 80 | |
| Sales of power and related services | | | 270.2 | | | | 394.5 | | | | — | | | | 55 | |
| Interest | | | 38.6 | | �� | | 32.4 | | |
| Other | | | 9.4 | | | | 44.3 | | | | 49 | | | | 53 | |
| | | | | | | | | | | |
| Total | | $ | 1,212.9 | | | $ | 1,613.8 | | | $ | 946 | | | $ | 1,247 | |
| | | | | | | | | | | |
Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains, Gulf Coast, Venezuela and Canada. Customers for power include the California Independent System Operator (ISO), the California Department of Water Resources, and other power marketers and utilities located throughout the United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
Our Venezuelan operations are operated for the exclusive benefit of PDVSA. As energy commodity prices have sharply declined, PDVSA has failed to make regular payments to many service providers, including us. Included withinsale of natural gas and related products and servicesin the table above at December 31, 2008, is a $57 million net receivable from PDVSA, none of which was 60 days old or older at that date. We continue to
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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.
Derivative assets and liabilities
We have a risk of loss as a result of counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss results from items including credit considerations and the regulatory environment for which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances.
The concentration of counterparties within the energy and energy trading industry impacts our overall exposure to credit risk in that these counterparties are similarly influenced by changes in the economy and regulatory issues. Additional collateral support could include the following:letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties.
| | |
| • | Letters of credit; |
|
| • | Payment under margin agreements; |
|
| • | Guarantees of payment by credit worthy parties. |
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2008 and 2007, we did not incur any significant losses due to counterparty bankruptcy filings.
The gross credit exposure from our derivative contracts, a portion of which is included in assets of discontinued operations (see Note 2), as of December 31, 2006,2008, is summarized below.as follows.
| | | | | | | | | | | | | | | | | |
| | | Investment
| | | | | Investment
| | | |
Counterparty Type | | Grade(a) | | Total | | | Grade(a) | | Total | |
| | | (Millions) | | | (Millions) | |
| |
| Gas and electric utilities | | $ | 248.0 | | | $ | 249.9 | | | $ | 2 | | | $ | 2 | |
| Energy marketers and traders | | | 412.7 | | | | 1,784.3 | | | | 127 | | | | 896 | |
| Financial institutions | | | 2,219.4 | | | | 2,219.4 | | | | 1,558 | | | | 1,559 | |
| Other | | | 23.3 | | | | 29.8 | | |
| | | | | | | | | | | |
| | | $ | 2,903.4 | | | | 4,283.4 | | | $ | 1,687 | | | | 2,457 | |
| | | | | | | |
| Credit reserves | | | | | | | (20.3 | ) | | | | | | | (6 | ) |
| | | | | | | |
| Gross credit exposure from derivatives | | | | | | $ | 4,263.1 | | | | | | | $ | 2,451 | |
| | | | | | | |
We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of December 31, 2006,2008, excluding collateral support discussed below, is summarized below.as follows.
| | | | | | | | | | | | | | | | | |
| | | Investment
| | | | | Investment
| | | |
Counterparty Type | | Grade(a) | | Total | | | Grade(a) | | Total | |
| | | (Millions) | | | (Millions) | |
| |
| Gas and electric utilities | | $ | 120.4 | | | $ | 120.5 | | | $ | — | | | $ | 1 | |
| Energy marketers and traders | | | 209.0 | | | | 455.4 | | | | 79 | | | | 80 | |
| Financial institutions | | | 325.5 | | | | 325.5 | | | | 600 | | | | 600 | |
| Other | | | 20.4 | | | | 20.4 | | |
| | | | | | | | | | | |
| | | $ | 675.3 | | | | 921.8 | | | $ | 679 | | | | 681 | |
| | | | | | | |
| Credit reserves | | | | | | | (20.3 | ) | | | | | | | (6 | ) |
| | | | | | | |
| Net credit exposure from derivatives | | | | | | $ | 901.5 | | | | | | | $ | 675 | |
| | | | | | | |
| | |
| (a) | | We determine investment grade primarily using publicly available credit ratings. We includedinclude counterparties with a minimum Standard & Poor’s of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. |
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| | |
| | We also classify counterparties that have provided sufficient collateral, such as cash, standby letters of credit, parent company guarantees, and property interests, as investment grade. |
Our ten largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are five counterparty positions, representing 72 percent of our net credit exposure from derivatives, associated with Exploration & Production’s hedging facility. (See Note 11.) Under certain conditions, the terms of this credit agreement may require the participating financial institutions to deliver collateral support with a designated collateral agent (which is another participating financial institution in the agreement). The level of collateral support required is dependent on whether the net position of the counterparty financial institution exceeds specified thresholds. The thresholds may be subject to prescribed reductions based changes in the credit rating of the counterparty financial institution.
At December 31, 2008, the designated collateral agent held $198 million of collateral support on our behalf under Exploration & Production’s hedging facility. In addition, we held collateral support, including letters of credit, of $36 million related to our other derivative positions.
Revenues
In 2006, 20052008, 2007 and 2004,2006, there were no customers for which our sales exceeded 10 percent of our consolidated revenues.
| |
Note 15.16. | Contingent Liabilities and Commitments |
Rate and Regulatory Matters and Related Litigation
Our interstate pipeline subsidiaries have various regulatory proceedings pending. As a result of rulings in certain of these proceedings, a portion of the revenues of these subsidiaries has been collected subject to refund. The natural gas pipeline subsidiaries have accrued approximately $2 million for potential refunds as of December 31, 2006.
Issues Resulting Fromfrom California Energy Crisis
Subsidiaries of our Power segment areOur former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the FERC.U.S. Federal Energy Regulatory Commission (FERC). These challenges included refund proceedings, summer 200290-day contracts, investigations of alleged market manipulation including withholding, gas indices and other gaming of the market, new long-term power sales to the State of California that were subsequently challenged and civil litigation relating to certain of these issues. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.
As a result of a December 19, 2006 Ninth CircuitJune 2008 U.S. Supreme Court of Appeals decision, certain contracts that Powerwe entered into during 2000 and 2001 may be subject to partial refunds.refunds depending on the results of further proceedings at the FERC. These contracts, under which Powerwe sold electricity, totaled approximately $89 million in revenue. While Power iswe are not a party to the cases involved in the appellate courtU.S. Supreme Court decision, the buyer of electricity from Powerus is a party to the cases and claims that Powerwe must refund to the buyer any loss it suffers due to the decision and the FERC’s reconsideration of the contract terms at issue in the decision. The FERC has directed the parties to provide additional information on certain issues remanded by the U.S. Supreme Court, but delayed the submission of this information to permit the parties to explore possible settlements of the contractual disputes.
Certain other issues also remain open at the FERC and for other nonsettling parties.
Refund proceedings
Although we entered into the State Settlement and Utilities Settlement, which resolved the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, such as the counterparty to the contracts described above and various California end users that did not participate in the Utilities Settlement. As a part of the Utilities Settlement, we funded escrow accounts that we anticipate will satisfy any ultimate refund determinations in favor of the nonsettling parties including interest on refund amounts that we might owe to settling and nonsettling parties. We are also owed interest from counterparties in the California market during the refund period for which we have recorded a receivable totaling approximately $31$24 million at December 31, 2006.2008. Collection of the interest is subject toand the conclusionpayment of this proceeding. Therefore, we continue to participate ininterest on refund amounts from the FERC refund case and related proceedings. Challenges to virtually every aspect of the refund proceeding, including the refund period, were made to the Ninth Circuit Court of Appeals. On August 2, 2006, the Ninth Circuit issued its order that largely upheld the FERC’s prior rulings, but it expanded the types of transactions that were made subject to refund. Because of our settlement, we do not expect this decision will have a material impact on us. No final refund calculation, however, has been made, and certain aspects of the refund calculation process remain unclear and prevent that final refund calculation. As part of the State Settlement, an additional $45 million, previously accrued, remains to be paidescrow accounts is
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subject to the California Attorney General (or his designee) overconclusion of this proceeding. Therefore, we continue to participate in the next three years, withFERC refund case and related proceedings.
Challenges to virtually every aspect of the refund proceedings, including the refund period, continue to be made. Because of our settlements, we do not expect that the final paymentresolution of $15 million duerefund obligations will have a material impact on January 1, 2010.us. Despite two FERC decisions that will affect the refund calculation, significant aspects of the refund calculation process remain unsettled, and the final refund calculation has not been made.
Reporting of Natural Gas-Related Information to Trade Publications
We disclosed on October 25, 2002, that certain of our natural gas traders had reported inaccurate information to a trade publication that published gas price indices. In 2002, we received a subpoena from a federal grand jury in northern California seeking documents related to our involvement in California markets, including our reporting to trade publications for both gas and power transactions. We have completed our response to the subpoena. Three former traders with Power have pled guilty to manipulation of gas prices through misreporting to an industry trade periodical. One former trader has pled not guilty. On February 21, 2006, we entered into a deferred prosecution agreement with the Department of Justice (DOJ) that is intended to resolve this matter. The agreement obligated us to pay a total of $50 million, of which $20 million was paid in March 2006. The remaining $30 million has been paid in February 2007. Absent a breach, the agreement will expire 15 months from the date of execution of the agreement and no further action will be taken by the DOJ.
Civil suits based on allegations of manipulating thepublished gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in:
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| | • | Class actionState court litigation in federal court in Nevada allegingCalifornia brought on behalf of certain business and governmental entities that we manipulatedpurchased gas prices for direct purchasers of gas in California. We have reached settlement of this matter for $2.4 million. Legal documents will be filed with the court and the settlement is subject to court approval.their use. |
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| | • | Class action litigation in state court in California alleging that we manipulated prices for indirect purchasers of gas in California. On December 11, 2006, the court granted final approval of our settlement of this matter for $15.6 million. |
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| • | State court in California on behalf of certain individual gas users. |
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| • | Class actionand 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. |
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| • | 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. |
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| • | On February 2, 2007,October 29, 2008, the Tennessee appellate court reversed the state court’s dismissal of the plaintiffs’ claims on federal preemption grounds and sent the case back to the lower court for further proceedings. We and other defendants appealed the reversal to the Tennessee Supreme Court. |
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| • | On January 13, 2009, the Missouri state court dismissed a case for lack of standing. We expect that the case before it because the claims could onlydecision will be asserted at the FERC.appealed. |
Earlier this year, we settled a case for $9.15 million in Federal court in New York based on an allegation of manipulation of the NYMEX gas market. It is reasonably possible that additional amounts may be necessary to resolve the remaining outstanding litigation in this area, the amount of which cannot be reasonably estimated at this time.
Mobile Bay Expansion
In December 2002, an administrative law judge at the FERC issued an initial decision in Transco’s 2001 general rate case which, among other things, rejected the recovery of the costs of Transco’s Mobile Bay expansion project from its shippers on a “rolled-in” basis and found that incremental pricing for the Mobile Bay expansion project is just and reasonable. In March 2004, the FERC issued an Order on Initial Decision in which it reversed certain parts of the administrative law judge’s decision and accepted Transco’s proposal for rolled-in rates. Power holds long-term transportation capacity on the Mobile Bay expansion project. If the FERC had adopted the decision of the administrative law judge on the pricing of the Mobile Bay expansion project and also required that the decision be implemented effective September 1, 2001, Power could have been subject to surcharges of approximately $111 million, including interest, through December 31, 2006, in addition to increased costs going forward. Certain parties have filed appeals in federal court seeking to have the FERC’s ruling on the rolled-in rates overturned.
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Enron Bankruptcy
We have outstanding claims against Enron Corp. and various of its subsidiaries (collectively “Enron”) related to its bankruptcy filed in December 2001. In 2002, we sold $100 million of our claims against Enron to a third party for $24.5 million. In 2003, Enron filed objections to these claims. We have resolved Enron’s objections, subject to court approval. Pursuant to the sales agreement, the purchaser of the claims has demanded repayment of the purchase price for the reduced portions of the claims. In January 2007, we entered into anagreement-in-principle with the purchaser to settle any potential repayment obligations.
Environmental Matters
Continuing operations
Since 1989, our Transco subsidiary has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other programsparties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At December 31, 2006,2008, we had accrued liabilities of $6$5 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than $500,000, which is included in the environmental accrual discussed above. We expect that these costs will be recoverable through Transco’s rates.
Beginning in the mid-1980’s,mid-1980s, our Northwest Pipeline subsidiary evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest Pipeline identified
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hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and Northwest Pipeline conducted a voluntaryclean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to reevaluate its previous mercuryclean-ups in Washington. Currently,Consequently, Northwest Pipeline is assessing the actions needed for theconducting additional remediation activities at certain sites to comply with Washington’s current environmental standards. At December 31, 2006,2008, we have accrued liabilities totaling approximately $5of $9 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.
In March 2008, the EPA issued a new air quality standard for ground level ozone. The new standard will likely impact the operations of our interstate gas pipelines and cause us to incur additional capital expenditures to comply. At this time we are unable to estimate the cost of these additions that may be required to meet the new regulations. We expect that costs associated with these compliance efforts will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2006,2008, we have accrued liabilities totaling approximately $7$6 million for these costs.
In August 2005, our subsidiary, Williams Production RMT Company, voluntarily disclosed toApril 2007, the Colorado Department of Public Health andNew Mexico Environment (CDPHE) two air permit violations. We have reached an agreement in principle with the CDPHE in which we agree to pay a $500,000 penalty and conduct a supplemental environmental project. A definitive agreement will be finalized soon.
In March 2006, the CDPHE issued a notice of violation (NOV) to Williams Production RMT Company related to our operating permit for the Rulison oil separation and evaporation facility. On April 12, 2006, we met with the
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CDPHE to discuss the allegations contained in the NOV. In May 2006, we provided additional information to the agency regarding the emission estimates for operations from 1997 through 2003 and applied for updated permits.
In July 2006, the CDPHEDepartment’s Air Quality Bureau (NMED) issued an NOV to Williams Production RMT Company relatedFour Corners, LLC (Four Corners) that alleged various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. In December 2007, the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV to operating permitsFour Corners that alleged air emissions permit exceedances for three glycol dehydrators at one of our Roan Cliffscompressor facilities and Hayburn Gas Plantsproposed a penalty of approximately $103,000. We are discussing the proposed penalties with the NMED.
In March 2008, the EPA proposed a penalty of $370,000 for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in Garfield County, Colorado. In September 2006, weColorado and for alleged permit violations at a compressor station. We met with the CDPHEEPA and are exchanging information in order to discussresolve the allegations contained in the NOV, and in October 2006, we provided additional requested information to the agency.issues.
In August 2006,September 2007, the CDPHE issued a NOV to Williams Production RMT Company related toEPA requested, and our Grand Valley Oil SeparationTransco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Evaporation Facility located in Garfield County, Colorado in whichAlabama as part of the CDPHE alleged that we failed to obtain a construction permit and to comply with certain provisionsEPA’s investigation of our existing permit. In September, 2006, wecompliance with the Clean Air Act. On March 28, 2008, the EPA issued NOVs alleging violations of Clean Air Act requirements at these compressor stations. We met with the CDPHE,EPA in May 2008 and submitted our response denying the allegations in October 2006, we provided additional requested information to the agency.
In July 2001, the EPA issued an information request asking for information on oil releases and discharges in any amount from our pipelines, pipeline systems, and pipeline facilities used in the movement of oil or petroleum products, during the period from July 1, 1998 through July 2, 2001. In November 2001, we furnished our response. In March 2004, the DOJ invited the new owner of Williams Energy Partners and Magellan Midstream Partners, L.P. (Magellan) to enter into negotiations regarding alleged violations of the Clean Water Act. With the exception of four minor release events that underwent earlier cleanup operation under state enforcement actions, our environmental indemnification obligations to Magellan were released in a 2004 buyout. We do not expect further enforcement action with respect to the four release events or two 2006 spills at our Colorado and Wyoming facilities after providing additional requested information to the DOJ.June 2008.
Former operations, including operations classified as discontinued
In connection with the sale of certain assets and businesses, we have retained responsibility, through indemnification of the purchasers, for environmental and other liabilities existing at the time the sale was consummated, as described below.
Agrico
In connection with the 1987 sale of the assets of Agrico Chemical Company, we agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations to the extent such costs exceed a specified amount. At December 31, 2006,2008, we have accrued liabilities of approximately $9 million for such excess costs.
Other
At December 31, 2006,2008, we have accrued environmental liabilities totaling approximately $25of $14 million related primarily to our:
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| | • | Potential indemnification obligations to purchasers of our former retail petroleum and refining operations; |
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| | • | Former propane marketing operations, bio-energy facilities, petroleum products and natural gas pipelines; |
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| • | Discontinued petroleum refining facilities; |
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| • | Former exploration and production and mining operations. |
These costs include certain conditions at specified locations related primarily to soil and groundwater contamination and any penalty assessed on Williams Refining & Marketing, L.L.C. (Williams Refining) associated with noncompliance with the EPA’s National Emission Standards for Hazardous Air Pollutants (NESHAP). In 2002, Williams Refining submitted a self-disclosure letter to the EPA indicating noncompliance with those regulations. This unintentional noncompliance had occurred due to a regulatory interpretation that resulted in under-counting the total annual benzene level at Williams Refining’s Memphis refinery. Also in 2002, the EPA conducted an all-
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media audit of the Memphis refinery. In 2004, Williams Refining and the new owner of the Memphis refinery met with the EPA and the DOJ to discuss alleged violations and proposed penalties due to noncompliance issues identified in the report, including the benzene NESHAP issue. In July and August 2006, we finalized our agreements that resolved both the government’s claims against us for alleged violations and an indemnity dispute with the purchaser in connection with our 2003 sale of the Memphis refinery. We have paid the required settlement amounts to the purchaser, and our payment to the government awaits the filing of the settlement with the court.
In 2004, our Gulf Liquids subsidiary initiated a self-audit of all environmental conditions (air, water, waste) at three facilities: Geismar, Sorrento, and Chalmette, Louisiana. The audit revealed numerous infractions of Louisiana environmental regulations and resulted in a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ). No specific penalty amount was assessed. Instead, LDEQ was required by Louisiana law to demand a profit and loss statement to determine the financial benefit obtained by noncompliance and to assess a penalty accordingly. Gulf Liquids offered $91,500 as a single, final, global multi-media settlement. Subsequent negotiations have resulted in a revised offer of $109,000, which LDEQ is currently reviewing.
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| • | Discontinued petroleum refining facilities; and |
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| • | Former exploration and production and mining operations. |
Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws.
Summary of environmental matters
Actual costs incurred for these matters could be substantially greater than amounts accrued depending on the actual number of contaminated sites identified, the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors, but the amount cannot be reasonably estimated at this time.
Other Legal Matters
Will Price (formerly Quinque)
In 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held onin April 1, 2005. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.
Grynberg
In 1998, the DOJU.S. Department of Justice (DOJ) informed us that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against us and certain of our wholly owned subsidiaries. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In connection with our sales of Kern River Gas Transmission in 2002 and Texas Gas Transmission Corporation in 2003, we agreed to indemnify the purchasers for any liability relating to this claim, including legal fees. The maximum amount of future payments that we could potentially be required to pay under these indemnifications depends upon the ultimate resolution of the claim and cannot currently be determined. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the DOJ announced that it was declining towould not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District
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Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remained pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against our Gas Pipeline and Midstream subsidiaries be dismissed but upheld the claims against our Exploration & Production subsidiaries against our jurisdictional challenge. In October 2006, theThe District Court dismissed all claims against us and our wholly owned subsidiaries, and in November 2006, Grynberg filed his notice ofsubsidiaries. The matter is on appeal withto the Tenth Circuit Court of Appeals.
OnIn August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust, served us and one of our Exploration & Production subsidiaries with a complaint in the state court in Denver, Colorado. The complaint alleges thatplaintiffs alleged we have used mismeasurement techniques that distortdistorted the BTUBritish Thermal Unit heating content of natural gas resulting in the alleged underpayment of royalties to Grynbergthem and other independent natural gas producers. The complaintThey also alleges thatalleged we inappropriately took inappropriate deductions from the gross value of their natural gas and made other royalty valuation errors. Under various theories of relief, the plaintiff isthey were seeking actual damages of between $2 million and $20 million based on interest rate variations and punitive damages in the amount of approximately $1.4$1 million. In 2004, Grynberg filed an amended complaint against one of our Exploration & Production subsidiaries. This subsidiary filed an answer in January 2005, denying liability for the damages claimed. Trial in this case was originally set for May 2006, but the parties have negotiated an agreementagreed to dismiss mismeasurement claims. In September
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2008, the court ruled in our favor on motions for summary judgment dismissing the measurement claims and deferring further proceedingsvarious claims. Trial on the royaltyremaining breach of contract and accounting claims until resolution of an appealoccurred in another case.November 2008. The jury found against us and awarded less than $2 million, which we believe materially concludes the matter. The plaintiffs seek to increase the total award by approximately $1 million, which we have contested.
Securities class actions
Numerous shareholder class action suits were filed against us in 2002 in the United States District Court for the Northern District of Oklahoma. The majority of the suits alleged that we and co-defendants, WilTel, previously an owneda subsidiary known as Williams Communications, and certain corporate officers, acted jointly and separately to inflate the stock price of both companies. Other suits alleged similar causes of action related to a public offering in early January 2002 known as the FELINE PACS offering. These cases were also filed in 2002 against us, certain corporate officers, all members of our board of directors and all of the offerings’ underwriters.WilTel securities. WilTel was dismissed as a defendant as a result of its bankruptcy. These cases were consolidated and an order was issued requiring separate amended consolidated complaints by our equity holders and WilTel equity holders. The underwriter defendants have requested indemnification and defense from these cases. If we grant the requested indemnifications to the underwriters, any related settlement costs will not be covered by our insurance policies. We covered the cost of defending the underwriters. In 2002, the amended complaints of the WilTel securities holders and of our securities holders added numerous claims related to Power.
On June 13, 2006, we announced that we had reached anagreement-in-principle to settle the claims of our securities holders for a total payment of $290 million. On October 4, 2006,July 6, 2007, the court granted preliminary approval of the settlement. On November 3, 2006, we paid into escrow approximately $145 million in cash to fund the settlement, and the balance of the total settlement amount was funded by our insurers. On February 9, 2007, the court gave its final approval to the settlement. We entered into indemnity agreements with certain of our insurers to ensure their timely payment related to this settlement. The carrying value of our estimated liability related to these agreements is immaterial because we believe the likelihood of any future performance is remote.
Litigation with the WilTel equity holders continues but the trial has been stayed pending decisions on various defendants’ motions for summary judgment.judgment and entered judgment for us and the other defendants in the WilTel matter. On February 18, 2009, the Tenth Circuit Court of Appeals affirmed the lower court’s decision. The plaintiffs might seek rehearing before the Tenth Circuit or request a writ of certiorari from the United States Supreme Court. Any obligation of ours to the WilTel equity holders as a result of a settlement, or as a result of trial in the event of a successful appeal of the court’s judgment, will not likely be covered by insurance asbecause our insurance coverage has been fully utilized by the settlement described above. The extent of theany such obligation is presently unknown and cannot be estimated, but it is reasonably possible that our exposure could materially exceedsexceed amounts accrued for this matter.
Derivative shareholder suits have been filed in state court in Oklahoma all based on similar allegations. The state court approved motions to consolidate and to stay these Oklahoma suits pending action by the federal court in
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the shareholder suits. On December 23, 2006, our insurer paid $1.2 million on our behalf to reimburse the plaintiffs’ attorneys fees and expenses which concluded the settlement of these suits. We previously implemented certain corporate governance and internal control enhancements that we agreed to under the court-approved settlement agreement.
Federal income tax litigation
One of our wholly-owned subsidiaries, Transco Coal Gas Company, was engaged in a dispute with the Internal Revenue Service (IRS) regarding the recapture of certain income tax credits associated with the construction of a coal gasification plant in North Dakota by Great Plains Gasification Associates, in which Transco Coal Gas Company was a partner. This case has been resolved. (See Note 5.)
TAPS Quality Bank
One of our subsidiaries, Williams Alaska Petroleum, Inc. (WAPI), is activelyhas been engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha, heavy distillate, vacuum gas oil and residual product cuts within the TAPS Quality Bank as well as the appropriate retroactive effects of the determinations. Due to the sale of WAPI’s interests on March 31, 2004, no future Quality Bank liability will accrue but we are responsible for any liability that existed as of that date including potential liability for any retroactive payments that might be awarded in these proceedings for the period prior to March 31, 2004. In the third quarter of 2004, the FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions. The initial decisions, set forth methodologies for determining the valuations of the product cuts under review and also approved the retroactive application of the approved methodologies for the heavy distillate and residual product cuts. Inthird-quarter 2004, we accrued approximately $134 million based on our computation and assessment of ultimate ruling terms that were considered probable. Our additional potential refund liability terminated on March 31, 2004, when WAPI sold the Alaska refinery and ceased shipping on the TAPS pipeline. We subsequently accrued additional amounts for interest.
The FERC and the RCA completed their reviews of the initial decisions and in 2005 issued substantially similar orders generally affirming the initial decisions. On June 1,In 2006, the FERC after two sets of rehearing requests, entered its final order, (FERC Final Order). During this administrative rehearing process all other appeals ofwhich the initial decisions were stayed including ExxonMobil’s appeal toRCA adopted. On February 15, 2008, the Alaska Supreme Court upheld the RCA’s order and on March 16, 2008, the D.C. Circuit Court of Appeals asserting thatupheld the FERC’s reliance onorder. We have paid substantially all amounts invoiced by the Highway Reauthorization Act as the basis for limiting the retroactive effect violates, among other things, the separation of powers under the U.S. Constitution by interfering with the FERC’s independent decision-making role. ExxonMobil filed a similar appeal in the Alaska Superior Court. We also appealed the FERC’s order to the extent of its ruling on the West Coast Heavy Distillate component.
The Quality Bank Administrator issued his interpretationsand third parties, except certain disputed amounts which remain accrued.
In 2008, we concluded that the likelihood of successful appeal by the payment obligations under the FERC Final Order,counterparties was remote, and we and others filed exceptions to these instructions with the FERC. We expect the FERC’s ruling on these payment instruction exceptions later in the first quarter of 2007. Once the FERC rules, the Administrator will invoice us forreduced remaining amounts due, and we will be required to pay the invoiced amounts, subject to the outcome of the appeals of the FERC Final Order. We estimate that our net obligation could be as much as $116 million. Amounts accrued in excess of our estimated remaining obligation by $54 million. On January 12, 2009, this estimated obligation will be retained pending resolutionmatter concluded when the U.S. Supreme Court denied a counterparty’s request for a writ of all appeals.
Redondo Beach taxes
On February 5, 2005, Power received a tax assessment letter, addressedcertiorari to AES Redondo Beach, L.L.C. and Power, fromappeal the city of Redondo Beach, California, in which the city asserted that approximately $33 million in back taxes and approximately $39 million in interest and penalties are owed related to natural gas used at the generating facility operated by AES Redondo Beach. Hearings were held in July 2005 and in September 2005 the tax administrator for the city issued a decision in which he found Power jointly and severally liable with AES Redondo Beach for back taxes of approximately $36 million and interest and penalties of approximately
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$21 million. Both we and AES Redondo Beach filed notices of appeal that were heard at the city level. On December 13, 2006, the city hearing officer for the appealruling of the pre-2005 amounts issued a final decision affirming our utility user tax liability and reversing AES Redondo’s liability because the officer ruled that AES Redondo is an exempt public utility. Even though we appealed this decision to the Los Angeles SuperiorD.C. Circuit Court we may be required to pay the full amount of any final assessment prior to the resolution of this state court appeal. Despite the city hearing officer’s unfavorable decision and the potential payment to preserve our appeal rights, we do not believe a contingent loss is probable.
The City’s current assessment of our liability (for the periods from 1998 through September 2006) is approximately $69 million (inclusive of interest and penalties). We have protested all these assessments and requested hearings on them. We and AES Redondo have also filed separate refund actions in Los Angeles Superior Court related to certain taxes paid since the initial 2005 notice of assessment. We believe that under our tolling agreement related to the Redondo Beach generating facility, AES Redondo Beach is responsible for taxes of the nature asserted by the city; however, AES Redondo Beach has notified us that it does not agree.Appeals.
Gulf Liquids litigation
Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. Gulsby and Gulsby-Bay defaulted on the construction contracts. In the fall of 2001, the contractors sureties, and Gulf Liquidssureties filed multiple cases in Louisiana and Texas. In January 2002, NAICO added Gulf Liquids’ co-venturer Power to the suits as a third-party defendant.Texas against Gulf Liquids asserted claims against the contractors and sureties for, among other things, breach of contract requesting contractual and consequential damages from $40 million to $80 million, any of which is subject to a sharing arrangement with XL Insurance Company.us.
AtIn 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual and punitive damages verdict against Powerus and Gulf Liquids on July 31, 2006 and its related punitive damages verdict on August 1, 2006. The court is not expected to enter any judgment until the second or third quarter of 2007.Liquids. Based on our interpretation of the jury verdicts, we haverecorded a charge based on our estimated exposure for actual damages of approximately $68 million plus potential interest of approximately $22 million, all of which have been accrued as of December 31, 2006.$20 million. In addition, we concluded that it iswas reasonably possible that any ultimate judgment may include additional amounts of approximately $199 million in excess of our accrual, which primarily represents our estimate of potential punitive damage exposure under Texas law.
Hurricane lawsuits
We were named as a defendant in two class action petitions for damages filed in federal court in Louisiana in September and October 2005 arising from hurricanes that struck Louisiana in 2005. The class action plaintiffs, purporting to represent persons, businesses and entities in the State of Louisiana who have suffered damage as a result of the winds and storm surge from the hurricanes, allege that the operating activities of the twosub-classes of defendants, which are all oil and gas pipelines (including Transco) that dredged pipeline canals or installed pipelines in the marshes of south Louisiana and all oil and gas exploration and production companies which drilled for oil and gas or dredged canals in the marshes of south Louisiana, have altered marshland ecology and caused marshland destruction which otherwise would have averted all or almost all of the destruction and loss of life caused by the hurricanes. Plaintiffs requested that the court allow the lawsuits to proceed as class actions and sought legal and equitable relief in an unspecified amount. In September 2006, the court granted our and the other defendants’ joint motion to dismiss the class action petitions on various grounds. In August 2006, an additional class action case containing substantially identical allegations was filed against the same defendants, including Transco. This case was dismissed on November 30, 2006.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
judgment might have included additional amounts of approximately $199 million in excess of our accrual, which primarily represented our estimate of potential punitive damage exposure under Texas law.
From May through October 2007, the court entered seven post-trial orders in the case (interlocutory orders) which, among other things, overruled the verdict award of tort and punitive damages as well as any damages against us. The court also denied the plaintiffs’ claims for attorneys’ fees. On January 28, 2008, the court issued its judgment awarding damages against Gulf Liquids of approximately $11 million in favor of Gulsby and approximately $4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby, Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In February 2009, we settled with certain of these parties and reduced our liability as of December 31, 2008, by $43 million, including $11 million of interest. If the judgment is upheld on appeal, our remaining liability will be substantially less than the amount of our accrual for these matters.
Wyoming severance taxes
TheIn August 2006, the Wyoming Department of Audit (DOA) audited the severance tax reporting forassessed our subsidiary, Williams Production RMT Company, additional severance tax and interest for the production years 2000 through 2002. In August 2006, the DOA assessed additional severance tax and interest for those periods of approximately $3 million. In addition, the DOA notified us of an increase in the taxable value of our interests for ad valorem tax purposes, which is estimated to result in additional taxes of approximately $2 million, including interest.purposes. We disputedisputed the DOA’s interpretation of the statutory obligation and have appealed this assessment to the Wyoming State Board of Equalization. IfEqualization (SBOE). The SBOE upheld the assessment and remanded it to the DOA prevailsto address the disallowance of a credit. We appealed to the Wyoming Supreme Court. In December 2008, the Wyoming Supreme Court ruled against us. The negative assessment for the2000-2002 time period resulted in its interpretationadditional severance and ad valorem taxes of our obligation and applies the same basis of assessment to subsequent periods, it is reasonably possible that we could owe$4 million. We have accrued a total liability of approximately $21$39 million related to $23 million in taxes andthis matter representing our exposure, including interest, from January 1, 2003, through December 31, 2006.the end of 2008. We have petitioned for rehearing of a portion of the ruling.
Royalty litigation
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in Colorado state court alleging that we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of gas and extracted products, improperly charged certain expenses, and failed to refund amounts withheld in excess of ad valorem tax obligations. The plaintiffs claim that the class might be in excess of 500 individuals and seek an accounting and damages. The parties have agreedreached a partial settlement agreement for an amount that was previously accrued. The partial settlement has received preliminary approval by the court, and we anticipate trial in late 2009 on remaining issues related to stayroyalty payment calculation and obligations under specific lease provisions. We are not able to estimate the amount of any additional exposure at this actiontime.
Certain other royalty matters are currently being litigated by other producers with a federal regulatory agency in orderColorado and with a state agency in New Mexico. Although we are not a party to participate inthese matters, the final outcome of those cases might lead to a mediation to be scheduled.future unfavorable impact on our results of operations.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
We sold a natural gas liquids pipeline system in 2002, and in July 2006, the purchaser of that system filed its complaint against us and our subsidiaries in state court in Houston, Texas. The purchaser alleges that we breached certain warranties under the purchase and sale agreement and seeks an unspecified amount of damages and our specific performance under certain guarantees. On September 1, 2006, we filed our answer to the purchaser’s complaint denying all liability. We anticipate that the trial will occur in the fourth quarter 2007, and our prior suit filed against the purchaser in Delaware state court has been stayed pending resolution of the Texas case.
At December 31, 2006,2008, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
133
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
Summary
Litigation, arbitration, regulatory matters, and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materiallymaterial adverse effect upon our future financial position.
Commitments
Commitments for construction and acquisition of property, plant and equipment are approximately $472 million at December 31, 2008.
136134
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Commitments
Power has entered into certain contracts giving it the right to receive fuel conversion services as well as certain other services associated with electric generation facilities that are currently in operation throughout the continental United States. At December 31, 2006, Power’s estimated committed payments under these contracts range from approximately $406 million to $424 million annually through 2017 and decline over the remaining five years to $59 million in 2022. Total committed payments under these contracts over the next sixteen years are approximately $5.5 billion. Included in the $5.5 billion is a $1.9 billion contract that is accounted for as an operating lease. (See Leases-Lessee in Note 11.) Total payments made under these contracts during 2006, 2005, and 2004 were $409 million, $403 million, and $402 million, respectively.
Commitments for construction and acquisition of property, plant and equipment are approximately $406 million at December 31, 2006.
137
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
Note 16.17. | Accumulated Other Comprehensive Loss |
The table below presents changes in the components ofaccumulated other comprehensive loss.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Income (Loss) | |
| | | | | | | | | | | | | | | | | | | | | Other Postretirement
| | | | |
| | | | | | Unrealized
| | | | | | | | | Pension Benefits | | | Benefits | | | | |
| | | | | | Appreciation
| | | Foreign
| | | Minimum
| | | Prior
| | | Net
| | | Prior
| | | Net
| | | | |
| | | Cash Flow
| | | (Depreciation)
| | | Currency
| | | Pension
| | | Service
| | | Actuarial
| | | Service
| | | Actuarial
| | | | |
| | | Hedges | | | On Securities | | | Translation | | | Liability | | | Cost | | | Loss | | | Cost | | | Gain | | | Total | |
| | | (Millions) | |
| |
| Balance at December 31, 2003 | | $ | (165.6 | ) | | $ | (1.9 | ) | | $ | 53.1 | | | $ | (6.6 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (121.0 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2004 Change: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | (460.9 | ) | | | (2.4 | ) | | | 15.8 | | | | 3.0 | | | | — | | | | — | | | | — | | | | — | | | | (444.5 | ) |
| Income tax benefit (provision) | | | 176.5 | | | | .9 | | | | — | | | | (1.2 | ) | | | — | | | | — | | | | — | | | | — | | | | 176.2 | |
| Net reclassification into earnings of derivative instrument losses (net of a $87.8 million income tax benefit) | | | 141.7 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 141.7 | |
| Realized losses on securities reclassified into earnings (net of a $2.1 million income tax benefit) | | | — | | | | 3.4 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 3.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (142.7 | ) | | | 1.9 | | | | 15.8 | | | | 1.8 | | | | — | | | | — | | | | — | | | | — | | | | (123.2 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2004 | | | (308.3 | ) | | | — | | | | 68.9 | | | | (4.8 | ) | | | — | | | | — | | | | — | | | | — | | | | (244.2 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2005 Change: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | (395.5 | ) | | | — | | | | 11.4 | | | | .6 | | | | — | | | | — | | | | — | | | | — | | | | (383.5 | ) |
| Income tax benefit (provision) | | | 151.3 | | | | — | | | | — | | | | (.2 | ) | | | — | | | | — | | | | — | | | | — | | | | 151.1 | |
| Net reclassification into earnings of derivative instrument losses (net of a $110.8 million income tax benefit) | | | 178.8 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 178.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (65.4 | ) | | | — | | | | 11.4 | | | | .4 | | | | — | | | | — | | | | — | | | | — | | | | (53.6 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | | (373.7 | ) | | | — | | | | 80.3 | | | | (4.4 | ) | | | — | | | | — | | | | — | | | | — | | | | (297.8 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2006 Change: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | 423.2 | | | | — | | | | (4.7 | ) | | | (1.3 | ) | | | — | | | | — | | | | — | | | | — | | | | 417.2 | |
| Income tax benefit (provision) | | | (161.8 | ) | | | — | | | | — | | | | .4 | | | | — | | | | — | | | | — | | | | — | | | | (161.4 | ) |
| Net reclassification into earnings of derivative instrument losses (net of a $82.3 million income tax benefit) | | | 132.8 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 132.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 394.2 | | | | — | | | | (4.7 | ) | | | (.9 | ) | | | — | | | | — | | | | — | | | | — | | | | 388.6 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Adjustment to initially apply SFAS No. 158: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | — | | | | — | | | | — | | | | 8.4 | | | | (5.7 | ) | | | (243.2 | )* | | | (6.7 | ) | | | (7.8 | ) | | | (255.0 | ) |
| Income tax benefit (provision) | | | — | | | | — | | | | — | | | | (3.1 | ) | | | 2.2 | | | | 92.5 | | | | 2.6 | | | | 9.9 | | | | 104.1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | — | | | | — | | | | — | | | | 5.3 | | | | (3.5 | ) | | | (150.7 | ) | | | (4.1 | ) | | | 2.1 | | | | (150.9 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | $ | 20.5 | | | $ | — | | | $ | 75.6 | | | $ | — | | | $ | (3.5 | ) | | $ | (150.7 | ) | | $ | (4.1 | ) | | $ | 2.1 | | | $ | (60.1 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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) | |
| |
| Balance at December 31, 2005 | | $ | (374 | ) | | $ | 80 | | | $ | (4 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (298 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2006 Change: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | 423 | | | | (4 | ) | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | 418 | |
| Income tax provision | | | (162 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (162 | ) |
| Net reclassification into earnings of derivative instrument losses (net of a $82 million income tax benefit) | | | 133 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 133 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 394 | | | | (4 | ) | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | 389 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Adjustment to initially apply SFAS No. 158: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | — | | | | — | | | | 8 | | | | (6 | ) | | | (243 | )* | | | (7 | ) | | | (8 | ) | | | (256 | ) |
| Income tax (provision) benefit | | | — | | | | — | | | | (3 | ) | | | 2 | | | | 93 | | | | 3 | | | | 10 | | | | 105 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | — | | | | — | | | | 5 | | | | (4 | ) | | | (150 | ) | | | (4 | ) | | | 2 | | | | (151 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | | 20 | | | | 76 | | | | — | | | | (4 | ) | | | (150 | ) | | | (4 | ) | | | 2 | | | | (60 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2007 Change: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | 201 | | | | 53 | | | | — | | | | — | | | | 68 | | | | — | | | | 15 | | | | 337 | |
| Income tax provision | | | (77 | ) | | | — | | | | — | | | | — | | | | (26 | ) | | | — | | | | (6 | ) | | | (109 | ) |
| Net reclassification into earnings of derivative instrument gains (net of a $187 million income tax provision) | | | (303 | )** | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (303 | ) |
| Amortization included in net periodic benefit expense | | | — | | | | — | | | | — | | | | — | | | | 19 | | | | 2 | | | | — | | | | 21 | |
| Income tax provision on amortization | | | — | | | | — | | | | — | | | | — | | | | (8 | ) | | | (1 | ) | | | — | | | | (9 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | (179 | ) | | | 53 | | | | — | | | | — | | | | 53 | | | | 1 | | | | 9 | | | | (63 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Allocation of other comprehensive loss to minority interest | | | 2 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2007 | | | (157 | ) | | | 129 | | | | — | | | | (4 | ) | | | (97 | ) | | | (3 | ) | | | 11 | | | | (121 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2008 Change: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-income tax amount | | | 714 | | | | (76 | ) | | | — | | | | — | | | | (565 | ) | | | 16 | | | | (15 | ) | | | 74 | |
| Income tax (provision) benefit | | | (270 | ) | | | — | | | | — | | | | — | | | | 213 | | | | (8 | ) | | | 6 | | | | (59 | ) |
| Net reclassification into earnings of derivative instrument losses (net of a $7 million income tax benefit) | | | 11 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 11 | |
| Amortization included in net periodic benefit expense | | | — | | | | — | | | | — | | | | 1 | | | | 13 | | | | 1 | | | | — | | | | 15 | |
| Income tax provision on amortization | | | — | | | | — | | | | — | | | | — | | | | (5 | ) | | | — | | | | — | | | | (5 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 455 | | | | (76 | ) | | | — | | | | 1 | | | | (344 | ) | | | 9 | | | | (9 | ) | | | 36 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Allocation of other comprehensive income (loss) to minority interest | | | (2 | ) | | | — | | | | — | | | | — | | | | 7 | | | | — | | | | — | | | | 5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2008 | | $ | 296 | | | $ | 53 | | | $ | — | | | $ | (3 | ) | | $ | (434 | ) | | $ | 6 | | | $ | 2 | | | $ | (80 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| * | | Includes $0.8$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.) |
138135
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Available-for-Sale Securities
During 2004, we received proceeds totaling $851.4 million from the sale and maturity of available-for-sale securities. We realized losses of $5.5 million from these transactions.
| |
Note 17.18. | Segment Disclosures |
Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Our master limited partnership,partnerships, Williams Partners L.P. and Williams Pipeline Partners L.P., isare consolidated within our Midstream segment.and Gas Pipeline segments, respectively. (See Note 1.) Other primarily consists of corporate operations.
Performance Measurement
We currently evaluate performance based onsegment profit (loss)from operations, which includessegment revenuesfrom external and internal customers,segment costs and expenses, depreciation, depletion and amortization, equity earnings (losses)andincome (loss) from investments including impairments related to investments accounted for under the equity method.. The accounting policies of the segments are the same as those described in Note 1. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.
During 2004, Power was party to intercompany interest rate swaps with the corporate parent, the effectThe primary types of which is included in Power’scosts and operating expenses by segment revenues andsegment profit (loss)can be generally summarized as shown in the reconciliation within the following tables. We terminated these interest-rate derivatives in the fourth quarter of 2004.follows:
| | |
| • | 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. |
The majority of energy
Energy commodity hedging by certain of our business units ismay be done through intercompany derivatives with Powerour Gas Marketing Services segment which, in turn, enters into offsetting derivative contracts with unrelated third parties. PowerGas Marketing Services bears the counterparty performance risks associated with the unrelated third parties. parties in these transactions. Additionally, Exploration & Production may enter into transactions directly with third parties under their credit agreement. (See Note 11.) Exploration & Production bears the counterparty performance risks associated with the unrelated third parties in these transactions.
External revenues of our Exploration & Production segment includesinclude third-party oil and gas sales, which are more than offset by transportation expenses and royalties due third parties on intersegment sales.
The following geographic area data includesrevenues from external customersbased on product shipment origin andlong-lived assetsbased upon physical location.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | United States | | Other | | Total | | | United States | | Other | | Total | |
| | | (Millions) | | | (Millions) | |
| |
| Revenues from external customers: | | | | | | | | | | | | | | | | | | | | | | | | |
| 2008 | | | $ | 11,924 | | | $ | 428 | | | $ | 12,352 | |
| 2007 | | | | 10,065 | | | | 421 | | | | 10,486 | |
| 2006 | | $ | 11,418.3 | | | $ | 394.6 | | | $ | 11,812.9 | | | | 8,905 | | | | 394 | | | | 9,299 | |
| 2005 | | | 12,258.3 | | | | 325.3 | | | | 12,583.6 | | |
| 2004 | | | 12,167.8 | | | | 293.5 | | | | 12,461.3 | | |
| Long-lived assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| 2008 | | | $ | 18,419 | | | $ | 659 | | | $ | 19,078 | |
| 2007 | | | | 16,279 | | | | 713 | | | | 16,992 | |
| 2006 | | $ | 14,510.4 | | | $ | 681.7 | | | $ | 15,192.1 | | | | 14,487 | | | | 682 | | | | 15,169 | |
| 2005 | | | 12,692.7 | | | | 739.8 | | | | 13,432.5 | | |
| 2004 | | | 12,149.0 | | | | 762.0 | | | | 12,911.0 | | |
136
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Our foreign operations are primarily located in Venezuela, Canada, and Argentina.Long-lived assetsare comprised of property, plant and equipment, goodwill and other intangible assets.
139
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table reflects the reconciliation ofsegment revenuesandsegment profit (loss)torevenuesandoperating income (loss)as reported in the Consolidated Statement of Income andother financial informationrelated tolong-lived assets.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Midstream
| | | | | | | | | | | | | | | Midstream
| | Gas
| | | | | | | |
| | | Exploration &
| | Gas
| | Gas &
| | | | | | | | | | | Exploration &
| | Gas
| | Gas &
| | Marketing
| | | | | | | |
| | | Production | | Pipeline | | Liquids | | Power | | Other | | Eliminations | | Total | | | Production | | Pipeline | | Liquids | | Services | | Other | | Eliminations | | Total | |
| | | (Millions) | | | (Millions) | |
| |
2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External | | | $ | (215 | ) | | $ | 1,600 | | | $ | 5,586 | | | $ | 5,371 | | | $ | 10 | | | $ | — | | | $ | 12,352 | |
| Internal | | | | 3,336 | | | | 34 | | | | 56 | | | | 1,041 | | | | 14 | | | | (4,481 | ) | | | — | |
| | | | | | | | | | | | | | | | | |
| Total revenues | | | $ | 3,121 | | | $ | 1,634 | | | $ | 5,642 | | | $ | 6,412 | | | $ | 24 | | | $ | (4,481 | ) | | $ | 12,352 | |
| | | | | | | | | | | | | | | | | |
| Segment profit (loss) | | | $ | 1,260 | | | $ | 689 | | | $ | 963 | | | $ | 3 | | | $ | (3 | ) | | $ | — | | | $ | 2,912 | |
| Less: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity earnings | | | | 20 | | | | 59 | | | | 58 | | | | — | | | | — | | | | — | | | | 137 | |
| Income from investments | | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | — | | | | 1 | |
| | | | | | | | | | | | | | | | | |
| Segment operating income (loss) | | | $ | 1,240 | | | $ | 630 | | | $ | 904 | | | $ | 3 | | | $ | (3 | ) | | $ | — | | | | 2,774 | |
| | | | | | | | | | | | | | | |
| General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | (149 | ) |
| | | | | |
| Total operating income | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 2,625 | |
| | | | | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additions to long-lived assets | | | $ | 2,563 | | | $ | 413 | | | $ | 679 | | | $ | — | | | $ | 42 | | | $ | — | | | $ | 3,697 | |
| Depreciation, depletion & amortization | | | $ | 737 | | | $ | 321 | | | $ | 233 | | | $ | 1 | | | $ | 18 | | | $ | — | | | $ | 1,310 | |
2007 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External | | | $ | (167 | ) | | $ | 1,576 | | | $ | 5,142 | | | $ | 3,924 | | | $ | 11 | | | $ | — | | | $ | 10,486 | |
| Internal | | | | 2,188 | | | | 34 | | | | 38 | | | | 709 | | | | 15 | | | | (2,984 | ) | | | — | |
| | | | | | | | | | | | | | | | | |
| Total revenues | | | $ | 2,021 | | | $ | 1,610 | | | $ | 5,180 | | | $ | 4,633 | | | $ | 26 | | | $ | (2,984 | ) | | $ | 10,486 | |
| | | | | | | | | | | | | | | | | |
| Segment profit (loss) | | | $ | 756 | | | $ | 673 | | | $ | 1,072 | | | $ | (337 | ) | | $ | (1 | ) | | $ | — | | | $ | 2,163 | |
| Less equity earnings | | | | 25 | | | | 51 | | | | 61 | | | | — | | | | — | | | | — | | | | 137 | |
| | | | | | | | | | | | | | | | | |
| Segment operating income (loss) | | | $ | 731 | | | $ | 622 | | | $ | 1,011 | | | $ | (337 | ) | | $ | (1 | ) | | $ | — | | | | 2,026 | |
| | | | | | | | | | | | | | | |
| General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | (161 | ) |
| | | | | |
| Total operating income | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,865 | |
| | | | | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additions to long-lived assets | | | $ | 1,717 | | | $ | 546 | | | $ | 610 | | | $ | — | | | $ | 27 | | | $ | — | | | $ | 2,900 | |
| Depreciation, depletion & amortization | | | $ | 535 | | | $ | 315 | | | $ | 214 | | | $ | 7 | | | $ | 10 | | | $ | — | | | $ | 1,081 | |
2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External | | $ | (189.9 | ) | | $ | 1,335.6 | | | $ | 4,071.1 | | | $ | 6,585.9 | | | $ | 10.2 | | | $ | — | | | $ | 11,812.9 | | | $ | (266 | ) | | $ | 1,336 | | | $ | 4,094 | | | $ | 4,128 | | | $ | 7 | | | $ | — | | | $ | 9,299 | |
| Internal | | | 1,677.5 | | | | 12.1 | | | | 53.6 | | | | 876.5 | | | | 16.3 | | | | (2,636.0 | ) | | | — | | | | 1,677 | | | | 12 | | | | 65 | | | | 921 | | | | 20 | | | | (2,695 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total revenues | | $ | 1,487.6 | | | $ | 1,347.7 | | | $ | 4,124.7 | | | $ | 7,462.4 | | | $ | 26.5 | | | $ | (2,636.0 | ) | | $ | 11,812.9 | | | $ | 1,411 | | | $ | 1,348 | | | $ | 4,159 | | | $ | 5,049 | | | $ | 27 | | | $ | (2,695 | ) | | $ | 9,299 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment profit (loss) | | $ | 551.5 | | | $ | 467.4 | | | $ | 658.3 | | | $ | (210.8 | ) | | $ | 1.9 | | | $ | — | | | $ | 1,468.3 | | | $ | 552 | | | $ | 467 | | | $ | 675 | | | $ | (195 | ) | | $ | (13 | ) | | $ | — | | | $ | 1,486 | |
| Less equity earnings | | | 21.8 | | | | 37.1 | | | | 27.0 | | | | 13.0 | | | | — | | | | — | | | | 98.9 | | | | 22 | | | | 37 | | | | 40 | | | | — | | | | — | | | | — | | | | 99 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment operating income (loss) | | $ | 529.7 | | | $ | 430.3 | | | $ | 631.3 | | | $ | (223.8 | ) | | $ | 1.9 | | | $ | — | | | | 1,369.4 | | | $ | 530 | | | $ | 430 | | | $ | 635 | | | $ | (195 | ) | | $ | (13 | ) | | $ | — | | | | 1,387 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | (132.1 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | (132 | ) |
| Securities litigation settlement and related costs | | | | | | | | | | | | | | | | | | | | | | | | | | | (167.3 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | (167 | ) |
| | | �� | | | | | | |
| Consolidated operating income | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,070.0 | | |
| Total operating income | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,088 | |
| | | | | | | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additions to long-lived assets | | $ | 1,495.7 | | | $ | 913.2 | | | $ | 279.4 | | | $ | 1.1 | | | $ | 18.1 | | | $ | — | | | $ | 2,707.5 | | | $ | 1,496 | | | $ | 913 | | | $ | 279 | | | $ | 1 | | | $ | 18 | | | $ | — | | | $ | 2,707 | |
| Depreciation, depletion & amortization | | $ | 360.2 | | | $ | 281.7 | | | $ | 201.2 | | | $ | 10.7 | | | $ | 11.7 | | | $ | — | | | $ | 865.5 | | | $ | 360 | | | $ | 282 | | | $ | 203 | | | $ | 7 | | | $ | 11 | | | $ | — | | | $ | 863 | |
| | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2005 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External | | $ | (201.6 | ) | | $ | 1,395.0 | | | $ | 3,187.6 | | | $ | 8,192.5 | | | $ | 10.1 | | | $ | — | | | $ | 12,583.6 | | |
| Internal | | | 1,470.7 | | | | 17.8 | | | | 45.1 | | | | 901.4 | | | | 17.1 | | | | (2,452.1 | ) | | | — | | |
| | | | | | | | | | | | | | | | | |
| Total revenues | | $ | 1,269.1 | | | $ | 1,412.8 | | | $ | 3,232.7 | | | $ | 9,093.9 | | | $ | 27.2 | | | $ | (2,452.1 | ) | | $ | 12,583.6 | | |
| | | | | | | | | | | | | | | | | |
| Segment profit (loss) | | $ | 587.2 | | | $ | 585.8 | | | $ | 471.2 | | | $ | (256.7 | ) | | $ | (105.0 | ) | | $ | — | | | $ | 1,282.5 | | |
| Less: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity earnings (losses) | | | 18.8 | | | | 43.6 | | | | 23.6 | | | | 3.1 | | | | (23.5 | ) | | | — | | | | 65.6 | | |
| Income (loss) from investments | | | — | | | | — | | | | 1.0 | | | | (23.0 | ) | | | (87.1 | ) | | | — | | | | (109.1 | ) | |
| | | | | | | | | | | | | | | | | |
| Segment operating income (loss) | | $ | 568.4 | | | $ | 542.2 | | | $ | 446.6 | | | $ | (236.8 | ) | | $ | 5.6 | | | $ | — | | | | 1,326.0 | | |
| | | | | | | | | | | | | | | |
| General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | (145.5 | ) | |
| Securities litigation settlement and related costs | | | | | | | | | | | | | | | | | | | | | | | | | | | (9.4 | ) | |
| | | | | |
| Consolidated operating income | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,171.1 | | |
| | | | | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additions to long-lived assets | | $ | 794.7 | | | $ | 420.2 | | | $ | 133.2 | | | $ | 5.9 | | | $ | 4.7 | | | $ | — | | | $ | 1,358.7 | | |
| Depreciation, depletion & amortization | | $ | 254.2 | | | $ | 267.3 | | | $ | 192.0 | | | $ | 14.9 | | | $ | 11.6 | | | $ | — | | | $ | 740.0 | | |
| | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2004 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External | | $ | (84.0 | ) | | $ | 1,345.0 | | | $ | 2,844.7 | | | $ | 8,346.2 | | | $ | 9.4 | | | $ | — | | | $ | 12,461.3 | | |
| Internal | | | 861.6 | | | | 17.3 | | | | 37.9 | | | | 912.5 | | | | 23.4 | | | | (1,852.7 | ) | | | — | | |
| | | | | | | | | | | | | | | | | |
| Total segment revenues | | | 777.6 | | | | 1,362.3 | | | | 2,882.6 | | | | 9,258.7 | | | | 32.8 | | | | (1,852.7 | ) | | | 12,461.3 | | |
| Less intercompany interest rate swap loss | | | — | | | | — | | | | — | | | | (13.7 | ) | | | — | | | | 13.7 | | | | — | | |
| | | | | | | | | | | | | | | | | |
| Total revenues | | $ | 777.6 | | | $ | 1,362.3 | | | $ | 2,882.6 | | | $ | 9,272.4 | | | $ | 32.8 | | | $ | (1,866.4 | ) | | $ | 12,461.3 | | |
| | | | | | | | | | | | | | | | | |
| Segment profit (loss) | | $ | 235.8 | | | $ | 585.8 | | | $ | 549.7 | | | $ | 76.7 | | | $ | (41.6 | ) | | $ | — | | | $ | 1,406.4 | | |
| Less: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity earnings (losses) | | | 11.9 | | | | 29.2 | | | | 14.6 | | | | 3.9 | | | | (9.7 | ) | | | — | | | | 49.9 | | |
| Loss from investments | | | — | | | | (1.0 | ) | | | (17.1 | ) | | | — | | | | (17.4 | ) | | | — | | | | (35.5 | ) | |
| Intercompany interest rate swap loss | | | — | | | | — | | | | — | | | | (13.7 | ) | | | — | | | | — | | | | (13.7 | ) | |
| | | | | | | | | | | | | | | | | |
| Segment operating income (loss) | | $ | 223.9 | | | $ | 557.6 | | | $ | 552.2 | | | $ | 86.5 | | | $ | (14.5 | ) | | $ | — | | | | 1,405.7 | | |
| | | | | | | | | | | | | | | |
| General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | (119.8 | ) | |
| | | | | |
| Consolidated operating income | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,285.9 | | |
| | | | | |
| Other financial information: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additions to long-lived assets | | $ | 445.4 | | | $ | 300.1 | | | $ | 91.3 | | | $ | 1.0 | | | $ | 6.0 | | | $ | — | | | $ | 843.8 | | |
| Depreciation, depletion & amortization | | $ | 192.3 | | | $ | 264.4 | | | $ | 178.4 | | | $ | 20.1 | | | $ | 13.3 | | | $ | — | | | $ | 668.5 | | |
140137
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table reflectstotal assetsandequity method investmentsby reporting segment.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Total Assets | | Equity Method Investments | | | Total Assets | | Equity Method Investments | |
| | | December 31,
| | December 31,
| | December 31,
| | December 31,
| | December 31,
| | December 31,
| | | December 31,
| | December 31,
| | December 31,
| | December 31,
| | December 31,
| | December 31,
| |
| | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Exploration & Production(1) | | $ | 7,850.9 | | | $ | 8,672.0 | | | $ | 5,576.4 | | | $ | 58.8 | | | $ | 58.4 | | | $ | 44.9 | | | $ | 10,286 | | | $ | 8,692 | | | $ | 7,851 | | | $ | 87 | | | $ | 72 | | | $ | 59 | |
| Gas Pipeline | | | 8,331.7 | | | | 7,581.0 | | | | 7,651.8 | | | | 432.4 | | | | 439.1 | | | | 769.5 | | | | 9,149 | | | | 8,624 | | | | 8,332 | | | | 570 | | | | 483 | | | | 432 | |
| Midstream Gas & Liquids | | | 5,483.8 | | | | 4,677.7 | | | | 4,211.7 | | | | 304.1 | | | | 314.2 | | | | 273.3 | | | | 7,024 | | | | 6,604 | | | | 5,562 | | | | 290 | | | | 321 | | | | 323 | |
| Power(2) | | | 6,884.8 | | | | 14,989.2 | | | | 8,204.1 | | | | 19.1 | | | | 19.2 | | | | 45.6 | | |
| Gas Marketing Services(2) | | | | 3,064 | | | | 4,437 | | | | 5,519 | | | | — | | | | — | | | | — | |
| Other | | | 4,224.6 | | | | 3,942.7 | | | | 3,597.6 | | | | — | | | | .2 | | | | 113.2 | | | | 3,532 | | | | 3,592 | | | | 3,923 | | | | — | | | | — | | | | — | |
Eliminations(3) | | | (7,373.4 | ) | | | (10,420.0 | ) | | | (5,248.6 | ) | | | — | | | | — | | | | — | | | | (7,055 | ) | | | (7,073 | ) | | | (7,187 | ) | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 25,402.4 | | | $ | 29,442.6 | | | $ | 23,993.0 | | | $ | 814.4 | | | $ | 831.1 | | | $ | 1,246.5 | | |
| | | | | | | | | | | | | | | | | 26,000 | | | | 24,876 | | | | 24,000 | | | | 947 | | | | 876 | | | | 814 | |
| Discontinued operations | | | | 6 | | | | 185 | | | | 1,402 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | |
| Total | | | $ | 26,006 | | | $ | 25,061 | | | $ | 25,402 | | | $ | 947 | | | $ | 876 | | | $ | 814 | |
| | | | | | | | | | | | | | | |
| | |
| (1) | | The 2006 decrease and 20052008 increase in Exploration & Production’s total assets areis due primarily to the fluctuationsan increase in derivative assetsproperty, plant and equipment — net as a result of the impact of changes in commodity prices on existing derivative contracts. Exploration & Production’s derivatives are primarily comprised of intercompany transactions with the Power segment.increased drilling activity. |
| |
| (2) | | The 2006 decrease and 2005 increase in Power’sGas Marketing Services’ total assets arefor 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. Power’sGas Marketing Services’ derivative assets are substantially offset by their derivative liabilities. |
|
(3) | | The 2006 decrease and 2005 increase in Eliminations are due primarily to the fluctuations in the intercompany derivative balances. |
141138
THE WILLIAMS COMPANIES, INC.
(Unaudited)
Summarized quarterly financial data are as follows (millions, except per-share amounts).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First
| | Second
| | Third
| | Fourth
| | | First
| | Second
| | Third
| | Fourth
| |
| | | Quarter | | Quarter | | Quarter | | Quarter | | | Quarter | | Quarter | | Quarter | | Quarter | |
| |
2006 | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 3,027.5 | | | $ | 2,715.1 | | | $ | 3,300.0 | | | $ | 2,770.3 | | |
| Costs and operating expenses | | | 2,588.7 | | | | 2,273.8 | | | | 2,822.4 | | | | 2,288.7 | | |
| Income (loss) from continuing operations | | | 131.1 | | | | (63.9 | ) | | | 110.1 | | | | 155.5 | | |
| Net income (loss) | | | 131.9 | | | | (76.0 | ) | | | 106.2 | | | | 146.4 | | |
| Basic earnings per common share: | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations | | | .22 | | | | (.11 | ) | | | .19 | | | | .27 | | |
| Diluted earnings per common share: | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations | | | .22 | | | | (.11 | ) | | | .19 | | | | .25 | | |
2005 | | | | | | | | | | | | | | | | | |
2008 | | | | | | | | | | | | | | | | | |
| Revenues | | $ | 2,954.0 | | | $ | 2,871.2 | | | $ | 3,082.3 | | | $ | 3,676.1 | | | $ | 3,204 | | | $ | 3,701 | | | $ | 3,245 | | | $ | 2,202 | |
| Costs and operating expenses | | | 2,390.3 | | | | 2,491.6 | | | | 2,826.2 | | | | 3,162.9 | | | | 2,353 | | | | 2,719 | | | | 2,364 | | | | 1,720 | |
| Income from continuing operations | | | 202.2 | | | | 40.7 | | | | 5.7 | | | | 68.8 | | | | 416 | | | | 419 | | | | 369 | | | | 130 | |
| Income before cumulative effect of change in accounting principle | | | 201.1 | | | | 41.3 | | | | 4.4 | | | | 68.5 | | |
| Net income | | | 201.1 | | | | 41.3 | | | | 4.4 | | | | 66.8 | | | | 500 | | | | 437 | | | | 366 | | | | 115 | |
| Basic earnings per common share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | | | .36 | | | | .07 | | | | .01 | | | | .12 | | | | .71 | | | | .72 | | | | .63 | | | | .23 | |
| Income before cumulative effect of change in accounting principle | | | .36 | | | | .07 | | | | .01 | | | | .12 | | |
| Diluted earnings per common share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | | | .34 | | | | .07 | | | | .01 | | | | .11 | | | | .70 | | | | .70 | | | | .62 | | | | .23 | |
| Income before cumulative effect of change in accounting principle | | | .34 | | | | .07 | | | | .01 | | | | .11 | | |
2007 | | | | | | | | | | | | | | | | | |
| Revenues | | | $ | 2,348 | | | $ | 2,805 | | | $ | 2,844 | | | $ | 2,489 | |
| Costs and operating expenses | | | | 1,823 | | | | 2,161 | | | | 2,206 | | | | 1,817 | |
| Income from continuing operations | | | | 170 | | | | 243 | | | | 228 | | | | 206 | |
| Net income | | | | 134 | | | | 433 | | | | 198 | | | | 225 | |
| Basic earnings per common share: | | | | | | | | | | | | | | | | | |
| Income from continuing operations | | | | .28 | | | | .40 | | | | .38 | | | | .35 | |
| Diluted earnings per common share: | | | | | | | | | | | | | | | | | |
| Income from continuing operations | | | | .28 | | | | .40 | | | | .38 | | | | .34 | |
The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding and rounding.
Prior period amounts reported above have been adjusted to reflect the presentation of certain revenues and costs for Exploration & Production on a net basis. These adjustments reducedrevenuesand reducedcosts and operating expensesby the same amount, with no net impact on segment profit. The reductions were as follows (in millions):
| | | | | | | | | | | | | | | | | |
| | | First
| | | Second
| | | Third
| | | Fourth
| |
| | | Quarter | | | Quarter | | | Quarter | | | Quarter | |
| |
2008 | | $ | 20 | | | $ | 28 | | | $ | 22 | | | $ | 10 | |
2007 | | $ | 20 | | | $ | 19 | | | $ | 16 | | | $ | 17 | |
Net income (loss)for fourth quarter 2006fourth-quarter 2008 includes a $40 million reduction toboth the tax provision associated with a favorable U.S. Tax Court ruling, a $7.4 million increase tounfavorable impact of the tax provision associated with an adjustment to deferred income taxes (see Note 5)significant decline in energy commodity prices and the following pre-tax items:
| | |
| | • | A $16.4$129 million impairment of a Venezuelan cost-based investmentcertain natural gas producing properties at Exploration & Production (see Note 3); |
|
| • | A $14.7 million charge associated with an oil purchase contract related4 of Notes to our former Alaska refinery (see Note 2). |
Net income (loss)for third quarter 2006 includes the following pre-tax items:
| | |
| • | $12.7 million of income due to a reduction of contingent obligations at our former distributive power generation business at Power (see Note 4)Consolidated Financial Statements); |
| |
| | • | $10.643 million of expenseincome including associated interest related to an adjustmentthe partial settlement of an accounts payable accrualthe Gulf Liquids litigation at Midstream;Midstream (see Notes 4 and 16); |
| |
| | • | $638 million accrual for a loss contingencyWyoming 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 exploration businessAlaska operations (see summarized results of discontinued operations at Note 2);. |
142139
THE WILLIAMS COMPANIES, INC.
QUARTERLY FINANCIAL DATA — (Continued)
(Unaudited)
Net income (loss)for second quarter 2006fourth-quarter 2008 also includes a $46 million adjustment to decrease state income taxes (net of federal benefit) due to a reduction in our estimate of the effective deferred state rate (see Note 5).
Net incomefor third-quarter 2008 includes the following pre-tax items:
| | |
| | • | $160.714 million accrual related to our securities litigation settlementimpairment of certain natural gas producing properties at Other (see Note 15); |
|
| • | $88 million accrual for Gulf Liquids litigation contingency and associated interest expense at MidstreamExploration & Production (see Note 4); |
| |
| | • | $19.210 million accrual for an adverse arbitration award related to our former chemical fertilizer businessgain from the sale of certain south Texas assets at Gas Pipeline (see Note 2)4). |
Net income (loss)for the first quarter 2006second-quarter 2008 includes the following pre-tax items:
| | |
| | • | $2754 million premium and conversion expensesgain related to the convertible debenture conversionfavorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Other (see Note 12)2); |
| |
| | • | $23.730 million gain onrecognized upon receipt of the remaining proceeds related to the sale of a contractual right to a production payment on certain receivablesfuture international hydrocarbon production at Power;Exploration & Production (see Note 4); |
| |
| | • | $910 million of incomecharge associated with a settlement primarily related to the settlementsale of an international contract disputenatural gas liquids pipeline systems in 2002 (see summarized results of discontinued operations at Midstream;Note 2); |
| |
| | • | $710 million charge associated with the reversalan oil purchase contract related to our former Alaska refinery (see summarized results of an accrued litigation contingency due to a favorable court ruling and the related accrued interest incomediscontinued operations at our Gas Pipeline segment.Note 2). |
Net incomefor fourthfirst quarter 20052008 includes the following pre-tax items:
| | |
| • | $118 million gain on the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production (see Note 4); |
|
| • | $74 million gain related to the favorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Note 2); |
|
| • | $54 million of income related to a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank (see summarized results of discontinued operations at Note 2). |
Net incomefor fourth-quarter 2007 includes a $20.2$23 million reductionadjustment to increase the tax provision associated withrelating to an adjustment to deferred income taxes (see Note 5)tax contingency and the following pre-tax items:
| | |
| | • | $68.7156 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 PowerGas Marketing Services (see Note 4); |
| |
| | • | $38.119 million impairment of our investment in Longhorn at Other (see Note 3);premiums, fees and expenses related to early debt retirement; |
| |
| | • | $32.112 million chargeof income related to accounting and valuation corrections for certain inventory itemsa favorable litigation outcome at Gas PipelineMidstream (see Note 4); |
| |
| | • | $2310 million charge related to an impairment of our investment in Aux Sablethe Carbonate Trend pipeline at PowerMidstream (see Note 3)4); |
| |
| | • | $5.29 million accrualcharge related to the reserve for contingent refund obligationscertain international receivables at Gas PipelineMidstream; |
|
| • | $6 million net loss, including transaction expenses, related to the sale of our discontinued power business (see summarized results of discontinued operations at Note 4)2). |
140
THE WILLIAMS COMPANIES, INC.
QUARTERLY FINANCIAL DATA — (Continued)
(Unaudited)
Net incomefor third quarter 2005third-quarter 2007 includes the following pre-tax items:
| | |
| | • | $21.717 million gain onof expenses related to the sale of certain natural gas propertiesour discontinued power business (see summarized results of discontinued operations at Exploration & Production (see Note 4)2); |
| |
| | • | $14.212 million of income from the reversal of a liability due to resolution of litigation at Gas Pipeline; |
|
| • | $13.8 million increase in expense related to the settlement of certain insurance coverage issues associated with ERISA and securities litigation at Other.the payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral (see Note 4). |
Net incomefor second quarter 2005second-quarter 2007 includes the following pre-tax items:
| | |
| | • | $49.1429 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 investmentHazelton facility included in Longhorndiscontinued operations (see summarized results of discontinued operations at OtherNote 2); |
|
| • | $14 million of gains from the sales of cost-based investments (see Note 3); |
| |
| | • | $17.114 million reduction of expenseexpenses related to the sale of our discontinued power business (see summarized results of discontinued operations at Gas Pipeline to correct the overstatement of pension expense in prior periods (see Note 7)2); |
| |
| | • | $13.16 million accrualof income associated with the payments received for litigation contingencies at Powera terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral (see Note 4); |
|
| • | $8.6 million gain on sale of our remaining interests inMid-America Pipeline and Seminole Pipeline at Midstream.. |
Net incomefor first quarter 2005the first-quarter 2007 includes the following pre-tax items:
| | |
| | • | $13.18 million of income due to the reversal of certain prior period accrualsa planned major maintenance accrual at Gas Pipeline; |
|
| • | $7.9 million gain on sale of certain natural gas properties at Exploration & Production (see Note 4).Midstream. |
143141
THE WILLIAMS COMPANIES, INC.
(Unaudited)
The following information pertains to our oil and gas producing activities and is presented in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities.” The information is required to be disclosed by geographic region. We have significant oil and gas producing activities primarily in the Rocky Mountain and Mid-continent areas of the United States. Additionally, we have international oiloil- and gas producinggas-producing activities, primarily in Argentina. However, proved reserves and revenues related to international activities are approximately 4.23.6 percent and 4.32.3 percent, respectively, of our total international and domestic proved reserves and revenues. The following information relates only to the oil and gas activities in the United States.
Capitalized Costs
| | | | | | | | | | | | | | | | | |
| | | As of December 31, | | | As of December 31, | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Millions) | | | (Millions) | |
| |
| Proved properties | | $ | 5,026.6 | | | $ | 3,870.5 | | | $ | 8,099 | | | $ | 6,409 | |
| Unproved properties | | | 500.3 | | | | 503.1 | | | | 806 | | | | 542 | |
| | | | | | | | | | | |
| | | | 5,526.9 | | | | 4,373.6 | | | | 8,905 | | | | 6,951 | |
| Accumulated depreciation, depletion and amortization and valuation provisions | | | (1,259.9 | ) | | | (937.4 | ) | | | (2,353 | ) | | | (1,754 | ) |
| | | | | | | | | | | |
| Net capitalized costs | | $ | 4,267.0 | | | $ | 3,436.2 | | | $ | 6,552 | | | $ | 5,197 | |
| | | | | | | | | | | |
| | |
| | • | CapitalizedExcluded from capitalized costs include the cost ofare equipment and facilities forin support of oil and gas producing activities. Theseproduction of $726 million and $505 million, net, for 2008 and 2007, respectively. The capitalized cost amounts for 20062008 and 20052007 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 and related equipment and facilities (includingincluding uncompleted development well costs);costs; and successful exploratory wells and related equipment and facilities.wells. |
| |
| | • | Unproved properties consist primarily of acreage related to probable/possible reserves acquired through the Barrett acquisitiontransactions in 2001. The balance is unproved exploratory acreage.2001 and 2008. |
Costs Incurred
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended
| | | For the Year Ended
| |
| | | December 31, | | | December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | | | (Millions) | | | |
| |
| Acquisition | | $ | 84.0 | | | $ | 45.3 | | | $ | 17.2 | | | $ | 543 | | | $ | 82 | | | $ | 84 | |
| Exploration | | | 20.2 | | | | 8.3 | | | | 4.5 | | | | 38 | | | | 38 | | | | 20 | |
| Development | | | 1,172.5 | | | | 723.1 | | | | 419.2 | | | | 1,699 | | | | 1,374 | | | | 1,173 | |
| | | | | | | | | | | | | | | |
| | | $ | 1,276.7 | | | $ | 776.7 | | | $ | 440.9 | | | $ | 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 landleasehold and reserve acquisitions in the Fort Worth basin. The 2005 costs primarily consist of a land and reserve acquisition in the Fort Worth basin and an additional land acquisition in the Arkoma basin. The 2004 costs relate to land and reserve acquisitions in the San Juan Basin, Arkoma basin, and the Powder River basin. |
144142
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)
| | |
| | • | 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. |
Results of Operations
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, | | | For the Year Ended December 31, | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | | | (Millions) | | | |
| |
| Revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas revenues | | $ | 1,237.8 | | | $ | 1,072.4 | | | $ | 599.9 | | | $ | 2,644 | | | $ | 1,725 | | | $ | 1,238 | |
| Other revenues | | | 186.1 | | | | 143.3 | | | | 137.3 | | | | 405 | | | | 232 | | | | 109 | |
| | | | | | | | | | | | | | | |
| Total revenues | | | 1,423.9 | | | | 1,215.7 | | | | 737.2 | | | | 3,049 | | | | 1,957 | | | | 1,347 | |
| | | | | | | | | | | | | | | |
| Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Production costs | | | 308.5 | | | | 230.3 | | | | 165.4 | | | | 555 | | | | 360 | | | | 309 | |
| General & administrative | | | 111.1 | | | | 79.5 | | | | 58.3 | | | | 169 | | | | 144 | | | | 111 | |
| Exploration expenses | | | 18.4 | | | | 8.3 | | | | 4.5 | | | | 27 | | | | 21 | | | | 18 | |
| Depreciation, depletion & amortization | | | 351.1 | | | | 244.7 | | | | 183.4 | | | | 724 | | | | 523 | | | | 351 | |
| (Gains)/Losses on sales of interests in oil and gas properties | | | (.4 | ) | | | (30.8 | ) | | | 0.1 | | | | 1 | | | | (1 | ) | | | — | |
| Impairment of certain natural gas properties in the Arkoma basin | | | | 143 | | | | — | | | | — | |
| Other expenses | | | 136.1 | | | | 141.1 | | | | 115.2 | | | | 349 | | | | 198 | | | | 59 | |
| | | | | | | | | | | | | | | |
| Total costs | | | 924.8 | | | | 673.1 | | | | 526.9 | | | | 1,968 | | | | 1,245 | | | | 848 | |
| | | | | | | | | | | | | | | |
| Results of operations | | | 499.1 | | | | 542.6 | | | | 210.3 | | | | 1,081 | | | | 712 | | | | 499 | |
| Provision for income taxes | | | (174.5 | ) | | | (216.9 | ) | | | (81.4 | ) | | | (406 | ) | | | (273 | ) | | | (174 | ) |
| | | | | | | | | | | | | | | |
| Exploration and production net income | | $ | 324.6 | | | $ | 325.7 | | | $ | 128.9 | | | $ | 675 | | | $ | 439 | | | $ | 325 | |
| | | | | | | | | | | | | | | |
| | |
| | • | Results of operations for producing activities consist of all related domestic activities within the Exploration & Production reporting unit. Other expenses in 2005unit and 2004 include a $6 million and $16excludes the $148 million gain respectively, on salessale of securities associateda 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 a coal seam royalty trust.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 PowerGas 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 non-producingnonproducing activities include acquisition and disposition of other working interest and royalty interest gas and the movement of gas from the wellhead to the tailgate of the respective plants for sale to the PowerGas Marketing Services subsidiary or third partythird-party purchasers. In addition, other revenues include recognition of income from transactions which transferred certain non-operatingnonoperating benefits to a third party. |
143
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)
| | |
| | • | 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 acquisition, exploration and development costs. |
145
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)
| | |
| | • | Exploration costsexpenses 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. |
Proved Reserves
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Bcfe) | | | | | (Bcfe) | | | |
| |
| Proved reserves at beginning of period | | | 3,382 | | | | 2,986 | | | | 2,703 | | | | 4,143 | | | | 3,701 | | | | 3,382 | |
| Revisions | | | (113 | ) | | | (12 | ) | | | (70 | ) | | | (220 | ) | | | (106 | ) | | | (113 | ) |
| Purchases | | | 41 | | | | 28 | | | | 24 | | | | 31 | | | | 19 | | | | 41 | |
| Extensions and discoveries | | | 669 | | | | 615 | | | | 521 | | | | 791 | | | | 863 | | | | 669 | |
| Production | | | (277 | ) | | | (224 | ) | | | (191 | ) | |
| Wellhead production | | | | (406 | ) | | | (334 | ) | | | (277 | ) |
| Sale of minerals in place | | | (1 | ) | | | (11 | ) | | | (1 | ) | | | — | | | | — | | | | (1 | ) |
| | | | | | | | | | | | | | | |
| Proved reserves at end of period | | | 3,701 | | | | 3,382 | | | | 2,986 | | | | 4,339 | | | | 4,143 | | | | 3,701 | |
| | | | | | | | | | | | | | | |
| Proved developed reserves at end of period | | | 1,945 | | | | 1,643 | | | | 1,348 | | | | 2,456 | | | | 2,252 | | | | 1,945 | |
| | | | | | | | | | | | | | | |
| | |
| | • | The SEC defines proved oil and gas reserves(Rule 4-10(a) ofRegulation 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). |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is based on the estimated quantities of proved reserves and the year-end prices and costs. The average year endyear-end natural gas prices used in the following estimates were $4.81, $6.95,$4.41, $5.78, and $5.08$4.81 per MMcfe at December 31, 2006, 2005,2008, 2007, and 2004,2006, respectively. Future income tax expenses have been computed considering available carry forwards and credits and the appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by SFAS No. 69. Continuation of year-end economic conditions also is assumed. The calculation is
144
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)
based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs. Of the $3,070$3,772 million of future development costs, $1,041 million, $942 million and $540 million areapproximately 72 percent is estimated to be spent in 2007, 20082009, 2010 and 2009, respectively.2011.
146
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows
| | | | | | | | | | | | | | | | | |
| | | At December 31, | | | At December 31, | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Millions) | | | (Millions) | |
| |
| Future cash inflows | | $ | 17,821 | | | $ | 23,510 | | | $ | 19,127 | | | $ | 23,937 | |
| Less: | | | | | | | | | | | | | | | | |
| Future production costs | | | 5,207 | | | | 4,441 | | | | 5,516 | | | | 5,345 | |
| Future development costs | | | 3,070 | | | | 2,258 | | | | 3,772 | | | | 3,497 | |
| Future income tax provisions | | | 3,350 | | | | 6,128 | | | | 3,284 | | | | 5,416 | |
| | | | | | | | | | | |
| Future net cash flows | | | 6,194 | | | | 10,683 | | | | 6,555 | | | | 9,679 | |
| Less 10 percent annual discount for estimated timing of cash flows | | | 3,338 | | | | 5,402 | | | | 3,382 | | | | 4,876 | |
| | | | | | | | | | | |
| Standardized measure of discounted future net cash flows | | $ | 2,856 | | | $ | 5,281 | | | $ | 3,173 | | | $ | 4,803 | |
| | | | | | | | | | | |
Sources of Change in Standardized Measure of Discounted Future Net Cash Flows
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Standardized measure of discounted future net cash flows beginning of period | | $ | 5,281 | | | $ | 3,147 | | | $ | 3,349 | | | $ | 4,803 | | | $ | 2,856 | | | $ | 5,281 | |
| Changes during the year: | | | | | | | | | | | | | | | | | | | | | | | | |
| Sales of oil and gas produced, net of operating costs | | | (1,179 | ) | | | (1,222 | ) | | | (835 | ) | | | (2,091 | ) | | | (1,426 | ) | | | (1,179 | ) |
| Net change in prices and production costs | | | (4,052 | ) | | | 2,358 | | | | (306 | ) | | | (2,548 | ) | | | 2,019 | | | | (4,052 | ) |
| Extensions, discoveries and improved recovery, less estimated future costs | | | 647 | | | | 1,310 | | | | 787 | | | | 1,423 | | | | 2,163 | | | | 647 | |
| Development costs incurred during year | | | 881 | | | | 723 | | | | 419 | | | | 817 | | | | 738 | | | | 881 | |
| Changes in estimated future development costs | | | (1,022 | ) | | | (300 | ) | | | (696 | ) | | | (724 | ) | | | (931 | ) | | | (1,022 | ) |
| Purchase of reserves in place, less estimated future costs | | | 63 | | | | 78 | | | | 29 | | | | 55 | | | | 48 | | | | 63 | |
| Sales of reserves in place, less estimated future costs | | | (2 | ) | | | (31 | ) | | | (3 | ) | | | — | | | | — | | | | (2 | ) |
| Revisions of previous quantity estimates | | | (140 | ) | | | (28 | ) | | | (90 | ) | | | (395 | ) | | | (266 | ) | | | (140 | ) |
| Accretion of discount | | | 790 | | | | 488 | | | | 286 | | | | 714 | | | | 434 | | | | 790 | |
| Net change in income taxes | | | 1,468 | | | | (1,272 | ) | | | 182 | | | | 1,108 | | | | (1,108 | ) | | | 1,468 | |
| Other | | | 121 | | | | 30 | | | | 25 | | | | 11 | | | | 276 | | | | 121 | |
| | | | | | | | | | | | | | | |
| Net changes | | | (2,425 | ) | | | 2,134 | | | | (202 | ) | | | (1,630 | ) | | | 1,947 | | | | (2,425 | ) |
| | | | | | | | | | | | | | | |
| Standardized measure of discounted future net cash flows end of period | | $ | 2,856 | | | $ | 5,281 | | | $ | 3,147 | | | $ | 3,173 | | | $ | 4,803 | | | $ | 2,856 | |
| | | | | | | | | | | | | | | |
147145
THE WILLIAMS COMPANIES, INC.
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | ADDITIONS | | | | | | | |
| | | | | | Charged to
| | | | | | | | | | |
| | | Beginning
| | | Cost and
| | | | | | | | | Ending
| |
| | | Balance | | | Expenses | | | Other | | | Deductions | | | Balance | |
| | | (Millions) | |
| |
| Year ended December 31, 2006: | | | | | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable(a) | | $ | 86.6 | | | $ | 3.7 | | | $ | (65.6 | )(f) | | $ | 8.8 | (c) | | $ | 15.9 | |
| Price-risk management credit reserves(a) | | | 37.0 | | | | (6.1 | )(d) | | | (10.6 | )(e) | | | — | | | | 20.3 | |
| Processing plant major maintenance accrual(b) | | | 7.2 | | | | 1.6 | | | | — | | | | .9 | | | | 7.9 | |
| Year ended December 31, 2005: | | | | | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable(a) | | | 98.8 | | | | 3.5 | | | | — | | | | 15.7 | (c) | | | 86.6 | |
| Price-risk management credit reserves(a) | | | 26.4 | | | | (2.6 | )(d) | | | 13.2 | (e) | | | — | | | | 37.0 | |
| Processing plant major maintenance accrual(b) | | | 5.7 | | | | 1.5 | | | | — | | | | — | | | | 7.2 | |
| Year ended December 31, 2004: | | | | | | | | | | | | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable(a) | | | 112.2 | | | | (.8 | ) | | | — | | | | 12.6 | (c) | | | 98.8 | |
| Price-risk management credit reserves(a) | | | 39.8 | | | | (12.8 | )(d) | | | (.6 | )(e) | | | — | | | | 26.4 | |
| Processing plant major maintenance accrual(b) | | | 4.1 | | | | 1.6 | | | | — | | | | — | | | | 5.7 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | 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) | | Included inaccrued liabilitiesin 2006 andother liabilities and deferred income in 2005 and 2004.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. |
| |
(d)(e) | | Included inrevenues. |
| |
(e) | | Included inaccumulated other comprehensive loss. |
|
| (f) | | During 2006, $65.6$66 million in previously reserved Enron receivables were sold. |
|
| (g) | | Included inaccumulated other comprehensive loss. |
|
| (h) | | Included inaccrued liabilitiesin 2006. |
148146
| |
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
NoneNone.
| |
| Item 9A. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined inRules 13a-15(e) and15d-15(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our Disclosure Controlsdisclosure controls and procedures (as defined inRules 13a-15(e) and15d-15(e) of the Securities Exchange Act (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
See “Management’s report set forth above in Item 8, “Financial Statements and Supplementary Data.”
Report of Independent Registered Public Accounting Firm on Internal Control overOver Financial Reporting”Reporting
See report set forth above in Item 8, Financial“Financial Statements and Supplementary Data.”
Fourth Quarter 2006 Changes in Internal ControlControls Over Financial Reporting
There have been no changes during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal controlInternal Controls over financial reporting.
| |
| Item 9B. | Other Information |
None.
147
PART III
| |
| Item 10. | Directors, Executive Officers and Corporate Governance |
The information regarding our directors and nominees for director required by Item 401 ofRegulation S-K will be presented under the headings “Boardheading. “Proposal 1 — Election of Directors — Board Committees,” “Election of Directors,” and “Principal Accounting Fees and Services”Directors” in our Proxy Statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders to be held May 17, 200721, 2009 (Proxy Statement), which information is incorporated by reference herein.
149
Information regarding our executive officers required by Item 401(b) ofRegulation S-K is presented at the end of Part I herein and captioned “Executive Officers of the Registrant” as permitted by General Instruction G(3) toForm 10-K and Instruction 3 to Item 401(b) ofRegulation S-K.
Information required by Item 405 ofRegulation S-K will be included under the heading “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in our Proxy Statement, which information is incorporated by reference herein.
Information required by paragraphs (c)(3), (d)(4) and (d)(5) of Item 407 ofRegulation S-K will be included under the heading “Corporate Governance”Governance and Board Matters” in our Proxy Statement, which information inis incorporated by reference herein.
We have adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, and Controller, or persons performing similar functions. The Code of Ethics, together with our Corporate Governance Guidelines, the charters for each of our board committees, and our Code of Business Conduct applicable to all employees are available on our Internet website athttp://www.williams.com.We will provide, free of charge, a copy of our Code of Ethics or any of our other corporate documents listed above upon written request to our Corporate Secretary at Williams, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172. We intend to disclose any amendments to or waivers of the Code of Ethics on behalf of our Chief Executive Officer, Chief Financial Officer, Controller, and persons performing similar functions on our Internet website athttp://www.williams.comunder the Investor Relations caption, promptly following the date of any such amendment or waiver.
| |
| Item 11. | Executive Compensation |
The information required by Item 402 and paragraphs (e)(4) and (e)(5) of Item 407 ofRegulation S-K regarding executive compensation will be presented under the headings “Board of Directors,”“Compensation Discussion and Analysis” “Executive Compensation” “Compensation committee interlocks and insider participation,Other Information,” and “Compensation committee report”Committee Report on Executive Compensation” in our Proxy Statement, which information is incorporated by reference herein. Notwithstanding the foregoing, the information provided under the heading “Compensation Committee Report”Report on Executive Compensation” in our Proxy Statement is furnished and shall not be deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.
| |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information regarding securities authorized for issuance under equity compensation plans required by Item 201(d) ofRegulation S-K and the security ownership of certain beneficial owners and management required by Item 403 ofRegulation S-K will be presented under the headings “Equity Compensation Stock Plans” and “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated by reference herein.
| |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
The information regarding certain relationships and related transactions required by Item 404 and Item 407(a) ofRegulation S-K will be presented under the heading “Certain Relationships“Corporate Governance and Related Transactions” and “Corporate Governance”Board Matters” in our Proxy Statement, which information is incorporated by reference herein.
148
| |
| Item 14. | Principal AccountingAccountant Fees and Services |
The information regarding our principal accountant fees and services required by Item 9(e) of Schedule 14A will be presented under the heading “Principal Accountant Fees and Services” in our Proxy Statement, which information is incorporated by reference herein.
150
PART IV
| |
| Item 15. | Exhibits, Financial Statement Schedules |
(a) 1 and 2.
| | | | | |
| | | Page |
| |
| Covered by report of independent auditors: | | | | |
| 2008 | | | 81 | |
| 2007 | | | 82 | |
| 2008 | | | 83 | |
| 2008 | | | 84 | |
| | | 85 | |
| Schedule for each year in the three-year period ended December 31, 2008: | | | | |
| II — Valuation and qualifying accounts | | | 146 | |
| Not covered by report of independent auditors: | | | | |
| | | 142139 | |
| | | 144 | |
Schedule for each of the three years ended December 31, 2006:142 | | | | |
| | | 148 | |
All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.
(a) 3 and (b). The exhibits listed below are filed as part of this annual report.
INDEX TO EXHIBITS
| | | | | | |
Exhibit
| | | | |
No.
| | | | Description
|
|
| 3 | .1* | | — | | Restated Certificate of Incorporation, as supplemented (filed as Exhibit 3.1 to ourForm 10-K filed March 11, 2005). |
| 3 | .2* | | — | | Restated By-laws (filed as Exhibit 3.2 to ourForm 8-K filed January 31, 2007). |
| 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 as Exhibit 4.1 to ourForm S-3 filed September 8, 1997). |
| 4 | .2* | | — | | Form of Floating Rate Senior Note (filed as Exhibit 4.3 to ourForm S-3 filed September 8, 1997). |
| 4 | .3* | | — | | Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to ourForm S-3 filed September 8, 1997). |
| 4 | .4* | | — | | Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(j) toForm 10-K for the fiscal year ended December 31, 2000). |
| 4 | .5* | | — | | Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(k) to ourForm 10-K for the fiscal year ended December 31, 2000). |
| 4 | .6* | | — | | Sixth Supplemental Indenture dated January 14, 2002, between Williams and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to ourForm 8-K filed January 23, 2002). |
| 4 | .7* | | — | | Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to ourForm 10-Q filed May 9, 2002). |
| 4 | .8* | | — | | Form of Senior Debt Indenture between Williams Holdings of Delaware, Inc. and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Williams Holdings of Delaware, Inc.’s ourForm 10-Q filed October 18, 1995). |
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 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.’sForm 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.’sForm 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
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 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.’sForm 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 Pipeline’s 7.125% Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Form S-3) and incorporated herein by reference. |
| | 4 | .17 | | — | | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’sForm 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 Corporation’s Form 8-K) (Commission File number 001-07414) and incorporated herein by reference. |
150
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 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 Corporation’sForm 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 GP’sForm 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 GP’s 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 Corporation’s 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 Corporation’s Form S-3) and incorporated herein by reference. |
| | 4 | .24 | | — | | Indenture dated as of August 27, 2001 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on November 8, 2001 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-4) and incorporated herein by reference. |
| | 4 | .25 | | — | | Indenture dated as of July 3, 2002 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed August 14, 2002 as Exhibit 4.1 to The Williams Companies Inc.’s Form 10-Q) and incorporated herein by reference. |
| | 4 | .26 | | — | | Indenture dated 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 Corporation’s 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 Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. |
| | 4 | .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 Corporation’s 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 Corporation’s
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. |
151
| | | | | | |
Exhibit
| | | | |
No.
| | | | Description
|
|
| 4 | .9* | | — | | First Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Citibank, N.A., as Trustee (filed as Exhibit 4(o) toForm 10-K for the fiscal year ended December 31, 1999). |
| 4 | .10* | | — | | 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 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 toForm S-3 dated February 25, 1997). |
| 4 | .11* | | — | | 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.’sForm 10-K for the fiscal year ended December 31, 1997). |
| 4 | .12* | | — | | 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.’sForm 10-K for the fiscal year ended December 31, 1997). |
| 4 | .13* | | — | | 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.’sForm 10-K for the fiscal year ended December 31, 1998). |
| 4 | .14* | | — | | 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 as Exhibit 4(q) to ourForm 10-K for the fiscal year ended December 31, 1999). |
| 4 | .15* | | — | | Revised Form of Indenture between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee, with respect to Senior Notes including specimen of 7.55% Senior Notes (filed as Exhibit 4.1 to Barrett Resources Corporation’s Amendment No. 2 to our Registration Statement onForm S-3 filed February 10, 1997). |
| 4 | .16* | | — | | First Supplemental Indenture dated 2001, between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee (filed as Exhibit 4.3 to ourForm 10-Q filed November 13, 2001). |
| 4 | .17* | | — | | Second Supplemental Indenture dated as of August 2, 2001, among Barrett Resources Corporation, as Issuer, Resources Acquisition Corp., The Williams Companies, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.4 to ourForm 10-Q filed November 13, 2001). |
| 4 | .18* | | — | | Third Supplemental Indenture dated as of May 20, 2004 with respect to the Indenture dated as of February 1, 1997 between Barrett Resources Corporation(predecessor-in-interest to Williams Production RMT Company) and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee (filed as Exhibit 99.2 to ourForm 8-K filed May 20, 2004). |
| 4 | .19* | | — | | 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 as Exhibit 4.2 to ourForm 10-Q filed August 12, 2003). |
| 4 | .20* | | — | | 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 as Exhibit 4.1 to ourForm 8-K filed September 21, 2004. |
| 4 | .21* | | — | | Senior Indenture, dated as of August 1, 1992, between Northwest Pipeline Corporation and Continental Bank, N.A., Trustee with regard to Northwest Pipeline’s 9% Debentures, due 2022 (filed as Exhibit 4.1 to Northwest Pipeline’sForm S-3 filed July 2, 1992). |
| 4 | .22* | | — | | Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee with regard to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed as Exhibit 4.1 to Northwest Pipeline’sForm S-3 filed September 14, 1995) |
| 4 | .23* | | — | | Senior Indenture, dated as of December 8, 1997, between Northwest Pipeline Corporation and The Chase Manhattan Bank, Trustee with regard to Northwest Pipeline’s 6.625% Debentures, due 2007 (filed as Exhibit 4.1 to Northwest Pipeline’sForm S-3 filed September 8, 1997) |
| 4 | .24* | | — | | Indenture dated March 4, 2003, between Northwest Pipeline Corporation and JP Morgan Chase Bank, as Trustee (filed as Exhibit 4.1 to ourForm 10-Q filed May 13, 2003. |
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 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. |
152
| | | | | | | | | | | | | |
Exhibit
| Exhibit
| | | | | Exhibit
| | | | |
No. | No. | | | | Description | No. | | | | Description |
| |
| | 4 | .25* | | — | | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.a., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed as Exhibit 4.1 to Northwest Pipeline’sForm 8-K dated June 23, 2006). | 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. |
| | 4 | .26* | | — | | Senior Indenture dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm S-3 dated April 2, 1996) | 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. |
| | 4 | .27* | | — | | Senior Indenture dated as of January 16, 1998 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm S-3 dated September 8, 1997). | 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. |
| | 4 | .28* | | — | | Indenture dated as of August 27, 2001 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm S-4 dated November 8, 2001). | 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. |
| | 4 | .29* | | — | | Indenture dated as of July 3, 2002 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to The Williams Companies Inc.’sForm 10-Q for the quarterly period ended June 30, 2002). | 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. |
| | 4 | .30* | | — | | Indenture dated December 17, 2004 between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm 8-K filed December 21, 2004). | 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. |
| | 4 | .31* | | — | | Indenture dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4$ Senior Note due 2016 (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm 8-K dated April 11, 2006). | 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. |
| | 4 | .32* | | — | | Indenture dated June 20, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and JPMorgan Chase Bank, N.A. (filed as Exhibit 4.1 to Williams Partners L.P.Form 8-K filed June 20, 2006). | 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. |
| | 4 | .33* | | — | | Indenture dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed as Exhibit 4.1 to Williams Partners L.P. filed December 19, 2006). | 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 | .1* | | — | | The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 1988 (filed as Exhibit 10(iii)(c) to ourForm 10-K for the fiscal year ended December 31, 1987). | 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 | .2* | | — | | First Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of April 1, 1988 (filed as Exhibit 10.2 to ourForm 10-K for the fiscal year ended December 31, 2003). | 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. |
| | 10 | .3* | | — | | Second Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 2002 and January 1, 2003 (filed as Exhibit 10.3 to ourForm 10-K filed March, 11, 2005). | 12* | | | — | | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. |
| | 10 | .4* | | — | | The Williams Companies, Inc. Stock Plan for Non-Officer Employees (filed as Exhibit 10(iii)(g) to ourForm 10-K for the fiscal year ended December 31, 1995). | 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. |
| | 10 | .5* | | — | | The Williams Companies, Inc. 1996 Stock Plan (filed as Exhibit A to our Proxy Statement dated March 27, 1996). | 21* | | | — | | Subsidiaries of the registrant. |
| | 10 | .6* | | — | | The Williams Companies, Inc. 1996 Stock Plan for Non-employee Directors (filed as Exhibit B to our Proxy Statement dated March 27, 1996). | |
| | 10 | .7 | | — | | The Williams Companies, Inc. 2001 Stock Plan. | |
| | 10 | .8 | | — | | The Williams Companies, Inc. 2002 Incentive Plan for Non-Employee Director Stock Option Agreement. | |
| | 10 | .9* | | — | | Indemnification Agreement effective as of August 1, 1986, among Williams, members of the Board of Directors and certain officers of Williams (filed as Exhibit 10(iii)(e) to ourForm 10-K for the year ended December 31, 1986). | |
| | 10 | .10* | | — | | Form of Stock Option Secured Promissory Note and Pledge Agreement among Williams and certain employees, officers and non-employee directors (filed as Exhibit 10(iii)(m) to ourForm 10-K for the fiscal year ended December 31, 1998). | |
153
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 1023 | .11*.1* | | — | | FormConsent of 2004 Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 10.12 to ourForm 10-K filed March 11, 2005).Independent Registered Public Accounting Firm, Ernst & Young LLP. |
| | 1023 | .12*.2* | | — | | FormConsent of 2004 Performance-Based Deferred Stock Agreement among WilliamsIndependent Petroleum Engineers and executive officers filed as Exhibit 10.13 to ourForm 10-K filed March 11, 2005).Geologists, Netherland, Sewell & Associates, Inc. |
| | 1023 | .13*.3* | | — | | FormConsent of Stock Option Agreement among WilliamsIndependent Petroleum Engineers and certain employeesGeologists, Miller and officers (filed as Exhibit 99.1 to ourForm 8-K filed March 2, 2005).Lents, LTD. |
| | 1024* | .14* | | — | | FormPower of 2005 Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 99.2 to ourForm 8-K filed March 2, 2005).Attorney. |
| | 1031 | .15*.1* | | — | | FormCertification of 2005 Performance-Based Deferred Stock Agreement among Williamsthe Chief Executive Officer pursuant to Rules 13a-14(a) and executive officers.(filed15d-14(a) promulgated under the Securities Exchange Act of 1934, as Exhibit 99.3amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to ourForm 8-K filed March 2, 2005).Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 1031 | .16*.2* | | — | | FormCertification of 2006 Deferred Stock Agreement among Williamsthe Chief Financial Officer pursuant to Rules 13a-14(a) and certain employees15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and officers (filedItem 601(b)(31) of Regulation S-K, as Exhibit 99.1adopted pursuant to ourForm 8-K filed March 7, 2006).Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 1032* | .17* | | — | | Form of 2006 Stock Option Agreement among Williams and certain employees and officers (filed as Exhibit 99.2 to ourForm 8-K filed March 7, 2006). |
| 10 | .18* | | — | | Form of 2006 Performance-Based Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 99.3 to ourForm 8-K filed March 7, 2006). |
| 10 | .19* | | — | | The Williams Companies, Inc. 2001 Stock Plan (filed as Exhibit 4.1 to ourForm S-8 filed August 1, 2001). |
| 10 | .20* | | — | | The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed as Exhibit 10.1 to ourForm 10-Q filed on August 5, 2004). |
| 10 | .21* | | — | | Form of Change in Control Severance Agreement between the Company and certain executive officers (filed as Exhibit 10.12 to ourForm 10-Q filed November 14, 2002). |
| 10 | .22* | | — | | Settlement Agreement, by and among the GovernorCertification of the State of CaliforniaChief Executive Officer and the several other parties named therein and The Williams Companies, Inc. and Williams Energy Marketing & Trading Company dated November 11, 2002 (filedChief Financial Officer pursuant to 18 U.S.C. Section 1350, as Exhibit 10.79adopted pursuant to ourForm 10-K forSection 906 of the fiscal year ended December 31, 2002). |
| 10 | .23* | | — | | The Williams Companies, Inc. Severance Pay Plan as Amended and Restated Effective October 28, 2003. |
| 10 | .24* | | — | | Amendment to The Williams Companies, Inc. Severance Pay Plan dated October 28, 2003. |
| 10 | .25* | | — | | Amendment to The Williams Companies, Inc. Severance Pay Plan dated June 1, 2004. |
| 10 | .26* | | — | | Amendment to The Williams Companies, Inc. Severance Pay Plan dated January 1, 2005. |
| 10 | .27* | | — | | U.S. $500,000,000 Term Loan Agreement among Williams Production Holdings LLC, Williams Production RMT Company, as Borrower, the Several Lenders from time to time parties thereto, Lehman Brothers Inc. and BancSarbanes-Oxley Act of America Securities LLC as Joint Lead Arrangers, Citigroup USA, Inc. and JPMorgan Chase Bank, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.1 to ourForm 10-Q filed August 12, 2003). |
| 10 | .28* | | — | | The First Amendment to the Term Loan Agreement dated February 25, 2004, between Williams Production Holdings, LLC, Williams Production RMT Company, as Borrower, the several financial institutions as lenders and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.3 to ourForm 10-Q filed May 6, 2004). |
| 10 | .29* | | — | | Guarantee and Collateral Agreement made by Williams Production Holdings LLC, Williams Production RMT Company and certain of its Subsidiaries in favor of Lehman Commercial Paper Inc. as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.2 to ourForm 10-Q filed August 12, 2003). |
| 10 | .30* | | — | | U.S. $1,275,000,000 Amended and Restated Credit Agreement Dated as of May 20, 2005 among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, Williams Partners L.P., as Borrowers, Citicorp USA, Inc., As Administrative Agent and Collateral Agent, Citibank, N.A. Bank of America, N.A. as Issuing Banks and The Banks Named Herein as Banks (filed as Exhibit 1.1 to ourForm 8-K filed May 26, 2005).2002. |
154
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 10 | .31* | | — | | 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 as Exhibit 10.1 to ourform 8-K filed May 1, 2006). |
| | 10 | .32* | | — | | 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 as Exhibit 10.3 to ourForm 8-K filed on January 26, 2005). |
| | 10 | .33* | | — | | 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 as Exhibit 10.4 to ourForm 8-K filed on January 26, 2005). |
| | 10 | .34* | | — | | 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 as Exhibit 10.3 to ourForm 8-K filed on September 26, 2005). |
| | 10 | .35* | | — | | 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 as Exhibit 10.3 to ourForm 8-K filed on September 26, 2005). |
| | 10 | .36* | | — | | Assumption Agreement dated June 17, 2003 by and between The Williams Companies, Inc. and WEG Acquisitions, L.P. (filed as Exhibit 10.10 to ourForm 10-Q filed August 12, 2003). |
| | 10 | .37* | | — | | Agreement for the Release of Certain Indemnification Obligations dated as of May 26, 2004 by and among Magellan Midstream Holdings, L.P., Magellan G.P. LLC and Magellan Midstream Partners, L.P., on the one hand, and The Williams Companies, Inc., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and Williams GP LLC, on the other hand (filed as Exhibit 10.6 to ourForm 10-Q filed August 5, 2004). |
| | 10 | .38* | | — | | Master Professional Services Agreement dated as of June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation (filed as Exhibit 10.2 to ourForm 10-Q filed August 5, 2004). |
| | 10 | .39* | | — | | 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 as Exhibit 10.3 to ourForm 10-Q filed August 5, 2004). |
| | 10 | .40* | | — | | 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 (incorporated by reference to Exhibit 2.1 to Williams Partners L.P.’s current report onForm 8-K (File No. 1-32599) filed on November 21, 2006) filed as Exhibit 2.1 to ourForm 8-K filed November 22, 2006). |
| | 10 | .41 | | — | | 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. |
| | 12 | | | — | | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. |
| | 14* | | | — | | Code of Ethics (filed as Exhibit 14 toForm 10-K for the fiscal year ended December 31, 2003). |
| | 20* | | | — | | Definitive Proxy Statement of Williams for 2007 (to be filed with the Securities and Exchange Commission on or before April , 2007). |
| | 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. |
155
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 24 | | | — | | Power of Attorney together with certified resolution. |
| | 31 | .1 | | — | | Certification of the Chief Executive Officer pursuant toRules 13a-14(a) and15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) ofRegulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | 31 | .2 | | — | | Certification of the Chief Financial Officer pursuant toRules 13a-14(a) and15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) ofRegulation 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. |
| | |
| * | | Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.Filed herewith |
156154
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
The Williams Companies, Inc.
(Registrant)
| | |
| | By: | /s/ Brian K. ShoreTed T. Timmermans |
Brian K. ShoreTed T. Timmermans
Attorney-in-factController
Date: February 28, 200724, 2009
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | | | | |
Signature | | Title | | Date |
| |
| | | | |
/s/ Steven J. Malcolm*Malcolm
Steven J. Malcolm* | | President, Chief Executive Officer
and Chairman of the Board (Principal
(Principal Executive Officer) | | February 28, 200724, 2009 |
| | | | | |
/s/ Donald R. Chappel*Chappel
Donald R. Chappel* | | Senior Vice President and Chief
Financial Officer (Principal
(Principal Financial Officer) | | February 28, 200724, 2009 |
| | | | | |
/s/ Ted T. Timmermans*Timmermans
Ted T. Timmermans* | | Controller (Principal Accounting
Officer) | | February 28, 200724, 2009 |
| | | | | |
/s/ Kathleen B. Cooper*Joseph R. Cleveland*
Kathleen B. Cooper*Joseph R. Cleveland* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ Irl F. Engelhardt*Kathleen B. Cooper*
Irl F. Engelhardt*Kathleen B. Cooper* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ William R. Granberry*Irl F. Engelhardt*
William R. Granberry*Irl F. Engelhardt* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ William E. Green*R. Granberry*
William E. Green* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ Juanita H. Hinshaw*William E. Green*
Juanita H. Hinshaw*William E. Green* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ W.R. Howell*Juanita H. Hinshaw*
W.R. Howell*Juanita H. Hinshaw* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ Charles M. Lillis*W.R. Howell*
Charles M. Lillis*W.R. Howell* | | Director | | February 28, 2007 |
| | | | |
/s/ George A. Lorch*
George A. Lorch* | | Director | | February 28, 200724, 2009 |
157155
| | | | | | | |
Signature | | Title | | Date |
| |
| | | | |
/s/ William G. Lowrie*Charles M. Lillis*
William G. Lowrie*Charles M. Lillis* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ Frank T. Macinnis*George A. Lorch*
Frank T. Macinnis*George A. Lorch* | | Director | | February 28, 200724, 2009 |
| | | | | |
/s/ Janice D. Stoney*William G. Lowrie*
Janice D. Stoney*William G. Lowrie* | | Director | | February 28, 200724, 2009 |
| | | | |
/s/ Frank T. MacInnis*
Frank T. MacInnis* | | Director | | February 24, 2009 |
| | | | |
/s/ Janice D. Stoney*
Janice D. Stoney* | | Director | | February 24, 2009 |
| | | | | | | |
| *By: | | /s/ Brian K. ShoreLa Fleur C. Browne
Brian K. ShoreLa Fleur C. Browne
Attorney-in-Fact | | | | February 24, 2009 |
158156
INDEX TO EXHIBITS
| | | | | | |
Exhibit
| | | | |
No.
| | | | Description
|
|
| 3 | .1* | | — | | Restated Certificate of Incorporation, as supplemented (filed as Exhibit 3.1 to ourForm 10-K filed March 11, 2005). |
| 3 | .2* | | — | | Restated By-laws (filed as Exhibit 3.2 to ourForm 8-K filed January 31, 2007). |
| 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 as Exhibit 4.1 to ourForm S-3 filed September 8, 1997). |
| 4 | .2* | | — | | Form of Floating Rate Senior Note (filed as Exhibit 4.3 to ourForm S-3 filed September 8, 1997). |
| 4 | .3* | | — | | Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to ourForm S-3 filed September 8, 1997). |
| 4 | .4* | | — | | Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(j) toForm 10-K for the fiscal year ended December 31, 2000). |
| 4 | .5* | | — | | Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(k) to ourForm 10-K for the fiscal year ended December 31, 2000). |
| 4 | .6* | | — | | Sixth Supplemental Indenture dated January 14, 2002, between Williams and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to ourForm 8-K filed January 23, 2002). |
| 4 | .7* | | — | | Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to ourForm 10-Q filed May 9, 2002). |
| 4 | .8* | | — | | Form of Senior Debt Indenture between Williams Holdings of Delaware, Inc. and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Williams Holdings of Delaware, Inc.’s ourForm 10-Q filed October 18, 1995). |
| 4 | .9* | | — | | First Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Citibank, N.A., as Trustee (filed as Exhibit 4(o) toForm 10-K for the fiscal year ended December 31, 1999). |
| 4 | .10* | | — | | 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 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 toForm S-3 dated February 25, 1997). |
| 4 | .11* | | — | | 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.’sForm 10-K for the fiscal year ended December 31, 1997). |
| 4 | .12* | | — | | 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.’sForm 10-K for the fiscal year ended December 31, 1997). |
| 4 | .13* | | — | | 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.’sForm 10-K for the fiscal year ended December 31, 1998). |
| 4 | .14* | | — | | 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 as Exhibit 4(q) to ourForm 10-K for the fiscal year ended December 31, 1999). |
| 4 | .15* | | — | | Revised Form of Indenture between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee, with respect to Senior Notes including specimen of 7.55% Senior Notes (filed as Exhibit 4.1 to Barrett Resources Corporation’s Amendment No. 2 to our Registration Statement onForm S-3 filed February 10, 1997). |
| 4 | .16* | | — | | First Supplemental Indenture dated 2001, between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee (filed as Exhibit 4.3 to ourForm 10-Q filed November 13, 2001). |
| 4 | .17* | | — | | Second Supplemental Indenture dated as of August 2, 2001, among Barrett Resources Corporation, as Issuer, Resources Acquisition Corp., The Williams Companies, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.4 to ourForm 10-Q filed November 13, 2001). |
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 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.’sForm 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.’sForm 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. |
| | | | | | |
Exhibit
| | | | |
No.
| | | | Description
|
|
| 4 | .18* | | — | | Third Supplemental Indenture dated as of May 20, 2004 with respect to the Indenture dated as of February 1, 1997 between Barrett Resources Corporation(predecessor-in-interest to Williams Production RMT Company) and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee (filed as Exhibit 99.2 to ourForm 8-K filed May 20, 2004). |
| 4 | .19* | | — | | 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 as Exhibit 4.2 to ourForm 10-Q filed August 12, 2003). |
| 4 | .20* | | — | | 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 as Exhibit 4.1 to ourForm 8-K filed September 21, 2004. |
| 4 | .21* | | — | | Senior Indenture, dated as of August 1, 1992, between Northwest Pipeline Corporation and Continental Bank, N.A., Trustee with regard to Northwest Pipeline’s 9% Debentures, due 2022 (filed as Exhibit 4.1 to Northwest Pipeline’sForm S-3 filed July 2, 1992). |
| 4 | .22* | | — | | Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee with regard to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed as Exhibit 4.1 to Northwest Pipeline’sForm S-3 filed September 14, 1995). |
| 4 | .23* | | — | | Senior Indenture, dated as of December 8, 1997, between Northwest Pipeline Corporation and The Chase Manhattan Bank, Trustee with regard to Northwest Pipeline’s 6.625% Debentures, due 2007 (filed as Exhibit 4.1 to Northwest Pipeline’sForm S-3 filed September 8, 1997). |
| 4 | .24* | | — | | Indenture dated March 4, 2003, between Northwest Pipeline Corporation and JP Morgan Chase Bank, as Trustee (filed as Exhibit 4.1 to ourForm 10-Q filed May 13, 2003. |
| 4 | .25* | | — | | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.a., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed as Exhibit 4.1 to Northwest Pipeline’sForm 8-K dated June 23, 2006). |
| 4 | .26* | | — | | Senior Indenture dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm S-3 dated April 2, 1996). |
| 4 | .27* | | — | | Senior Indenture dated as of January 16, 1998 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm S-3 dated September 8, 1997). |
| 4 | .28* | | — | | Indenture dated as of August 27, 2001 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm S-4 dated November 8, 2001). |
| 4 | .29* | | — | | Indenture dated as of July 3, 2002 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to The Williams Companies Inc.’sForm 10-Q for the quarterly period ended June 30, 2002). |
| 4 | .30* | | — | | Indenture dated December 17, 2004 between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm 8-K filed December 21, 2004). |
| 4 | .31* | | — | | Indenture dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4$ Senior Note due 2016 (filed as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’sForm 8-K dated April 11, 2006). |
| 4 | .32* | | — | | Indenture dated June 20, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and JPMorgan Chase Bank, N.A. (filed as Exhibit 4.1 to Williams Partners L.P.Form 8-K filed June 20, 2006). |
| 4 | .33* | | — | | Indenture dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed as Exhibit 4.1 to Williams Partners L.P. filed December 19, 2006). |
| 10 | .1* | | — | | The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 1988 (filed as Exhibit 10(iii)(c) to ourForm 10-K for the fiscal year ended December 31, 1987). |
| | | | | | | |
Exhibit
| | | | |
No. | | | | Description |
| |
| | 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.’sForm 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 Pipeline’s 7.125% Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Form S-3) and incorporated herein by reference. |
| | 4 | .17 | | — | | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’sForm 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 Corporation’s 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 GP’sForm 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 GP’s 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 Corporation’s 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 Corporation’s 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 Corporation’s 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 Corporation’s 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 Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. |
| | 4 | .27 | | — | | Indenture dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K) and incorporated herein by reference. |
| | 4 | .28 | | — | | Registration Rights Agreement, dated as of May 22, 2008, among Transcontinental Gas Pipe Line Corporation and Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J. P. Morgan Securities Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed on May 23, 2008 as Exhibit 10.1 to Transcontinental Gas Pipe Line Corporation’s
Form 8-K) and incorporated herein by reference. |
| | 4 | .29 | | — | | Indenture dated June 20, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and JPMorgan Chase Bank, N.A. (filed on June 20, 2006 as Exhibit 4.1 to Williams Partners L.P. Form 8-K) and incorporated herein by reference. |
| | | | | | | | | | | | | |
Exhibit
| Exhibit
| | | | | Exhibit
| | | | |
No. | No. | | | | Description | No. | | | | Description |
| |
| | 10 | .2* | | — | | First Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of April 1, 1988 (filed as Exhibit 10.2 to ourForm 10-K for the fiscal year ended December 31, 2003). | 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 | .3* | | — | | Second Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 2002 and January 1, 2003 (filed as Exhibit 10.3 to ourForm 10-K filed March, 11, 2005). | 10 | .1* | | — | | The Williams Companies Amended and Restated Retirement Restoration Plan effective January 1, 2008. |
| | 10 | .4* | | — | | The Williams Companies, Inc. Stock Plan for Non-Officer Employees (filed as Exhibit 10(iii)(g) to ourForm 10-K for the fiscal year ended December 31, 1995). | 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 | .5* | | — | | The Williams Companies, Inc. 1996 Stock Plan (filed as Exhibit A to our Proxy Statement dated March 27, 1996). | 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 | .6* | | — | | The Williams Companies, Inc. 1996 Stock Plan for Non-employee Directors (filed as Exhibit B to our Proxy Statement dated March 27, 1996). | 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 | .7 | | — | | The Williams Companies, Inc. 2001 Stock Plan. | 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 | .8 | | — | | The Williams Companies, Inc. 2002 Incentive Plan for Non-Employee Director Stock Option Agreement. | 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 | .9* | | — | | Indemnification Agreement effective as of August 1, 1986, among Williams, members of the Board of Directors and certain officers of Williams (filed as Exhibit 10(iii)(e) to ourForm 10-K for the year ended December 31, 1986). | 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 | .10* | | — | | Form of Stock Option Secured Promissory Note and Pledge Agreement among Williams and certain employees, officers and non-employee directors (filed as Exhibit 10(iii)(m) to ourForm 10-K for the fiscal year ended December 31, 1998). | 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 | .11* | | — | | Form of 2004 Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 10.12 to ourForm 10-K filed March 11, 2005). | 10 | .9* | | — | | Form of 2008 Restricted Stock Unit Agreement among Williams and non-management directors. |
| | 10 | .12* | | — | | Form of 2004 Performance-Based Deferred Stock Agreement among Williams and executive officers filed as Exhibit 10.13 to ourForm 10-K filed March 11, 2005). | 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 | .13* | | — | | Form of Stock Option Agreement among Williams and certain employees and officers (filed as Exhibit 99.1 to ourForm 8-K filed March 2, 2005). | 10 | .11* | | — | | Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan. |
| | 10 | .14* | | — | | Form of 2005 Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 99.2 to ourForm 8-K filed March 2, 2005). | 10 | .12* | | — | | Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan. |
| | 10 | .15* | | — | | Form of 2005 Performance-Based Deferred Stock Agreement among Williams and executive officers.(filed as Exhibit 99.3 to ourForm 8-K filed March 2, 2005). | 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 | .16* | | — | | Form of 2006 Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 99.1 to ourForm 8-K filed March 7, 2006). | 10 | .14* | | — | | Amendment No. 1 to The Williams Companies, Inc. 2007 Incentive Plan. |
| | 10 | .17* | | — | | Form of 2006 Stock Option Agreement among Williams and certain employees and officers (filed as Exhibit 99.2 to ourForm 8-K filed March 7, 2006). | 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 | .18* | | — | | Form of 2006 Performance-Based Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 99.3 to ourForm 8-K filed March 7, 2006). | 10 | .16* | | — | | Amendment No. 1 to The Williams Companies, Inc. Employee Stock Purchase Plan. |
| | 10 | .19* | | — | | The Williams Companies, Inc. 2001 Stock Plan (filed as Exhibit 4.1 to ourForm S-8 filed August 1, 2001). | 10 | .17* | | — | | Amendment No. 2 to The Williams Companies, Inc. Employee Stock Purchase Plan. |
| | 10 | .20* | | — | | The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed as Exhibit 10.1 to ourForm 10-Q filed on August 5, 2004). | 10 | .18* | | — | | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers. |
| | 10 | .21* | | — | | Form of Change in Control Severance Agreement between the Company and certain executive officers (filed as Exhibit 10.12 to ourForm 10-Q filed November 14, 2002). | 10 | .19* | | — | | The Williams Companies, Inc. Severance Pay Plan. |
| | 10 | .22* | | — | | Settlement Agreement, by and among the Governor of the State of California and the several other parties named therein and The Williams Companies, Inc. and Williams Energy Marketing & Trading Company dated November 11, 2002 (filed as Exhibit 10.79 to ourForm 10-K for the fiscal year ended December 31, 2002). | 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 | .23* | | — | | The Williams Companies, Inc. Severance Pay Plan as Amended and Restated Effective October 28, 2003. | 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 | .24* | | — | | Amendment to The Williams Companies, Inc. Severance Pay Plan dated October 28, 2003. | |
| | 10 | .25* | | — | | Amendment to The Williams Companies, Inc. Severance Pay Plan dated June 1, 2004. | |
| | 10 | .26* | | — | | Amendment to The Williams Companies, Inc. Severance Pay Plan dated January 1, 2005. | |
| | | | | | |
Exhibit
| | | | |
No.
| | | | Description
|
|
| 10 | .27* | | — | | U.S. $500,000,000 Term Loan Agreement among Williams Production Holdings LLC, Williams Production RMT Company, as Borrower, the Several Lenders from time to time parties thereto, Lehman Brothers Inc. and Banc of America Securities LLC as Joint Lead Arrangers, Citigroup USA, Inc. and JPMorgan Chase Bank, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.1 to ourForm 10-Q filed August 12, 2003). |
| 10 | .28* | | — | | The First Amendment to the Term Loan Agreement dated February 25, 2004, between Williams Production Holdings, LLC, Williams Production RMT Company, as Borrower, the several financial institutions as lenders and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.3 to ourForm 10-Q filed May 6, 2004). |
| 10 | .29* | | — | | Guarantee and Collateral Agreement made by Williams Production Holdings LLC, Williams Production RMT Company and certain of its Subsidiaries in favor of Lehman Commercial Paper Inc. as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.2 to ourForm 10-Q filed August 12, 2003). |
| 10 | .30* | | — | | U.S. $1,275,000,000 Amended and Restated Credit Agreement Dated as of May 20, 2005 among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, Williams Partners L.P., as Borrowers, Citicorp USA, Inc., As Administrative Agent and Collateral Agent, Citibank, N.A. Bank of America, N.A. as Issuing Banks and The Banks Named Herein as Banks (filed as Exhibit 1.1 to ourForm 8-K filed May 26, 2005). |
| 10 | .31* | | — | | 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 as Exhibit 10.1 to ourform 8-K filed May 1, 2006). |
| 10 | .32* | | — | | 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 as Exhibit 10.3 to ourForm 8-K filed on January 26, 2005). |
| 10 | .33* | | — | | 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 as Exhibit 10.4 to ourForm 8-K filed on January 26, 2005). |
| 10 | .34* | | — | | 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 as Exhibit 10.3 to ourForm 8-K filed on September 26, 2005). |
| 10 | .35* | | — | | 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 as Exhibit 10.3 to ourForm 8-K filed on September 26, 2005). |
| 10 | .36* | | — | | Assumption Agreement dated June 17, 2003 by and between The Williams Companies, Inc. and WEG Acquisitions, L.P. (filed as Exhibit 10.10 to ourForm 10-Q filed August 12, 2003). |
| 10 | .37* | | — | | Agreement for the Release of Certain Indemnification Obligations dated as of May 26, 2004 by and among Magellan Midstream Holdings, L.P., Magellan G.P. LLC and Magellan Midstream Partners, L.P., on the one hand, and The Williams Companies, Inc., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and Williams GP LLC, on the other hand (filed as Exhibit 10.6 to ourForm 10-Q filed August 5, 2004). |
| 10 | .38* | | — | | Master Professional Services Agreement dated as of June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation (filed as Exhibit 10.2 to ourForm 10-Q filed August 5, 2004). |
| 10 | .39* | | — | | 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 as Exhibit 10.3 to ourForm 10-Q filed August 5, 2004). |
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Exhibit
| | | | |
No. | | | | Description |
| |
| | 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. |
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Exhibit
| Exhibit
| | | | | Exhibit
| | | | |
No. | No. | | | | Description | No. | | | | Description |
| |
| | 10 | .40* | | — | | 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 (incorporated by reference to Exhibit 2.1 to Williams Partners L.P.’s current report onForm 8-K (File No. 1-32599) filed on November 21, 2006) filed as Exhibit 2.1 to ourForm 8-K filed November 22, 2006). | 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. |
| | 10 | .41 | | — | | 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. | 12* | | | — | | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. |
| | 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. |
| | 14* | | | — | | Code of Ethics (filed as Exhibit 14 toForm 10-K for the fiscal year ended December 31, 2003). | 21* | | | — | | Subsidiaries of the registrant. |
| | 20* | | | — | | Definitive Proxy Statement of Williams for 2007 (to be filed with the Securities and Exchange Commission on or before April , 2007). | 23 | .1* | | — | | Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. |
| | 21 | | | — | | Subsidiaries of the registrant. | 23 | .2* | | — | | Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. |
| | 23 | .1 | | — | | Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. | 23 | .3* | | — | | Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. |
| | 23 | .2 | | — | | Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | 24* | | | — | | Power of Attorney. |
| | 23 | .3 | | — | | Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | 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. |
| | 24 | | | — | | Power of Attorney together with certified resolution. | 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. |
| | 31 | .1 | | — | | Certification of the Chief Executive Officer pursuant toRules 13a-14(a) and15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) ofRegulation 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. |
| | 31 | .2 | | — | | Certification of the Chief Financial Officer pursuant toRules 13a-14(a) and15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) ofRegulation 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. | |
| | |
| * | | Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.Filed herewith |
