exv99w1

Exhibit 99.1

Item 6. Selected Financial Data

The following financial data at 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 the other financial information included in this Exhibit 99.1 of this Form 8-K. All other financial data has been prepared from our accounting records.


	2008		2007		2006			2005			2004
	(Millions, except per-share amounts)
Revenues (1)	$	12,352	$	10,486	$	9,299		$	9,690		$	8,343
Income from continuing operations (2)		1,508		937		387			499			170
Income (loss) from discontinued operations (3)		84		143		(38	)		(157	)		15
Cumulative effect of change in accounting principles (4)		—		—		—			(2	)		—
Amounts attributable to The Williams Companies Inc.:
Income from continuing operations		1,334		847		347			473			149
Income (loss) from discontinued operations		84		143		(38	)		(157	)		15
Cumulative effect of change in accounting principles		—		—		—			(2	)		—
Diluted earnings (loss) per common share:
Income from continuing operations		2.26		1.40		.57			.79			.28
Income (loss) from discontinued operations		.14		.23		(.06	)		(.26	)		.03
Total assets at December 31		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		196		143		392			123			250
Long-term debt at December 31		7,683		7,757		7,622			7,591			7,712
Stockholders’ equity at December 31		8,440		6,375		6,073			5,427			4,956
Cash dividends declared per common share		.43		.39		.345			.25			.08


(1)		Prior period amounts reported for Exploration & Production have been adjusted to reflect the presentation of certain revenues and costs on a net basis. These adjustments reduced revenues and reduced costs and operating expenses by the same amount, with no net impact on segment profit. The reductions were $72 million in 2007, $77 million in 2006, $91 million in 2005 and $65 million in 2004.

(2)		See Note 4 of Notes to Consolidated Financial Statements for discussion of asset sales, impairments, and other accruals in 2008, 2007, and 2006. Income from continuing operations for 2005 includes an $82 million charge for litigation contingencies and a $110 million charge for impairments of certain equity investments. Income from continuing operations for 2004 includes $94 million of income from a favorable arbitration award and $282 million of early debt retirement costs.

(3)		See Note 2 of Notes to Consolidated Financial Statements for the analysis of the 2008, 2007, and 2006 income (loss) from discontinued operations. The discontinued operations results for 2005 includes our former power business while 2004 includes the power business, the Canadian straddle plants, and the Alaska refining, retail, and pipeline operations.

(4)		The 2005 cumulative effect of change in accounting principles is due to the implementation of Financial Accounting Standards Board (FASB) Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations — an Interpretation of FASB statement No. 143 (SFAS No. 143).”

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. Our operations are located principally in the United States and are organized into the following reporting segments: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids (Midstream), and Gas Marketing Services. (See Note 1 of Notes to Consolidated Financial Statements included in Item 8 of this Exhibit 99.1 and Part I Item 1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, for further discussion of these segments.)

Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Item 8 of this Exhibit 99.1.

Overview of 2008

Our plan for 2008 was focused on continued disciplined growth. Objectives and highlights of this plan included:


Objectives		Highlights

Continuing to improve both EVA^® and segment profit.		2008 segment profit of $2.9 billion, an increase of $749 million from 2007, contributed to improving our EVA^®.

Continuing to increase natural gas production and reserves.		We invested $2.5 billion in capital expenditures in Exploration & Production, increasing average daily domestic production by approximately 20 percent over last year while adding 602 billion cubic feet equivalent in net reserves. Total year-end 2008 proved domestic natural gas reserves are 4.3 trillion cubic feet equivalent, up 5 percent from year-end 2007 reserves.

Increasing the scale of our gathering and processing business in key growth basins.		We invested $608 million in capital expenditures in Midstream, primarily Deepwater Gulf expansion projects and gas-processing capacity in the western United States.

Continue to invest in expansion projects on our interstate natural gas pipelines.		We invested $306 million in capital expenditures in Gas Pipeline during 2008.

Our 2008 income from continuing operations attributable to The Williams Companies, Inc., increased to $1.3 billion, as compared to $847 million in 2007. Our net cash provided by operating activities was almost $3.4 billion in 2008 compared to $2.2 billion in 2007.

While these annual measures are favorable compared to the prior year, the overall trend of results was significantly different when considering the first three quarters of the 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 prices, while our Midstream business realized higher margins from a favorable energy commodity price environment. However, energy commodity prices declined sharply during the 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.

See additional discussion in Results of Operations.

Other Significant 2008 Events

We completed our stock repurchase program by reaching the $1 billion limit authorized by our Board of Directors. (See Note 12 of Notes to Consolidated Financial Statements.)

Exploration & 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 Operations — Segments, Exploration & Production.

We recognized pre-tax income of $183 million in income from discontinued operations related to our former Alaska operations. (See Note 2 of Notes to Consolidated Financial Statements.)

Exploration & Production recognized pre-tax income of $148 million related to the sale of a contractual right to a production payment on certain future 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.

The overall decline in 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 7 of Notes to Consolidated Financial Statements.)

Subsequent Events

For our first-quarter 2009 reporting, we recognized a net charge attributable to The Williams Companies, Inc., of $241 million related to our Venezuela operations. In May 2009, the Venezuelan government seized the assets of our majority-owned entities in Venezuela. (See Note 19 of Notes to Consolidated Financial Statements.)

Outlook for 2009

We 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 2009 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 completing major projects, meeting legal, regulatory, and/or contractual commitments, and maintaining a reduced level of natural 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;

	•		Continuing to invest in our natural gas production development, although at a lower level than in recent years;

	•		Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions, as well as seizing attractive opportunities.

Potential risks and/or obstacles that could impact the execution of our plan include:

	•		Lower than anticipated commodity prices;

	•		Lower than expected levels of cash flow from operations;

	•		Availability of capital;

	•		Counterparty credit and performance risk;

	•		Decreased drilling success at Exploration & Production;

	•		Decreased drilling success or abandonment of projects by third parties served by Midstream and Gas Pipeline;

	•		Additional general economic, financial markets, or industry downturn;

	•		Changes in the political and regulatory environments;

	•		Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 16 of Notes to Consolidated Financial Statements).

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 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.

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.

Accounting Pronouncements Issued But Not Yet Adopted

Accounting pronouncements that have been issued but not yet adopted may have an effect on our Consolidated Financial Statements in the future.

See Recent Accounting Standards in Note 1 of Notes to Consolidated Financial Statements for further information on 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:

	•		Expanding the definition of oil and gas reserves and providing clarification of certain concepts and technologies used in the reserve estimation process.

	•		Allowing optional disclosure of probable and possible reserves and permitting optional disclosure of price sensitivity analysis.

	•		Modifying prices used to estimate reserves for SEC disclosure purposes to a 12-month average price instead of a single-day, period-end price.

	•		Requiring certain additional disclosures around proved undeveloped reserves, internal controls used to ensure objectivity of the estimation process, and qualifications of those preparing and/or auditing the reserves.

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 No. 69, “Disclosures about Oil and Gas Producing Activities” (SFAS No. 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 No. 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.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have discussed the following accounting estimates and assumptions as well as related disclosures with our Audit Committee. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Impairments of Long-Lived Assets and Goodwill

We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that may include the estimated fair value of the asset, undiscounted future cash flows, discounted future cash flows, and the current and future economic environment in which the asset is operated.

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 judgments and/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.

We also perform interim assessments of goodwill if impairment triggering events or circumstances are present. Examples of impairment triggering events or circumstances include:

	•		The testing for recoverability of a significant long-lived asset group within the reporting unit;

	•		Recent operating losses or negative cash flows at the reporting unit level;

	•		A decline in natural gas prices or reserve quantities;

	•		Not meeting internal forecasts, or downward adjustments to future forecasts;

	•		A decline in enterprise market capitalization below our consolidated stockholders’ equity;

	•		Industry trends.

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 review our energy contracts to determine whether they are, or contain derivatives. We further assess the appropriate accounting method for any derivatives identified, which could include:

	•		Qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings;

	•		Qualifying for and electing accrual accounting under the normal purchases and normal sales exception, or;

	•		Applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings.

If cash flow hedge accounting or accrual accounting is not applied, a derivative is subject to mark-to-market accounting. Determination of the accounting method involves significant judgments and assumptions, which are further described below.

The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in offsetting the cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur, and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.

For derivatives designated as cash flow hedges, we must periodically assess whether they continue to qualify for hedge accounting. We prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we reclassify amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting the cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.

Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand, and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.

Since our energy derivative contracts could be accounted for in three different ways, two of which are elective, our accounting method could be different from that used by another party for a similar transaction. Furthermore, the accounting method may influence the level of volatility in the financial statements associated with changes in the fair value of derivatives, as generally depicted below:


	Consolidated Statement of Income		Consolidated Balance Sheet
Accounting Method	Drivers	Impact	Drivers	Impact

Accrual Accounting	Realizations	Less Volatility	None	No Impact

Cash Flow Hedge Accounting	Realizations & Ineffectiveness	Less Volatility	Fair Value Changes	More Volatility

Mark-to-Market Accounting	Fair Value Changes	More Volatility	Fair Value Changes	More Volatility

Our determination of the accounting method does not impact our cash flows related to derivatives.

Additional discussion of the accounting for energy contracts at fair value is included in Notes 1 and 15 of Notes to Consolidated Financial Statements.

Oil- and Gas-Producing Activities

We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:

•

An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates.

•

Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses, including that for goodwill.

The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering, and economic data. After being estimated internally, 99 percent of our reserve estimates are either audited or prepared by independent experts. (See Part I Item 1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, for further discussion.) The data may change substantially over time as a result of numerous factors, including additional development cost and activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. Such changes could trigger an impairment of our oil- and gas-producing properties and/or goodwill and have an impact on our depletion expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $46 million and $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. Significant unfavorable changes in the forward price curve could result in an impairment of our oil and gas properties and/or goodwill.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 16 of Notes to Consolidated Financial Statements.

Valuation of Deferred Tax Assets and Tax Contingencies

We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of the book basis and from tax carry-forwards generated in the current and prior years. We must evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. At December 31, 2008, we have $639 million of deferred tax assets for which a $15 million valuation allowance has been established. When assessing the need for a valuation allowance, we consider forecasts of future company performance, the estimated impact of potential asset dispositions and our ability and intent to execute tax planning strategies to utilize tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.

We regularly face challenges from domestic and foreign tax authorities regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. We evaluate the liability associated with our various filing positions by applying the two step process of recognition and measurement as required by FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The ultimate disposition of these contingencies could have a significant impact on 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. Net periodic benefit expense and obligations are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute expense and the benefit obligations are shown in Note 7 of Notes to Consolidated Financial Statements. The following table presents the estimated increase (decrease) in net periodic benefit expense and obligations resulting from a one-percentage-point change in the specified assumption.


	Benefit Expense						Benefit Obligation
	One-Percentage-			One-Percentage-			One-Percentage-			One-Percentage-
	Point Increase			Point Decrease			Point Increase			Point Decrease
	(Millions)
Pension benefits:
Discount rate	$	(13	)	$	14		$	(133	)	$	154
Expected long-term rate of return on plan assets		(7	)		7			—			—
Rate of compensation increase		3			(3	)		17			(17	)
Other postretirement benefits:
Discount rate		(2	)		2			(32	)		37
Expected long-term rate of return on plan assets		(1	)		1			—			—
Assumed health care cost trend rate		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 capital market projections for the asset classifications in which the portfolio is invested as well as the weightings of each asset classification. The 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 of return are long-term in nature and are not significantly impacted by short-term market swings. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 7.75 percent for 2006 through 2008 and 8.5 percent for 2003 through 2005. Over the past ten years, our actual average return on plan assets for our pension plans has been approximately 2.1 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 rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related expense. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 7 of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term high-quality debt securities as well as by the duration of our plans’ liabilities.

The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and expense to increase.

The assumed health care cost trend rates are based on 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.

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 of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the 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, in other 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.

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, 2008. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Years Ended December 31,
				$ Change		% Change						$ Change		% Change
				from		from						from		from
	2008			2007*		2007*			2007			2006*		2006*			2006
	(Millions)								(Millions)								(Millions)
Revenues	$	12,352			+1,866		+18	%	$	10,486			+1,187		+13	%	$	9,299
Costs and expenses:
Costs and operating expenses		9,156			-1,149		-14	%		8,007			-518		-7	%		7,489
Selling, general and administrative expenses		504			-33		-7	%		471			-82		-21	%		389
Other (income) expense — net		(82	)		+64	NM				(18	)		+52	NM					34
General corporate expenses		149			+12		+7	%		161			-29		-22	%		132
Securities litigation settlement and related costs		—			—		—			—			+167		+100	%		167

Total costs and expenses		9,727								8,621								8,211

Operating income		2,625								1,865								1,088
Interest accrued — net		(594	)		+59		+9	%		(653	)		—		—			(653	)
Investing income		191			-66		-26	%		257			+89		+53	%		168
Early debt retirement costs		(1	)		+18		+95	%		(19	)		+12		+39	%		(31	)
Other income — net		—			-11		-100	%		11			-15		-58	%		26

Income from continuing operations before income taxes		2,221								1,461								598
Provision for income taxes		713			-189		-36	%		524			-313		-148	%		211

Income from continuing operations		1,508								937								387
Income (loss) from discontinued operations		84			-59		-41	%		143			+181	NM				(38	)

Net income		1,592								1,080								349
Less: Net income attributable to noncontrolling interests		174								90								40

Net income attributable to The Williams Companies, Inc.	$	1,418							$	990							$	309


*		+ = Favorable change to net income; — = Unfavorable change to net income; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator, or a percentage change greater than 200.

2008 vs. 2007

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 increase in revenues is primarily due to higher production revenues at Exploration & Production resulting from both higher net realized average prices and increased production volumes sold. Midstream also experienced higher olefin production revenues primarily due to higher average prices and volumes as well as increased natural gas liquid (NGL) production 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 the absence of a loss recognized on a legacy derivative sales contract in 2007.

The increase in costs and operating expenses is primarily due to increased costs associated with our olefin and NGL production businesses at Midstream. Higher depreciation, depletion, and amortization and higher operating taxes at Exploration & Production also contributed to the increase in expenses.

The increase in selling, general and administrative expenses (SG&A) primarily includes the impact of higher staffing and compensation at our Exploration & Production and Midstream segments in support of increased operational activities.

Other (income) expense — net within operating income in 2008 includes:

	•		Gain of $148 million on the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production;

	•		Net gains of $49 million on foreign currency exchanges at Midstream;

	•		Income of $32 million related to the partial settlement of our Gulf Liquids litigation at Midstream;

	•		Gain of $10 million on the sale of certain south Texas assets at Gas Pipeline;

	•		Income of $17 million resulting from involuntary conversion gains at Midstream;

	•		Impairment charges totaling $143 million related to certain natural gas producing properties at Exploration & Production;

	•		Expense of $23 million related to project development costs at Gas Pipeline.

Other (income) expense — net within operating income in 2007 includes:

	•		Income of $18 million associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral;

	•		Income of $17 million associated with a change in estimate related to a regulatory liability at Northwest Pipeline;

	•		Income of $12 million related to a favorable litigation outcome at Midstream;

	•		Income of $8 million due to the reversal of a planned major maintenance accrual at Midstream;

	•		Expense of $20 million related to an accrual for litigation contingencies at Gas Marketing Services;

	•		Expense of $10 million related to an impairment of the Carbonate Trend pipeline at Midstream.

The increase in operating income reflects improved operating results at Exploration & Production due to higher net realized average prices, natural gas production growth and a gain of $148 million on the sale of 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 favorable price movements on derivative positions economically hedging the anticipated withdrawals of natural gas from storage and the absence of a loss recognized on a legacy derivative sales contract in 2007. Partially offsetting these increases is a decrease in operating income at Midstream primarily due to a sharp decline in energy commodity prices in the latter part of 2008.

Interest accrued — net decreased primarily due to increased capitalized interest resulting from an increased level of capital expenditures. The decrease was also a result of lower interest rates on debt issuances that occurred late in the fourth quarter of 2007 and in the first half of 2008 for which the proceeds were primarily used to retire existing debt bearing higher interest rates. While our overall debt balances have been relatively comparable, the net effect of these retirements and issuances has resulted in lower rates.

The decrease in investing income is primarily due to a decrease in interest income largely resulting from lower average interest rates in 2008 compared to 2007.

Net income attributable to noncontrolling interests increased primarily reflecting the growth in the noncontrolling interest holdings of Williams Partners L.P. and Williams Pipeline Partners L.P. in late 2007 and early 2008, respectively.

Provision for income taxes increased primarily due to higher pre-tax income partially offset by a reduction in our estimate of the effective deferred state tax rate. 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 in income (loss) from discontinued operations.

2007 vs. 2006

The increase in revenues is 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 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.

The increase in costs and operating expenses is due primarily to increased NGL and olefins marketing purchases and increased costs associated with our olefins production business at Midstream. Additionally, Exploration & Production experienced higher depreciation, depletion and amortization and lease operating expenses due primarily to higher production volumes.

The increase in SG&A is primarily due to increased staffing in support of increased drilling and operational activity at Exploration & Production, the absence of a $25 million gain in 2006 related to the sale of certain receivables at Gas Marketing Services, and a $9 million charge related to certain international receivables at Midstream.

Other (income) expense — net within operating income in 2006 includes:

	•		A $73 million accrual for a Gulf Liquids litigation contingency;

	•		Income of $9 million due to a settlement of an international contract dispute at Midstream.

The increase in general corporate expenses is attributable to various factors, including higher employee-related costs, increased levels of charitable contributions and information technology expenses. The higher employee-related costs are primarily the result of higher stock compensation expense. (See Note 1 of Notes to Consolidated Financial Statements.)

The securities litigation settlement and related costs is primarily the result of our 2006 settlement related to class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002. (See Note 16 of Notes to Consolidated Financial Statements.)

The increase in operating income reflects record high NGL margins at Midstream, continued strong natural gas production growth at Exploration & Production, the positive effect of new rates at Gas Pipeline, and the absence of 2006 litigation expenses associated with shareholder lawsuits and Gulf Liquids litigation.

Interest accrued — net includes a decrease of $19 million in interest expense associated with our Gulf Liquids litigation contingency, offset by changes in our debt portfolio, most significantly the issuance of new debt in December 2006 by Williams Partners L.P.

The increase in investing income is due to:

	•		A $27 million increase in interest income primarily associated with larger cash and cash equivalent balances combined with slightly higher rates of return in 2007 compared to 2006;

	•		Increased equity earnings of $38 million due largely to increased earnings of our Gulfstream Natural Gas System, L.L.C. (Gulfstream), Discovery Producer Services LLC (Discovery) and Aux Sable Liquid Products, L.P. (Aux Sable) investments;

	•		The absence of a $16 million impairment in 2006 of a Venezuelan cost-based investment at Exploration & Production;

	•		$14 million of gains from sales of cost-based investments in 2007.

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 costs in 2007 includes $19 million of premiums and fees related to the December 2007 repurchase of senior unsecured notes. Early debt retirement costs in 2006 includes $27 million in premiums and fees related to the January 2006 debt conversion and $4 million of accelerated amortization of debt expenses related to the retirement of the debt secured by assets of Williams Production RMT Company.

Net income attributable to noncontrolling interests increased primarily due to the growth in the noncontrolling interest holdings of Williams Partners L.P.

Provision for income taxes was significantly higher in 2007 due primarily to higher pre-tax earnings. 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 in income (loss) from discontinued operations.

Results of Operations — Segments

We are currently organized into the following segments: Exploration & Production, Gas Pipeline, Midstream, Gas Marketing Services, and Other. Other primarily consists of corporate operations. Our management currently evaluates performance based on segment profit (loss) from operations. (See Note 18 of Notes to Consolidated Financial Statements.)

Exploration & Production

Overview of 2008

In 2008, 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 following Outlook for 2009 section.

We’ve remained focused on continuing our domestic development drilling program in our growth basins. Accordingly, we:

	•		Benefited from increased domestic net realized average prices for the total year of 2008, which increased by approximately 28 percent compared to 2007. The domestic net realized average price for 2008 was $6.48 per thousand cubic feet of gas equivalent (Mcfe) compared to $5.08 per Mcfe in 2007. Net realized average prices include market prices, net of fuel and shrink and hedge positions, less gathering and transportation expenses. The domestic net realized average price for the fourth quarter 2008 was $4.43 per Mcfe reflecting the significant decline in natural gas prices.

	•		Increased average daily domestic production levels by approximately 20 percent compared to 2007. The average daily domestic production for 2008 was approximately 1,094 million cubic feet of gas equivalent (MMcfe) compared to 913 MMcfe in 2007. The increased production is primarily due to increased development within the Piceance, Powder River, and Fort Worth basins.

	•		Drilled 1,783 gross domestic development wells in 2008 with a success rate of approximately 99 percent. This contributed to total net additions of 602 billion cubic feet equivalent (Bcfe) in net reserves — a replacement rate for our domestic production of 148 percent. Capital expenditures for domestic drilling, development, and acquisition activity in 2008 were approximately $2.5 billion compared to $1.7 billion in 2007. Capital expenditures for 2008 include acquisitions in the Piceance and Fort Worth basins discussed in Significant events below.

The benefits of higher net realized average prices and higher production volumes were partially offset by increased operating costs. The increase in operating costs was primarily due to the impact of increased production volumes and prices on operating taxes and higher well service and lease service costs. In addition, higher production volumes coupled with higher capitalized drilling costs increased depreciation, depletion, and amortization expense.

Significant events

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 had 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. A third party subsequently exercised its contractual option to purchase, on the same terms and conditions, an interest in a portion of the acquired assets for $71 million.

In September 2008, we increased our position in the Fort Worth basin by acquiring certain undeveloped leasehold acreage and producing properties for $147 million. This acquisition is consistent with our growth 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 our properties in the 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 2009

Considering 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 2009:

	•		Continuing our development drilling program in the Piceance, Fort Worth, Powder River and San Juan basins through our planned capital expenditures projected between $950 million and $1.05 billion.

	•		Slight growth in our annual average daily domestic production level compared to 2008, with fourth quarter 2009 volumes likely to be less than the prior comparable period.

	•		Declines in the costs of services and materials associated with development activities as demand for these resources decline. However, in the first quarter of 2009, we estimate we will incur between $25 million and $35 million in expense from contract penalties associated with the reduction in drilling rigs deployed.

Risks to achieving our expectations include unfavorable natural gas market price movements which are impacted by numerous factors, including weather conditions, domestic natural gas production levels and demand, and the downturn in the global economy. A further significant decline in natural gas prices would impact these expectations for 2009.

In addition, changes in laws and regulations may impact our development drilling program. For example, the 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 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.

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 using NYMEX and basis fixed-price contracts and collar agreements.

For 2009, we have the following agreements and contracts for our daily domestic production, shown at weighted average volumes and basin-level weighted average prices:


			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 our 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 2009.

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 total segment revenues is primarily due to the following:

	•		$919 million, or 53 percent, increase in domestic production revenues reflecting $571 million associated with a 28 percent increase in net realized average prices and $348 million associated with a 20 percent increase in production volumes sold. The impact of hedge positions on increased net realized average prices includes the effect of fewer volumes hedged by fixed-price contracts. The increase in production volumes reflects an increase in the number of producing wells primarily from the Piceance, Powder River, and Fort Worth basins. Production revenues in 2008 and 2007 include approximately $85 million and $53 million, respectively, related to natural gas liquids and approximately $62 million and $40 million, respectively, related to condensate.

	•		$151 million increase in revenues for gas management activities related to gas sold on behalf of certain outside parties, which is substantially offset by a similar increase in segment costs and expenses. This increase is primarily due to increases in natural gas prices and volumes sold.

	•		$17 million favorable change related to hedge ineffectiveness due to $1 million in net unrealized gains from hedge ineffectiveness in 2008 compared to $16 million in net unrealized losses in 2007.

Total segment costs and expenses increased $591 million, primarily due to the following:

	•		$202 million higher depreciation, depletion and amortization expense primarily due to higher production volumes and increased capitalized drilling costs.

	•		$149 million increase in expenses for gas management activities related to gas purchased on behalf of certain outside parties, which is offset by a similar increase in segment revenues.

	•		$143 million of property impairments in 2008 in the Arkoma basin as previously discussed.

	•		$118 million higher operating taxes primarily due to both higher average market prices and higher domestic production volumes sold and the $34 million charge related to the Wyoming severance and ad valorem tax issue previously discussed.

	•		$61 million higher lease operating expenses from the increased number of producing wells primarily within the Piceance, Powder River, and Fort Worth basins combined with increased prices for well and lease service expenses and higher facility expenses.

	•		$28 million higher SG&A expenses primarily due to increased staffing in support of increased drilling and operational activity, including higher compensation. The higher SG&A expenses also include an increase of $11 million in bad debt expense.

	•		$17 million higher gathering expenses due to higher domestic production volumes.

	•		$17 million of expense in 2008 related to the write-off of certain exploratory drilling costs for our domestic and international operations.

These increases are partially offset by the $148 million gain associated with the previously discussed sale of our Peru interests in 2008.

The $504 million increase in segment profit is primarily due to the 28 percent increase in domestic net realized average prices and the 20 percent increase in domestic production volumes sold, partially offset by the increase in total segment costs and expenses.

2007 vs. 2006

The increase in total segment revenues is primarily due to 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 in segment costs and expenses.

These increases were partially offset by a $30 million unfavorable change related to hedge ineffectiveness due to $16 million in net unrealized losses from hedge ineffectiveness in 2007 compared to $14 million in net unrealized gains in 2006.

Total segment costs and expenses increased $409 million, primarily due to the following:

	•		$173 million higher depreciation, depletion and amortization expense primarily due to higher production volumes and increased capitalized drilling costs.

	•		$144 million increase in expenses for gas management activities related to gas purchased on behalf of certain outside parties which is offset by a similar increase in segment revenues.

	•		$46 million higher lease operating expenses from the increased number of producing wells primarily within the Piceance, Powder River, and Fort Worth basins in combination with higher well service expenses, facility expenses, equipment rentals, maintenance and repair services, and salt water disposal expenses.

	•		$36 million higher SG&A expenses primarily due to increased staffing in support of increased drilling and operational activity, including higher compensation. In addition, we incurred higher insurance and information technology support costs related to the increased activity. First quarter 2007 also includes approximately $5 million of expenses associated with a correction of costs incorrectly capitalized in prior periods.

The $204 million increase in segment profit is primarily due to the 21 percent increase in domestic production volumes sold as well as the 15 percent increase in net realized average prices, partially offset by the increase in segment costs and expenses.

Gas Pipeline

Overview

Gas Pipeline’s strategy to create value focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.

Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates. As a result, the recent decline in energy commodity prices has not significantly impacted our results of operations.

Significant events of 2008 include:

Gas 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.

Status of rate case

During 2006, Transco filed a general rate case with the FERC designed to recover increases in costs. The new rates were 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 their pending 2006 rate case. On March 7, 2008, the FERC approved the agreement without modification. The agreement became effective June 1, 2008 and required refunds were issued in July 2008.

Hurricane Ike

In 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 Natural Gas System, L.L.C. (Gulfstream), received FERC approval to extend its existing pipeline approximately 34 miles within Florida. Construction began in April 2008 and the expansion was placed into service in September 2008. The extension fully subscribed the remaining 345 Mdt/d of firm capacity on the existing pipeline. Gulfstream’s estimated cost of this project is $118 million.

Gulfstream Phase IV expansion project

In September 2007, Gulfstream received FERC approval to construct 17.8 miles of 20-inch pipeline and to install a new compressor facility. Construction began in December 2007. The pipeline expansion was placed into service in the fourth quarter of 2008, and the compressor facility was placed into service in January 2009. The expansion increased capacity by 155 Mdt/d. Gulfstream’s estimated cost of this project is $192 million.

Sentinel expansion project

In August 2008, we received FERC approval to construct an expansion in the northeast United States. The cost of the project is estimated to be up to $200 million. We 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 placed into service by November 2009.

Colorado Hub Connection project

In September 2008, we filed an application with the FERC to construct a 27-mile pipeline to provide increased access to the Rockies natural gas supplies. The estimated cost of the project is $60 million with service targeted to commence in November 2009. We will combine the lateral capacity with 341 Mdt/d of 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,
	2008		2007		2006
	(Millions)
Segment revenues	$	1,634	$	1,610	$	1,348

Segment profit	$	689	$	673	$	467

2008 vs. 2007

Segment revenues increased $24 million, or 1 percent, due primarily to a $52 million increase in transportation revenues resulting 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 revenues increased $28 million due to transportation imbalance settlements (offset in costs and operating expenses). Partially offsetting these increases is the absence of $59 million associated with a 2007 sale of excess inventory gas (offset in costs and operating expenses).

Costs and operating expenses decreased $11 million, or 1 percent, due primarily to the absence of $59 million associated with a 2007 sale of excess inventory gas (offset in segment revenues). The decrease is partially offset by an increase in costs of $28 million associated with transportation imbalance settlements (offset in segment revenues) and higher rental expense related to the Parachute lateral that was transferred to Midstream in December 2007.

Other income — net changed 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 in segment profit is due primarily 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 in other income — net.

2007 vs. 2006

Revenues increased $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 expenses increased $86 million, or 11 percent, due primarily to:

	•		An increase of $59 million associated with the sale of excess inventory gas;

	•		An increase in depreciation expense of $30 million due to property additions;

	•		An increase in personnel costs of $10 million due primarily to higher compensation as well as an increase in number of employees.

Partially offsetting these increases is a decrease of $12 million in contract and outside service costs and a decrease of $7 million in materials and supplies expense.

Other (income) expense — net changed favorably by $15 million due primarily to $18 million of income associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral. Also included in the favorable change is $17 million of income recorded in the second quarter of 2007 for a change in estimate related to a regulatory liability at Northwest Pipeline, partially offset by $18 million of expense related to higher asset retirement obligations.

Equity earnings increased $14 million due primarily to a $14 million increase in equity earnings from Gulfstream. Gulfstream’s higher earnings were primarily due to a decrease in property taxes from a favorable litigation outcome as well as improved operating results.

The $206 million, or 44 percent, increase in segment profit is due primarily to $262 million higher revenues, $14 million higher equity earnings and $15 million favorable other (income) expense — net as previously discussed. Partially offsetting these increases are higher costs and operating expenses as previously discussed.

Midstream Gas & Liquids

Overview of 2008

Midstream’s ongoing strategy is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers.

Significant events during 2008 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.

Volatile commodity prices

During the first three quarters of 2008, strong per-unit NGL margins driven by higher crude prices, which impact NGL prices, in relationship to natural gas prices contributed significantly to our realized margins. 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 realized per-unit margins that 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, Texas.

Our average realized NGL per-unit margin at our processing plants during 2008 was 61 cents per gallon (cpg), compared to 55 cpg in 2007. The increase in our NGL per-unit margin is partially due to a change in the 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 the fourth quarter of 2008, we reduced our recoveries of ethane in those periods. Because we typically realize lower per-unit margins for ethane versus other NGLs, if we had produced the same mix of ethane and non-ethane NGLs during 2008 as we generally have in prior years, the average per-unit margin in 2008 would have been lower. NGL margins have exceeded our rolling five-year average for the last seven quarters, in spite of strong NGL margins in 2007 and early 2008 that have significantly increased our rolling five-year average from 26 cpg at the end of the 2007 to 37 cpg at the end 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 late 2007, the NGL marketing business sold the majority of our equity volumes in the West region to a 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 for sale at downstream markets, which increased our inventory levels. Inventory volumes also increased during 2008 due to the previously 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 reducing our recovery of ethane to accommodate these restrictions. In the fourth quarter of 2008, these restrictions were alleviated as we were able to deliver NGL volumes from our 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 NGL per-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 2008 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 60 percent equity interest in, also sustained hurricane damage and was not accepting offshore gas from producers while repairs were being made. The mainline 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 timing to resolve these claims 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.

We own approximately 23.6 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. We consolidate Williams Partners L.P. within the Midstream 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.

Outlook for 2009

The following factors could impact our business in 2009.

Commodity price changes

	•		Margins in our NGL and olefins business are highly dependent upon continued demand within the global economy. NGL products are currently the preferred feedstock for ethylene and propylene olefin production, which are the building blocks of polyethylene or plastics. Forecasted domestic and global demand for polyethylene has weakened with the recent instability in the global economy. A continued slow down in domestic and global economies could further reduce the demand for the petrochemical products we produce in both Canada and the United States.

	•		As evidenced by recent events, NGL, crude and natural gas prices are highly volatile. NGL price changes have historically tracked with changes in the price of crude oil; however ethane prices have recently disassociated from crude prices. As NGL prices, especially ethane, decline, we expect lower per-unit NGL margins in 2009 compared to 2008. Additionally, we anticipate periods when it is not economical to recover ethane, which will further reduce our segment profit.

	•		Although natural gas prices declined significantly during the fourth-quarter of 2008, which reduced our costs associated with the production of NGLs, NGL margins were compressed as NGL prices fell more than natural gas prices. However, we expect continued favorable gas price differentials in the Rocky Mountain area to partially mitigate such per-unit margin declines.

	•		In our olefin production business, we continue to maintain a cost advantage as our propylene and ethylene olefin production processes use NGL-based feedstocks, which are less expensive than other olefin production processes that use alternative crude-based feedstocks. However, margins have narrowed and we anticipate results from our olefins production business for the 2009 year to be below 2008 levels.

	•		Fee-based revenues generally reduce our exposure to commodity price risks, but may also reduce our profitability compared to keep-whole arrangements in high margin environments. Certain of our gas processing contracts contain provisions that allow customers to periodically elect processing services on either a fee-basis or a keep-whole or percent-of-liquids basis. If customers switch from keep-whole to fee-based processing, we expect a reduction in our NGL equity sales volumes in 2009 compared to 2008.

Gathering and processing volumes

	•		Natural gas supplies supporting our gathering and processing volumes are dependent upon producer drilling activities. The current credit crisis and economic downturn, together with the low commodity price environment, are expected to reduce certain producer drilling activities. Although our customers in the West region are generally large producers and we anticipate they will continue with some level of drilling plans, certain reductions are expected in 2009. A significant decline in drilling activity would likely reduce our gathered volumes and volumes available for both fee-based and keep-whole processing.

	•		We expect higher fee revenues, depreciation and operating expenses in our Gulf Coast region as our Devils Tower infrastructure expansions serving the Blind Faith and Bass Lite prospects move into a full year of operation in 2009. While we expect to continue to connect new supplies in the deepwater, this increase is expected to be partially offset by lower volumes in other Gulf Coast areas due to natural declines.

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 of the Gulf of Mexico, we completed construction of 37-mile extensions of both of our oil and gas pipelines from our Devils Tower spar to the Blind Faith prospect located in Mississippi Canyon. The pipelines have been commissioned and production began flowing in the fourth quarter of 2008.

Ongoing commitments

	•		In the western deepwater of the Gulf of Mexico, we expect to spend $205 million on our major expansion projects in 2009, including the Perdido Norte project, which will include an expansion of our Markham gas processing facility and oil and gas lines that will expand the scale of our existing infrastructure. We expect this project to begin contributing to our segment profit at the end of 2009.

	•		In the West Region, we expect to spend $260 million on our major expansion projects in 2009, including the Willow Creek facility and additional capacity at our Echo Springs facility.

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 in the petrochemicals industry, which has been under severe stress from the current economic downturn. Although we actively manage our credit exposure through certain collateral or payment terms and arrangements, continued economic downturn may result in significant credit or bad debt losses.

	•		We expect significant savings in certain NGL transportation costs in the West region due to the transition from our previous shipping arrangement to transportation on the Overland Pass pipeline. NGL volumes from our Wyoming plants began to flow into the Overland Pass pipeline in the fourth quarter of 2008, relieving pipeline capacity constraints and resulting in an expected increase in NGL volumes for 2009.

	•		Our Venezuelan operations are operated for the exclusive benefit of the Venezuelan state-owned oil company, Petróleos de Venezuela S.A. (PDVSA). As energy commodity prices have sharply declined, PDVSA has failed to make regular payments to many service providers, including us. At December 31, 2008, we had a net receivable of $57 million from PDVSA, none of which was 60 days old or older at that date. This does not include $15 million owed to our 49 percent equity investee, Accroven, of which $5 million was 60 days old or older at December 31, 2008. We continue to monitor the situation and are actively seeking resolution with PDVSA. The collection of receivables from PDVSA has historically been slower and more time consuming than our other customers due to their policies and the political unrest in Venezuela. We expect, at this time, that the amounts will ultimately be paid. The failure of PDVSA to make payments to service providers, however, could jeopardize the Venezuelan oil industry and thereby unfavorably impact all service providers, including us.

			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 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,
	2008			2007			2006
	(Millions)
Segment revenues	$	5,642		$	5,180		$	4,159

Segment profit (loss):
Domestic gathering & processing		841			897			631
Venezuela		104			89			98
NGL Marketing, Olefins and Other		113			174			16
Indirect general and administrative expense		(95	)		(88	)		(70	)

Total	$	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 as indirect general and

administrative expense. These charges represent any overhead cost not directly attributable to one of the specific asset groups noted in this discussion.

2008 vs. 2007

The increase in segment revenues is largely due to:

	•		A $210 million increase in revenues in our olefins production business due primarily to higher average product prices and also to higher volumes sold associated with the increase of our ownership interest in the Geismar olefins facility effective July 2007.

	•		A $163 million increase in revenues associated with the production of NGLs due primarily to higher average NGL prices, partially offset by lower volumes. Lower volumes resulted from reduced ethane recoveries at the plants during the third and fourth quarters of 2008 compared to higher volumes during 2007 as we transitioned from shipping volumes through a pipeline for sale downstream to product sales at the plant.

	•		A $69 million increase in fee-based revenues due primarily to the West region, Venezuela, the deepwater Gulf Coast region and at our Conway fractionation and storage facilities.

Segment costs and expenses increased $569 million, or 14 percent, primarily as a result of:

	•		A $213 million increase in costs in our olefins production business due to higher feedstock prices and also to higher volumes produced associated with the increase of our ownership interest in the Geismar olefins facility effective July 2007. The increase also includes a $10 million higher charge to write down the value of olefin inventories.

	•		A $191 million increase in costs associated with the production of NGLs due primarily to higher average natural gas prices.

	•		A $126 million increase in NGL, olefin and crude marketing purchases due primarily to higher average NGL and crude prices, partially offset by lower volumes as discussed in the revenue section above. The increase also includes a $19 million higher charge in 2008 to write down the value of NGL and olefin inventories.

	•		A $107 million increase in operating costs including higher depreciation, repair costs and property insurance deductibles related to the hurricanes, gas transportation expenses in the eastern Gulf of Mexico, employee costs, and higher costs associated with the increase of our ownership interest in the Geismar olefins facility.

These increases are partially offset by:

	•		A $44 million favorable change related to foreign currency exchange gains primarily due to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•		$32 million of income related to the partial settlement of our Gulf Liquids litigation (see Note 16 of Notes to Consolidated Financial Statements).

	•		A $16 million favorable change due to higher involuntary conversion gains in 2008 related to insurance recoveries in excess of the carrying value of our Ignacio and Cameron Meadows plants.

The decrease in Midstream’s segment profit reflects the previously described changes in segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.

Domestic gathering & processing

The decrease in domestic gathering & processing segment profit includes a $49 million decrease in the West region and a $7 million decrease in the Gulf Coast region.

The decrease in our West region’s segment profit includes:

	•		A $45 million decrease in NGL margins due to a significant increase in costs associated with the production of NGLs reflecting higher natural gas prices and lower volumes sold. The decrease in volumes sold is due primarily to restricted transportation capacity, unfavorable ethane economics, an increase in inventory during 2008, hurricane-related disruptions at a third-party fractionation facility, and lower equity volumes as processing agreements change from keep-whole to fee-based. These decreases were partially offset by a full year of production from the fifth train at our Opal processing plant, which began production in the first quarter of 2007.

	•		A $35 million increase in operating costs driven by higher turbine and engine overhaul expenses, depreciation expense and employee costs.

	•		The absence of a $12 million favorable litigation outcome in 2007.

	•		A $24 million increase in fee revenues including new lease revenues from Gas Pipeline for the Parachute lateral transferred to Midstream in December 2007.

	•		A $12 million involuntary conversion gain related to our Ignacio plant. These insurance recoveries were used to rebuild the plant.

The decrease in the Gulf Coast region’s segment profit is primarily due to $39 million higher operating costs including higher depreciation, gas transportation expenses and hurricane repair and property insurance deductibles. These 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 profit for 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 in segment profit of 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.

	•		$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 in segment revenues is 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.

	•		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 expenses increased $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.

	•		A $37 million increase in operating expenses including higher depreciation, maintenance, gathering fuel expenses and operating taxes.

	•		$24 million higher general and administrative expenses.

	•		A $10 million loss on impairment of the Carbonate Trend pipeline and an $8 million loss on impairment of other assets.

	•		The absence of $11 million of net gains on the sales of assets in 2006.

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 increase in Midstream’s segment profit reflects $339 million higher NGL margins and the absence of the previously mentioned $73 million Gulf Liquids litigation charge in 2006, as well as the other previously described changes in segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of Midstream’s various operations is presented as follows.

Domestic gathering & processing

The increase in domestic gathering and processing segment profit includes a $308 million increase in the West region, partially offset by a $42 million decrease in the Gulf Coast region.

The increase in our West region’s segment profit primarily results from higher NGL margins, higher processing fee based revenues and a favorable litigation settlement, partially offset by higher operating expenses and lower gathering fee revenues. The significant components of this increase include the following:

	•		NGL margins increased $326 million in 2007 compared to 2006. This increase was driven by an increase in average per unit NGL prices, a decrease in costs associated with the production of NGLs reflecting lower natural gas prices and higher volumes due primarily to new capacity on the fifth cryogenic train at our Opal plant.

	•		Processing fee revenues increased $12 million. Processing volumes are higher due to customers electing to take liquids and pay processing fees.

	•		$12 million income in 2007 from a favorable litigation outcome.

	•		Gathering fee revenues decreased $6 million due primarily to natural volume declines and the shutdown of the Ignacio plant in the fourth quarter of 2007 as a result of the fire.

	•		Operating expenses increased $21 million including $9 million in higher depreciation, $9 million in higher treating plant and gathering fuel due primarily to the expiration of a favorable gas purchase contract, $5 million related to gas imbalance revaluation losses in the current year compared to gains in the prior year, $5 million higher leased compression costs and $4 million higher costs related to the Jicarilla lease arrangement. These were partially offset by the absence of a $7 million accounts payable accrual adjustment in 2006 and $5 million in lower system product losses.

The decrease in the Gulf Coast region’s segment profit is primarily a result of lower volumes from our deepwater facilities, losses on impairments, and the absence of gains on assets in 2006, partially offset by higher NGL margins and higher other fee revenues. The significant components of this decrease include the following:

	•		Fee revenues from our deepwater assets decreased $40 million due primarily to declines in producers’ volumes.

	•		A $10 million loss on impairment of the Carbonate Trend pipeline and a $6 million loss on impairment of our other assets.

	•		The absence of $8 million in gains on the sales of certain gathering assets and a processing plant in 2006 and $5 million lower involuntary conversion gains resulting from insurance proceeds used to rebuild the Cameron Meadows plant.

	•		NGL margins increased $14 million driven by higher NGL prices, partially offset by lower NGL recoveries and an increase in costs associated with the production of NGLs.

	•		Other fee revenues increased $8 million driven by higher water removal fees.

Venezuela

Segment profit for our Venezuela assets decreased primarily due to the absence of a $9 million gain from the settlement of a contract dispute in 2006, $6 million lower fee revenues due primarily to the discontinuance in 2007 of revenue recognition related to labor escalation receivables, $7 million higher operating expenses, and $8 million higher bad debt expense related to labor escalation receivables, partially offset by $19 million of higher currency exchange gains and $1 million higher equity earnings.

NGL marketing, olefins and other

The significant components of the increase in segment profit of our other operations include the following:

	•		The absence of the previously mentioned $73 million Gulf Liquids litigation charge in 2006.

	•		$46 million in higher margins from our olefins production business due primarily to the increase in ownership of the Geismar olefins facility in July 2007 and higher prices of NGL products produced in our Canadian olefins operations.

	•		$18 million in higher margins related to the marketing of olefins and $21 million in higher margins related to the marketing of NGLs due to more favorable changes in pricing while product was in transit during 2007 as compared to 2006.

	•		An $8 million reversal of a maintenance accrual (see below).

	•		$9 million higher Aux Sable equity earnings primarily due to favorable processing margins.

	•		$11 million higher Discovery equity earnings primarily due to higher NGL margins and volumes.

These increases are partially offset by:

	•		$19 million in higher foreign exchange losses related to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•		The absence of a $4 million favorable transportation settlement in 2006.

Effective January 1, 2007, we adopted FASB Staff Position (FSP) No. AUG AIR-1, Accounting for Planned Major Maintenance Activities. As a result, we recognized as other income an $8 million reversal of an accrual for major maintenance on our Geismar ethane cracker. We did not apply the FSP retrospectively because the impact to our first quarter 2007 and estimated full year 2007 earnings, as well as the impact to prior periods, is not material. We have adopted the deferral method for accounting for these costs going forward.

Indirect general and administrative expense

The increase in indirect general and administrative expense is due primarily to higher technical support services and other charges for various administrative support functions and higher employee expenses.

Gas Marketing Services

Gas Marketing Services (Gas Marketing) primarily supports our natural gas businesses by providing marketing and risk management services, which include marketing and hedging the gas produced by Exploration & Production, and procuring 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 2008

Gas Marketing’s operating results for 2008 were primarily driven by higher realized margins on both storage and transportation contracts in addition to favorable price movements on derivative positions executed to hedge the anticipated withdrawals of natural gas from storage. These gains were partially offset by adjustments made to the carrying value of the natural gas inventories in storage reflecting a decline in the price of natural gas.

Outlook for 2009

For 2009, Gas Marketing will focus on providing services that support our natural gas businesses. Gas Marketing’s earnings may continue to reflect mark-to-market volatility from commodity-based derivatives that represent economic hedges but are not designated as hedges for accounting purposes or do not qualify for hedge accounting.

Year-Over-Year Operating Results


	Years Ended December 31,
	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	)

2008 vs. 2007

Realized revenues represent (1) revenue from the sale of natural gas and (2) gains and losses from the net financial settlement of derivative contracts. Realized revenues increased $1,437 million primarily due to an increase in physical natural gas revenue as a result of a 26 percent increase in average prices on physical natural gas sales. This is slightly offset by a decrease related to net financial settlements of derivative contracts.

Net forward unrealized mark-to-market gains (losses) primarily represent changes in the fair values of certain derivative contracts with a future settlement or delivery date that are not designated as hedges for accounting purposes or do not qualify for hedge accounting. The 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.

Total segment costs and expenses increased $1,439 million, primarily due to a 33 percent increase in average prices on physical natural gas purchases. These increases were partially offset by the absence of a $20 million accrual for litigation contingencies in 2007.

The $340 million favorable change in segment profit (loss) is primarily due to the favorable change in net forward unrealized mark-to-market gains (losses), which includes the absence of a 2007 loss recognized on a legacy derivative natural gas sales contract. The favorable change in segment profit (loss) also reflects the absence of a $20 million accrual for litigation contingencies in 2007, partially offset by a decline in accrual earnings.

2007 vs. 2006

Realized revenues decreased $237 million primarily due to a decrease in net financial settlements of derivative contracts. This is partially offset by an increase in physical natural gas revenue as a result of a 9 percent increase in natural gas sales volumes partially offset by a 6 percent decrease in average prices on physical natural gas sales.

Net forward unrealized mark-to-market gains (losses) 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.

Total segment costs and expenses decreased $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 volumes. The net decrease was also partially offset by:

	•		A $20 million accrual for litigation contingencies in 2007.

	•		The absence of a $25 million gain from the sale of certain receivables to a third party in 2006.

The $142 million unfavorable change in segment profit (loss) is primarily due to the loss recognized on a legacy derivative contract previously treated as a normal purchase and normal sale, a $20 million accrual for litigation contingencies and the absence of a $25 million gain from the sale of certain receivables, partially offset by an improvement in accrual earnings.

Other

Year-Over-Year Operating Results


	Years Ended December 31,
	2008			2007			2006
	(Millions)
Segment revenues	$	24		$	26		$	27

Segment loss	$	(3	)	$	(1	)	$	(13	)

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 debt and/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.)

Outlook

For 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 our requirements for working capital, capital and investment expenditures, and debt payments while maintaining a sufficient level of liquidity. In particular, we note the following assumptions for the coming year:

	•		We expect to maintain liquidity of at least $1 billion from cash and cash equivalents and unused revolving credit facilities.

	•		We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, and utilization of our revolving credit facilities as needed. However, we may be opportunistic in accessing the capital markets to build additional liquidity. We estimate our cash flow from operations to be between $1.9 billion and $2.2 billion in 2009.

We estimate capital and investment expenditures will total $2,150 million to $2,450 million in 2009. Of this total, approximately two-thirds is considered nondiscretionary to meet legal, regulatory, and/or contractual requirements or to preserve the value of existing assets. Included within the total estimated expenditures for 2009 is $250 million to $300 million for compliance and maintenance-related projects at Gas Pipeline, including Clean Air Act compliance.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:

	•		Lower than expected levels of cash flow from operations.

	•		Sustained reductions in energy commodity prices from year-end 2008 levels.

	•		Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 16 of Notes to Consolidated Financial Statements).

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2009. As noted below, certain of our unsecured revolving and letter of credit facilities are scheduled to expire in 2009 and 2010. These facilities were originated primarily in support of our 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, 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 may 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.

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
	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 equivalents includes $30 million of funds received from third parties as collateral. The obligation for these amounts is reported as accrued liabilities on the Consolidated Balance Sheet. Also included is $609 million of cash and cash equivalents that is being utilized by certain subsidiary and international operations. The remainder of our cash and cash equivalents is primarily held in government-backed instruments.

(2)		Northwest Pipeline and Transco each have access to $400 million under this facility to the extent not utilized by us. We expect that the ability of both Northwest Pipeline and Transco to borrow under this facility is reduced by approximately $19 million each due to the bankruptcy of a participating bank. We also expect that our consolidated ability to borrow under this facility is reduced by a total of $70 million, including the reductions related to Northwest Pipeline and Transco. The available liquidity in the table above reflects this $70 million reduction. (See Note 11 of Notes to Consolidated Financial Statements.) The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction.

		Our primary credit facility contains financial covenants including the requirement that we not exceed stated debt to capitalization ratios. At December 31, 2008, we are significantly below the maximum allowed ratios (see Note 11 of Notes to Consolidated Financial Statements).

(3)		This facility is only available to Williams Partners L.P. We expect that Williams Partners L.P.’s ability to borrow under this facility is reduced by $12 million due to the bankruptcy of a participating bank. The available liquidity in the table above reflects this $12 million reduction. (See Note 11 of Notes to Consolidated Financial Statements.) The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction.

		This credit facility contains financial covenants related to Williams Partners L.P.’s EBITDA to interest expense ratio and indebtedness to EBITDA ratio (all as defined in the credit agreement). At December 31, 2008, they are in compliance with these covenants. However, since the ratios are calculated on a rolling four-quarter basis, the ratios at December 31, 2008, do not reflect the full-year impact of lower commodity prices in the fourth quarter which have continued into 2009.

Williams Partners L.P. has a shelf registration statement, which expires in October 2009, available for the issuance of $1.17 billion aggregate principal amount of debt and limited partnership unit securities.

At the parent-company level, we have a shelf registration statement, which as a well-known seasoned issuer, allows us to issue an unlimited amount of registered debt and equity securities. This shelf registration statement expires in May 2009.

Exploration & Production has an unsecured credit agreement with certain banks that, so long as certain conditions are met, serves to reduce our use of cash and other credit facilities for margin requirements related to our hedging activities as well as lower transaction fees. The agreement extends through December 2013. (See Note 11 of Notes to Consolidated Financial Statements.)

Credit ratings

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,
	2008			2007			2006
	(Millions)
Net cash provided (used) by:
Operating activities	$	3,355		$	2,237		$	1,890
Financing activities		(432	)		(511	)		1,103
Investing activities		(3,183	)		(2,296	)		(2,321	)

Increase (decrease) in cash and cash equivalents	$	(260	)	$	(570	)	$	672

Operating Activities

Our net cash provided by operating activities in 2008 increased from 2007 due primarily to the increase in our earnings. Significant transactions impacting our net cash provided by operating activities in 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).

	•		$144 million of required refunds paid by Transco related to a general rate case with the FERC (see Results of Operations — Segments, Gas Pipeline).

Our net cash provided by operating activities in 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 2006. These increases are partially offset by increased income tax payments in 2007 and other changes in working capital.

Financing Activities

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.

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

	•		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.

	•		We paid $207 million of quarterly dividends on common stock for the year ended December 31, 2006.

Investing Activities

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.

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.

2006

	•		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

We have various other guarantees and commitments which are disclosed in Notes 3, 9, 10, 11, 15, and 16 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations, including obligations related to discontinued operations.


			2010-		2012-
	2009		2011		2013		Thereafter		Total
	(Millions)
Long-term debt, including current portion:
Principal(l)	$	53	$	994	$	1,248	$	5,611	$	7,906
Interest		588		1,151		894		4,452		7,085
Capital leases		3		2		—		—		5
Operating leases		96		80		42		44		262
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)		—		1		—		—		1

Total	$	2,614	$	4,176	$	3,689	$	12,708	$	23,187


(1)		The debt instruments in this table are classified by stated maturity date. See Note 11 of Notes to Consolidated Financial Statements for discussion of certain non-recourse debt of two of our Venezuelan subsidiaries that is in technical default and classified as current on our Consolidated Balance Sheet.

(2)		Includes $3.7 billion of natural gas purchase obligations at market prices at our Exploration & Production segment. The purchased natural gas can be sold at market prices.

(3)		The obligations for physical and financial derivatives are based on market information as of December 31, 2008 and assumes contracts remain outstanding for their full contractual duration. Because market information changes daily and has the potential to be volatile, significant changes to the values in this category may occur.

(4)		Expected offsetting cash inflows of $3.6 billion at December 31, 2008, resulting from product sales or net positive settlements, are not reflected in these amounts. In addition, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.

(5)		Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $75 million in 2008 and $56 million in 2007. In 2009, we expect to contribute approximately $77 million to these plans (see Note 7 of Notes to Consolidated Financial Statements). During 2008, we contributed $60 million to our tax-qualified pension plans which was greater than the minimum funding requirements. Although the 2008 economic downturn resulted in a significant decrease in the funded status of our tax-qualified pension plans, we expect to contribute approximately $60 million to these pension plans again in 2009, which is expected to be greater than the minimum funding requirements. Estimated future minimum funding requirements may vary significantly from historical requirements if investment returns do not return to expected levels. Future minimum funding requirements may also be impacted if actual results differ significantly from estimated results for assumptions such as interest rates, retirement rates, mortality and other significant assumptions or by changes to current legislation and regulations.

(6)		As of December 31, 2008, we have accrued approximately $79 million for unrecognized tax benefits. We cannot make reasonably reliable estimates of the timing of the future payments of these liabilities. Therefore, these liabilities have been excluded from the table above. See Note 5 of Notes to Consolidated Financial Statements for information regarding our contingent tax liability reserves.

Effects of Inflation

Our operations have benefited from relatively low inflation rates. Approximately 38 percent of our gross property, plant and equipment is at Gas Pipeline. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulation, along with competition and other market factors, may limit our ability to recover such increased costs. For the other operating units, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in oil and natural gas and related commodities than by changes in

general inflation. Crude, natural gas, and natural gas liquids prices are particularly sensitive to the Organization of the Petroleum Exporting Countries (OPEC) production levels and/or the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to these price changes is reduced through the use of hedging instruments and the fee-based nature of certain of our services.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own (see Note 16 of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $43 million, all of which are recorded as liabilities on our balance sheet at December 31, 2008. We will seek recovery of approximately $14 million of the accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2008, we paid approximately $10 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $11 million in 2009 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, 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.

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 result in additional controls. Capital expenditures necessary to install emission control devices on our Transco gas pipeline system to comply with rules were approximately $2 million in 2008 and are estimated to be between $5 million and $10 million through 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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. The majority of our debt portfolio is comprised of fixed rate debt in order to mitigate the impact of fluctuations in interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets.

The tables below provide information about our interest rate risk-sensitive instruments as of December 31, 2008 and 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
																					December 31,
	2009			2010			2011			2012			2013			Thereafter(1)			Total		2008
	(Dollars in millions)
Long-term debt, including current portion (4)(6):
Fixed rate	$	41		$	27		$	948		$	971		$	17		$	5,566		$	7,570	$	6,011
Interest rate		7.6	%		7.6	%		7.6	%		7.6	%		7.5	%		7.9	%
Variable rate	$	12		$	12		$	7		$	255		$	5		$	13		$	304	$	274
Interest rate (2)


																					Fair Value
																					December 31,
	2008			2009			2010			2011			2012			Thereafter(1)			Total		2007
	(Dollars in millions)
Long-term debt, including current portion (4):
Fixed rate	$	53		$	41		$	27		$	948		$	971		$	5,111		$	7,151	$	7,994
Interest rate		7.7	%		7.7	%		7.4	%		7.4	%		7.3	%		7.7	%
Variable rate	$	85		$	12		$	12		$	7		$	605	(5)	$	18		$	739	$	735
Interest rate (3)


(1)		Includes unamortized discount and premium.

(2)		The interest rate at December 31, 2008, is LIBOR plus 0.76 percent.

(3)		The interest rate at December 31, 2007 was LIBOR plus 0.75 percent.

(4)		Excludes capital leases.

(5)		Includes 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 and natural gas liquids, as well as other market factors, such as market volatility and commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our proprietary trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to changes in energy-commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios.

Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. 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 $0.2 million at December 31, 2008, and $1 million at December 31, 2007. During the year ended December 31, 2008, our value at risk for these contracts ranged from a high of $3.3 million to a low of $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

		Gas Marketing Services		• Natural gas 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 $33 million at December 31, 2008, and $24 million at December 31, 2007. During the year ended December 31, 2008, our value at risk for these contracts ranged from a high of $72 million to a low of $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 our value-at-risk calculation, any change in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

Trading Policy

We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.

Foreign Currency Risk

We have international investments that could affect our financial results if the investments incur a permanent decline in value as a result of changes in foreign currency exchange rates and/or the economic conditions in foreign countries.

International investments accounted for under the cost method totaled $17 million at December 31, 2008, and $24 million at December 31, 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.

Net assets of consolidated foreign operations, whose functional currency is the local currency, are located primarily in Canada and approximate 5 percent and 7 percent of our net assets at December 31, 2008 and 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 translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar would have changed stockholders’ equity by approximately $84 million at December 31, 2008.

Item 8. Financial Statements and Supplementary Data

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, 2008 and 2007, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed at the accompanying Index 9.01, Exhibit 99.2. 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 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 5 to the consolidated financial statements, effective January 1, 2007 the Company adopted FASB Interpretation No. 48, Accounting for 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 Williams Companies, Inc.’s internal control over financial reporting as of December 31, 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 23, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
February 23, 2009, except as it relates to the
matter discussed in the first paragraph of
Basis of Presentation set forth in Note 1,
as to which the date is
May 21, 2009

THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF INCOME


	Years Ended December 31,
	2008			2007			2006
	(Millions, except per-share amounts)
Revenues:
Exploration & Production	$	3,121		$	2,021		$	1,411
Gas Pipeline		1,634			1,610			1,348
Midstream Gas & Liquids		5,642			5,180			4,159
Gas Marketing Services		6,412			4,633			5,049
Other		24			26			27
Intercompany eliminations		(4,481	)		(2,984	)		(2,695	)

Total revenues		12,352			10,486			9,299


Segment costs and expenses:
Costs and operating expenses		9,156			8,007			7,489
Selling, general and administrative expenses		504			471			389
Other (income) expense — net		(82	)		(18	)		34

Total segment costs and expenses		9,578			8,460			7,912


General corporate expenses		149			161			132
Securities litigation settlement and related costs		—			—			167


Operating income (loss):
Exploration & Production		1,240			731			530
Gas Pipeline		630			622			430
Midstream Gas & Liquids		904			1,011			635
Gas Marketing Services		3			(337	)		(195	)
Other		(3	)		(1	)		(13	)
General corporate expenses		(149	)		(161	)		(132	)
Securities litigation settlement and related costs		—			—			(167	)

Total operating income		2,625			1,865			1,088


Interest accrued		(653	)		(685	)		(670	)
Interest capitalized		59			32			17
Investing income		191			257			168
Early debt retirement costs		(1	)		(19	)		(31	)
Other income — net		—			11			26


Income from continuing operations before income taxes		2,221			1,461			598
Provision for income taxes		713			524			211


Income from continuing operations		1,508			937			387
Income (loss) from discontinued operations		84			143			(38	)

Net income		1,592			1,080			349
Less: Net income attributable to noncontrolling interests		174			90			40

Net income attributable to The Williams Companies, Inc.	$	1,418		$	990		$	309


Amounts attributable to The Williams Companies, Inc.:
Income from continuing operations	$	1,334		$	847		$	347
Income (loss) from discontinued operations		84			143			(38	)

Net income	$	1,418		$	990		$	309


Basic earnings (loss) per common share:
Income from continuing operations	$	2.30		$	1.42		$	.58
Income (loss) from discontinued operations		.14			.24			(.06	)

Net income	$	2.44		$	1.66		$	.52

Weighted-average shares (thousands)		581,342			596,174			595,053


Diluted earnings (loss) per common share:
Income from continuing operations	$	2.26		$	1.40		$	.57
Income (loss) from discontinued operations		.14			.23			(.06	)

Net income	$	2.40		$	1.63		$	.51

Weighted-average shares (thousands)		592,719			609,866			608,627

See accompanying notes.

THE WILLIAMS COMPANIES, INC.
CONSOLIDATED BALANCE SHEET


	December 31,
	2008			2007
	(Dollars in millions,
	except per-share amounts)

ASSETS
Current assets:
Cash and cash equivalents	$	1,439		$	1,699
Accounts and notes receivable (net of allowance of $40 at December 31, 2008 and $27 at December 31, 2007)		941			1,192
Inventories		260			209
Derivative assets		1,464			1,736
Assets of discontinued operations		6			185
Deferred income taxes		—			199
Other current assets and deferred charges		301			318

Total current assets		4,411			5,538
Investments		971			901
Property, plant and equipment — net		18,065			15,981
Derivative assets		986			859
Goodwill		1,011			1,011
Other assets and deferred charges		562			771

Total assets	$	26,006		$	25,061


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,059		$	1,131
Accrued liabilities		1,170			1,158
Derivative liabilities		1,093			1,824
Liabilities of discontinued operations		1			175
Long-term debt due within one year		196			143

Total current liabilities		3,519			4,431
Long-term debt		7,683			7,757
Deferred income taxes		3,390			2,996
Derivative liabilities		875			1,139
Other liabilities and deferred income		1,485			933
Contingent liabilities and commitments (Note 16)
Equity:
Stockholders’ equity:
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		8,074			6,748
Retained earnings (deficit)		874			(293	)
Accumulated other comprehensive loss		(80	)		(121	)

		9,481			6,942

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		8,440			6,375
Noncontrolling interests in consolidated subsidiaries		614			1,430

Total equity		9,054			7,805

Total liabilities and equity	$	26,006		$	25,061

See accompanying notes.

THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY


	The Williams Companies, Inc., Stockholders
								Accumulated
			Capital in		Retained			Other									Total
	Common		Excess of		Earnings			Comprehensive						Treasury			Stockholders’			Noncontrolling
	Stock		Par Value		(Deficit)			Loss			Other			Stock			Equity			Interests			Total
	(Dollars in millions, except per-share amounts)
Balance, December 31, 2005	$	579	$	6,328	$	(1,136	)	$	(298	)	$	(5	)	$	(41	)	$	5,427		$	214		$	5,641

Comprehensive income:
Net income — 2006		—		—		309			—			—			—			309			40			349
Other comprehensive income:
Net unrealized gains on cash flow hedges, net of reclassification adjustments		—		—		—			394			—			—			394			—			394
Foreign currency translation adjustments		—		—		—			(4	)		—			—			(4	)		—			(4	)
Minimum pension liability adjustment		—		—		—			(1	)		—			—			(1	)		—			(1	)

Total other comprehensive income																		389			—			389

Total comprehensive income																		698			40			738
Adjustment to initially apply SFAS No. 158, net of tax:
Pension benefits:
Prior service cost		—		—		—			(4	)		—			—			(4	)		—			(4	)
Net actuarial loss		—		—		—			(150	)		—			—			(150	)		—			(150	)
Minimum pension liability		—		—		—			5			—			—			5			—			5
Other postretirement benefits:
Prior service cost		—		—		—			(4	)		—			—			(4	)		—			(4	)
Net actuarial gain		—		—		—			2			—			—			2			—			2
Issuance of common stock from 5.5% debentures conversion (Note 12)		20		193		—			—			—			—			213			—			213
Cash dividends — Common stock ($.35 per share)		—		—		(207	)		—			—			—			(207	)		—			(207	)
Sale of limited partner units of consolidated partnership		—		—		—			—			—			—			—			863			863
Dividends and distributions to noncontrolling interests		—		—		—			—			—			—			—			(36	)		(36	)
Repayment of stockholders’ notes		—		—		—			—			5			—			5			—			5
Stock-based compensation, including tax benefit		4		84		—			—			—			—			88			—			88


Balance, December 31, 2006		603		6,605		(1,034	)		(60	)		—			(41	)		6,073			1,081			7,154
Comprehensive income:
Net income — 2007		—		—		990			—			—			—			990			90			1,080
Other comprehensive loss:
Net unrealized losses on cash flow hedges, net of reclassification adjustments		—		—		—			(177	)		—			—			(177	)		(2	)		(179	)
Foreign currency translation adjustments		—		—		—			53			—			—			53			—			53
Pension benefits:
Net actuarial gain		—		—		—			53			—			—			53			—			53
Other postretirement benefits:
Prior service cost		—		—		—			1			—			—			1			—			1
Net actuarial gain		—		—		—			9			—			—			9			—			9

Total other comprehensive loss																		(61	)		(2	)		(63	)

Total comprehensive income																		929			88			1,017
Cash dividends — Common stock ($.39 per share)		—		—		(233	)		—			—			—			(233	)		—			(233	)
Sale of limited partner units of consolidated partnership		—		—		—			—			—			—			—			333			333
Dividends and distributions to noncontrolling interests		—		—		—			—			—			—			—			(75	)		(75	)
FIN 48 adjustment (Note 5)		—		—		(17	)		—			—			—			(17	)		—			(17	)
Purchase of treasury stock (Note 12)		—		—		—			—			—			(526	)		(526	)		—			(526	)
Stock-based compensation, including tax benefit		5		143		—			—			—			—			148			—			148
Other		—		—		1			—			—			—			1			3			4


Balance, December 31, 2007		608		6,748		(293	)		(121	)		—			(567	)		6,375			1,430			7,805
Comprehensive income:
Net income — 2008		—		—		1,418			—			—			—			1,418			174			1,592
Other comprehensive income:
Net unrealized gains on cash flow hedges, net of reclassification adjustments		—		—		—			453			—			—			453			2			455
Foreign currency translation adjustments		—		—		—			(76	)								(76	)		—			(76	)
Pension benefits:
Prior service cost		—		—		—			1			—			—			1			—			1
Net actuarial loss		—		—		—			(337	)								(337	)		(7	)		(344	)
Other postretirement benefits:
Prior service cost		—		—		—			9			—			—			9			—			9
Net actuarial loss		—		—		—			(9	)		—			—			(9	)		—			(9	)

Total other comprehensive income																		41			(5	)		36

Total comprehensive income																		1,459			169			1,628
Cash dividends — Common stock ($.43 per share)		—		—		(250	)		—			—			—			(250	)		—			(250	)
Sale of limited partner units of consolidated partnership		—		—		—			—			—			—			—			362			362
Dividends and distributions to noncontrolling interests		—		—		—			—			—			—			—			(122	)		(122	)
Issuance of common stock from 5.5% debentures conversion (Note 12)		2		25		—			—			—			—			27			—			27
Conversion of Williams Partners L.P. subordinated units to common units (Note 12)		—		1,225		—			—			—			—			1,225			(1,225	)		—
Purchase of treasury stock (Note 12)		—		—		—			—			—			(474	)		(474	)		—			(474	)
Stock-based compensation, including tax benefit		3		67		—			—			—			—			70			—			70
Other		—		9		(1	)		—			—			—			8			—			8


Balance, December 31, 2008	$	613	$	8,074	$	874		$	(80	)	$	—		$	(1,041	)	$	8,440		$	614		$	9,054

See accompanying notes.

THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS


	Years Ended December 31,
	2008			2007			2006
	(Millions)
OPERATING ACTIVITIES:
Net income	$	1,592		$	1,080		$	349
Adjustments to reconcile to net cash provided by operations:
Reclassification of deferred net hedge gains related to sale of power business		—			(429	)		—
Depreciation, depletion and amortization		1,310			1,082			866
Provision for deferred income taxes		611			370			154
Provision for loss on investments, property and other assets		166			162			26
Net (gain) loss on dispositions of assets and business		(36	)		16			(23	)
Gain on sale of contractual production rights		(148	)		—			—
Early debt retirement costs		1			19			31
Amortization of stock-based awards		31			70			44
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		329			(122	)		386
Inventories		(48	)		29			31
Margin deposits and customer margin deposits payable		88			(135	)		98
Other current assets and deferred charges		(76	)		(10	)		(30	)
Accounts payable		(343	)		26			(184	)
Accrued liabilities		7			(200	)		(110	)
Changes in current and noncurrent derivative assets and liabilities		(121	)		370			303
Other, including changes in noncurrent assets and liabilities		(8	)		(91	)		(51	)

Net cash provided by operating activities		3,355			2,237			1,890

FINANCING ACTIVITIES:
Proceeds from long-term debt		674			684			1,299
Payments of long-term debt		(665	)		(806	)		(777	)
Proceeds from issuance of common stock		32			56			34
Proceeds from sale of limited partner units of consolidated partnerships		362			333			863
Tax benefit of stock-based awards		21			32			16
Dividends paid		(250	)		(233	)		(207	)
Purchase of treasury stock		(474	)		(526	)		—
Payments for debt issuance costs and amendment fees		(4	)		(4	)		(37	)
Premiums paid on early debt retirements and tender offer		—			(27	)		(26	)
Dividends and distributions paid to noncontrolling interests		(122	)		(75	)		(36	)
Changes in cash overdrafts		—			52			(25	)
Other — net		(6	)		3			(1	)

Net cash provided (used) by financing activities		(432	)		(511	)		1,103

INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(3,475	)		(2,816	)		(2,509	)
Net proceeds from dispositions		119			12			23
Changes in accounts payable and accrued liabilities		81			(52	)		105
Purchases of investments/advances to affiliates		(111	)		(60	)		(49	)
Purchases of auction rate securities		—			(304	)		(386	)
Purchase of ARO trust investments		(31	)		—			—
Proceeds from sales of auction rate securities		—			353			414
Proceeds from sale of business		22			471			—
Proceeds from sale of contractual production rights		148			—			—
Proceeds from dispositions of investments and other assets		41			92			62
Proceeds from sale of ARO trust investments		14			—			—
Other — net		9			8			19

Net cash used by investing activities		(3,183	)		(2,296	)		(2,321	)

Increase (decrease) in cash and cash equivalents		(260	)		(570	)		672
Cash and cash equivalents at beginning of year		1,699			2,269			1,597

Cash and cash equivalents at end of year	$	1,439		$	1,699		$	2,269

See accompanying notes.

THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

Description of Business

Operations of our company are located principally in the United States and are organized into the following reporting segments: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids (Midstream), and Gas Marketing Services (Gas Marketing).

Exploration & Production includes natural gas development, production and gas management activities primarily in the Rocky Mountain and Mid-Continent regions of the United States and oil and natural gas interests in Argentina.

Gas Pipeline is comprised primarily of two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies. Gas Pipeline includes Northwest Pipeline GP (Northwest Pipeline), which extends from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington, and Transcontinental Gas Pipe Line Company, LLC (Transco), 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 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.

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.

Basis of Presentation

These consolidated financial statements and notes have been recast to reflect the retrospective application of the presentation and disclosure requirements of Statement of Financial Accounting Standards (SFAS) No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51.” Noncontrolling interests in consolidated subsidiaries are now presented in the consolidated balance sheet within equity as a component separate from stockholders’ equity. Net income now includes earnings attributable to both The Williams Companies, Inc., and the noncontrolling interests. Net income reported prior to the adoption of SFAS No. 160 is now equivalent to net income attributable to The Williams Companies, Inc. Earnings per share continues to be based on earnings attributable to only The Williams Companies, Inc.

Prior period amounts reported for Exploration & Production have been adjusted to reflect the presentation of certain revenues and costs on a net basis. These adjustments reduced revenues and reduced costs and operating expenses by the same amount, with no net impact on segment profit. The reductions were $72 million in 2007 and $77 million in 2006.

Discontinued operations

In accordance with the provisions related to discontinued operations within 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.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

Master limited partnerships

We currently own approximately 23.6 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. Considering the presumption of control of the general partner in accordance with Emerging Issues Task Force (EITF) Issue No. 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. 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 Issue No. 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.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions include:

	•		Impairment assessments of investments, long-lived assets and goodwill;

	•		Litigation-related contingencies;

	•		Valuations of derivatives;

	•		Hedge accounting correlations and probability;

	•		Environmental remediation obligations;

	•		Realization of deferred income tax assets;

	•		Valuation of Exploration & Production’s reserves;

	•		Asset retirement obligations;

	•		Pension and postretirement valuation variables.

These estimates are discussed further throughout these notes.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash and cash equivalents

Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Restricted cash

Current restricted cash is included in other current assets and deferred charges in 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 our California settlement. (See Note 16.) Noncurrent restricted cash is included in other assets and deferred charges in the Consolidated Balance Sheet and 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 noncurrent restricted cash is primarily invested in short-term money market accounts with financial institutions.

The classification of restricted cash is determined based on the expected term of the collateral requirement and not necessarily the maturity date of the investment.

Auction rate securities

An auction rate security is an instrument with a long-term underlying maturity, but for which an auction is conducted periodically, as specified, to reset the interest rate and allow investors to buy or sell the instrument. Our Consolidated Statement of Cash Flows reflects the gross amount of the purchases of auction rate securities and the proceeds 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 receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or 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

All inventories are stated at the lower of cost or market. We determine the cost of certain natural gas inventories held by Transco using the last-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 equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at Federal Energy Regulatory Commission (FERC)-prescribed rates. See Note 9 for depreciation rates used for major regulated gas plant facilities.

Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except as noted below for oil and gas exploration and production activities. See Note 9 for the estimated useful lives associated with our nonregulated assets.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Gains or losses from the ordinary sale or retirement of property, plant and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in other (income) expense — net included in operating income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment — net.

Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells, as applicable, are capitalized as incurred. If proved reserves are not found, such costs are charged to expense. Other exploration costs, including lease rentals, are expensed as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred. Depreciation, depletion and amortization is provided under the units of production method on a field basis.

We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in other (income) expense — net included in operating income, except for regulated entities, for which the liability is offset by a regulatory asset.

Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated 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 have goodwill of approximately $1 billion at December 31, 2008 and 2007, attributable to our Exploration & Production segment.

When a reporting unit is sold or classified as held for sale, any goodwill of that reporting unit is included in its carrying value for purposes of determining any impairment or gain/loss on sale. If a portion of a reporting unit with goodwill is sold or classified as held for sale and that asset group represents a business, a portion of the reporting unit’s goodwill is allocated to and included in the carrying value of that asset group. None of the operations sold during the periods reported represented reporting units with goodwill or businesses within reporting units to which goodwill was required to be allocated.

Judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Treasury stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to capital in excess of par value using the average-cost method.

Derivative instruments and hedging activities

We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.

We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheet in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual 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 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 may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We have also designated a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in other 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 in revenues. Gains or losses deferred in accumulated other comprehensive loss associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in accumulated other comprehensive loss until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in accumulated other comprehensive loss is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in revenues.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:

	•		Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;

	•		The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;

	•		Realized gains and losses on all derivatives that settle financially;

	•		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 Issue No. 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.

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 from the sale of gas upon settlement of the transportation and exchange imbalances.

As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our 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 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.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Midstream revenues

Natural gas gathering and processing services are performed under volumetric-based fee contracts, keep-whole agreements and percent-of-liquids arrangements. Revenues under volumetric-based fee contracts are recorded when services have been performed. Under keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the 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 revenues

Revenues generally are recorded when services are performed or products have been delivered.

Impairment of long-lived assets and investments

We evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. Except for proved and unproved properties discussed below, when an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with SFAS No. 144, 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

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of potentially recoverable reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. Costs of acquired 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 an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

Capitalization of interest

We capitalize interest during construction on major projects with construction periods of at least three months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds as a component of other income — net. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on the average interest rate on debt.

Employee stock-based awards

Compensation cost for share-based awards is based on the grant date fair value. Total stock-based compensation expense for the years ending December 31, 2008, 2007, and 2006, was $31 million, $70 million and $44 million, respectively, of which $1 million, $9 million and $3 million, respectively, is included in income (loss) from discontinued operations. Measured but unrecognized stock-based compensation expense at December 31, 2008, was approximately $57 million, which does not include the effect of estimated forfeitures of $3 million. This amount is comprised of approximately $7 million related to stock options and approximately $50 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.

Income taxes

We include the operations of our subsidiaries in our consolidated tax return. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

Earnings (loss) per common share

Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options, nonvested restricted stock units and, for applicable periods presented, convertible debt, unless otherwise noted.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 of other comprehensive income (loss).

Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains and losses which are reflected in the Consolidated Statement of Income.

Issuance of equity of consolidated subsidiary

Sales of residual equity interests in a consolidated subsidiary are accounted for as capital transactions. No adjustments to capital are made for sales of preferential interests in a subsidiary. No gain or loss is recognized on these transactions.

Recent Accounting Standards

In September 2006, the Financial Accounting Standards 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 was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB 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 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

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 FSP No. 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 Issue No. 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 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 2008, the FASB issued EITF 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 with EITF 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 apply EITF 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 issued EITF 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.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In December 2008, the FASB issued FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”. This FSP amends 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 disclosure 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 category 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 valuation techniques used to develop fair value measurements of plan assets at the annual reporting date. For fair value measurements using significant unobservable inputs (Level 3), an employer should disclose the effect of the measurements on changes in plan assets for the period. 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 years ending after December 15, 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 will assess the application of this Statement on our disclosures in our Consolidated Financial Statements.

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 November 2007, we sold substantially all of our power business for approximately $496 million in cash. In 2008, we received an additional $22 million of proceeds, including the final purchase price adjustments and $8 million from the sale of Hazleton.

Summarized Results of Discontinued Operations


	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	)

Income (loss) from discontinued operations before income taxes for the year ended December 31, 2008, includes $140 million of gains from the favorable resolution of matters involving pipeline transportation rates associated with our 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. (See Note 16.) These 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.

Income (loss) from discontinued operations before income taxes for the year ended December 31, 2007, includes a gain of $429 million (reported in revenues of discontinued operations) associated with the reclassification of deferred net hedge gains from accumulated other comprehensive income to earnings in second-quarter 2007. This reclassification was based on the determination that the hedged forecasted transactions were probable of not occurring due to the sale of our power business. This gain is partially offset by unrealized mark-to-market losses of approximately $23 million. Income (loss) from discontinued operations before income taxes also includes the results of our former power business operations.

Income (loss) from discontinued operations before income taxes for the year ended December 31, 2006, includes charges of $19 million for an adverse arbitration award related to our former chemical fertilizer business, $6 million for a loss contingency in connection with a former exploration business, and $15 million associated with an oil

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 taxes also includes the results of our former power business operations.

(Impairments) and gain (loss) on sales for 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.

Summarized 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

The December 31, 2008 and 2007, balances for derivative assets and derivative liabilities represent contracts remaining to be assigned to the purchaser of our former power business, entirely offset by reciprocal positions with that same party. We continue to pursue assignment of the remaining contracts which are with one counterparty as of December 31, 2008.

Note 3. Investing Activities

Investing Income


	Years Ended December 31,
	2008			2007			2006
	(Millions)
Equity earnings*	$	137		$	137		$	99
Income from investments*		1			—			—
Impairments of cost-based investments		(4	)		(1	)		(20	)
Interest income and other		57			121			89

Total investing income	$	191		$	257		$	168


*		Items also included in segment profit. (See Note 18.)

Impairments of cost-based investments for the year ended December 31, 2006, includes a $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.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Interest income and other for the years ended December 31, 2008 and 2007, includes $10 million and $14 million, respectively, of gains from sales of cost-based investments.

Investments


	December 31,
	2008		2007
	(Millions)
Equity method:
Gulfstream Natural Gas System, L.L.C. — 50%	$	525	$	439
Discovery Producer Services, L.L.C. — 60%*		184		215
Petrolera Entre Lomas S.A. — 40.8%		73		65
ACCROVEN — 49.3%		69		62
Other		96		95

		947		876
Cost method		24		25

	$	971	$	901


*		Our consolidated subsidiary, Williams Partners L.P., owns 60 percent. However, we continue to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company, which provide the other member of Discovery significant participatory rights such that we do not control the investment.

Differences 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 presented below, received from companies accounted for by the equity method were $167 million in 2008 and $118 million in 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

In addition, we contributed $90 million in 2008 and $38 million in 2007 to Gulfstream Natural Gas System, L.L.C. (Gulfstream).

Guarantees on Behalf of Investees

We have guaranteed commercial letters of credit totaling $20 million on behalf of ACCROVEN. These expire in January 2010 and have no carrying value.

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, 2008 and 2007.

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 in other (income) expense — net within segment 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 — net within segment costs and expenses also 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 in costs and operating expenses within segment costs and expenses. Associated with this charge is an interest expense accrual of $4 million, which is included in interest accrued. (See Note 16.)

Note 5. Provision for Income Taxes

The provision for income taxes from continuing operations includes:


	2008			2007			2006
	(Millions)
Current:
Federal	$	179		$	29		$	(9	)
State		24			9			3
Foreign		35			46			43

		238			84			37
Deferred:
Federal		466			422			146
State		(11	)		(4	)		4
Foreign		20			22			24

		475			440			174

Total provision	$	713		$	524		$	211

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Reconciliations from the provision for income taxes from continuing operations at the federal statutory rate to the realized provision for income taxes are as follows:


	2008			2007			2006
	(Millions)
Provision at statutory rate	$	777		$	511		$	209
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)		8			4			7
Foreign operations — net		(7	)		11			16
Federal income tax litigation		(5	)		—			(40	)
Nondeductible convertible debenture expenses		—			—			10
Impact of nontaxable noncontrolling interests		(53	)		(24	)		(7	)
Other — net		(7	)		22			16

Provision for income taxes	$	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 2006, respectively.

Income from continuing operations before income taxes includes $196 million, $169 million, and $144 million of foreign income in 2008, 2007, and 2006, respectively.

During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various tax filing positions, we apply the two-step process of recognition and measurement as required by FASB Interpretation No. 48, “Accounting for 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 estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within other — net in our reconciliation of the tax provision to the federal statutory rate.

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2008, and 2007, are as follows:


	2008		2007
	(Millions)
Deferred tax liabilities:
Property, plant and equipment	$	3,568	$	3,192
Derivatives — net		263		—
Investments		163		176
Other		112		89

Total deferred tax liabilities		4,106		3,457

Deferred tax assets:
Accrued liabilities		581		433
Derivatives — net		—		173
Foreign carryovers		3		50
Minimum tax credits		—		8
Other		55		53

Total deferred tax assets		639		717

Less valuation allowance		15		57

Net deferred tax assets		624		660

Overall net deferred tax liabilities	$	3,482	$	2,797

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The valuation allowance at December 31, 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. We do not expect to be able to utilize our $15 million of foreign deferred tax assets.

The reductions in foreign carryovers and the valuation allowance were primarily due to the restructuring of the European operations of our former power business.

Undistributed earnings of certain consolidated foreign subsidiaries at December 31, 2008, totaled approximately $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.

As 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 during 2008 and 2007, respectively. Approximately $81 million and $86 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2008 and 2007, respectively.

As of December 31, 2008, the Internal Revenue Service (IRS) examinations of our consolidated U.S. income tax returns for 2006 and 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 open to audit from 2003 through 2008. 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 have a material impact on our financial position.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 6. Earnings Per Common Share from Continuing Operations

Basic and diluted earnings per common share for the years ended December 31, 2008, 2007 and 2006, are:


	2008		2007		2006
	(Dollars in millions, except per-share
	amounts; shares in thousands)
Income from continuing operations attributable to The Williams Companies, Inc., available to common stockholders for basic and diluted earnings per common share (1)	$	1,334	$	847	$	347

Basic weighted-average shares (2)(3)		581,342		596,174		595,053
Effect of dilutive securities:
Nonvested restricted stock units		1,334		1,627		1,029
Stock options		3,439		4,743		4,440
Convertible debentures (3)		6,604		7,322		8,105

Diluted weighted-average shares		592,719		609,866		608,627

Earnings per common share from continuing operations:
Basic	$	2.30	$	1.42	$	.58

Diluted	$	2.26	$	1.40	$	.57


(1)		The years ended December 31, 2008, 2007 and 2006, include $2 million, $3 million and $3 million of interest expense, net of tax, associated with our convertible debentures. (See Note 12.) These amounts have been added back to income from continuing operations attributable to The Williams Companies, Inc., available to common stockholders to calculate diluted earnings per common share.

(2)		From the inception of our stock repurchase program in third-quarter 2007 to its completion in July 2008, we purchased 29 million shares of our common stock. (See Note 12.)

(3)		During third-quarter 2008, we issued 2 million shares of our common stock in exchange for a portion of our 5.5 percent convertible debentures. During January 2006, we issued 20 million shares of common stock related to a conversion offer for our 5.5 percent convertible debentures.

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.


	2008		2007		2006
Options excluded (millions)		6.4		.8		3.6
Weighted-average exercise prices of options excluded	$	26.41	$	40.07	$	36.14
Exercise price ranges of options excluded	$	16.40 - $42.29	$	36.66 - $42.29	$	26.79 - $42.29
Fourth quarter weighted-average market price	$	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 the subsidized retiree medical benefits, except for participants that were employees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups. Certain of these other postretirement benefit plans, particularly the subsidized retiree medical benefit plans, provide for retiree contributions and contain other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for these plans anticipates future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Benefit Obligations

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated. The annual measurement date for our plans is December 31. The sale of our power business in 2007 did not have a significant impact on our employee benefit plans. (See Note 2.)


							Other
							Postretirement
	Pension Benefits						Benefits
	2008			2007			2008			2007
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	896		$	931		$	284		$	312
Service cost		23			23			2			3
Interest cost		60			54			18			17
Plan participants’ contributions		—			—			5			5
Benefits paid		(70	)		(64	)		(23	)		(23	)
Medicare Part D subsidy		—			—			2			—
Plan amendment		—			—			(38	)		—
Actuarial (gain) loss		126			(48	)		23			(30	)

Benefit obligation at end of year		1,035			896			273			284

Change in plan assets:
Fair value of plan assets at beginning of year		1,074			1,005			192			180
Actual return on plan assets		(360	)		92			(62	)		15
Employer contributions		61			41			14			15
Plan participants’ contributions		—			—			5			5
Benefits paid		(70	)		(64	)		(23	)		(23	)

Fair value of plan assets at end of year		705			1,074			126			192

Funded status — overfunded (underfunded)	$	(330	)	$	178		$	(147	)	$	(92	)

Accumulated benefit obligation	$	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

The plan assets within our other postretirement benefit plans are intended to be used for the payment of benefits for certain groups of participants. The current liabilities for the other postretirement benefit plans represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.

The 2008 benefit obligation actuarial loss of $126 million for our pension plans is due primarily to the impact of decreases in the discount rate utilized to calculate the benefit obligation and changes to the mortality assumptions. The 2007 benefit obligation actuarial gain of $48 million for our pension plans is due primarily to the impact of changes in the discount rate assumptions utilized to calculate the benefit obligation. The 2008 benefit obligation actuarial loss of $23 million for our other postretirement benefit plans is due primarily to the impact of the decrease in the discount rate used to calculate the benefit obligation and changes to the mortality assumptions. The 2008 other postretirement benefits plan amendment of $38 million is due to an increase in the retirees’ cost-sharing percentage within our subsidized retiree medical benefit plans. The 2007 benefit obligation actuarial gain of $30 million for our

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

other postretirement benefit plans is due primarily to the impact of the increase in the discount rate used to calculate the benefit obligation and a decrease in the 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 of net periodic benefit expense allow for the delayed recognition of gains and losses caused by differences between actual and assumed outcomes for items such as estimated return on plan assets, or caused by changes in assumptions for items such as discount rates or estimated future compensation levels. The net actuarial gain (loss) presented in the following table and recorded in accumulated other comprehensive loss and net regulatory assets represents the cumulative net deferred gain (loss) from these types of differences or changes which have not yet been recognized in the Consolidated Statement of Income. A portion of the net actuarial gain (loss) is amortized over the participants’ average remaining future years of service, which is approximately 12 years for both our pension plans and our other postretirement benefit plans.

Pre-tax amounts not yet recognized in net periodic benefit expense at December 31 are as follows:


							Other
							Postretirement
	Pension Benefits						Benefits
	2008			2007			2008			2007
	(Millions)
Amounts included in accumulated other comprehensive loss:
Prior service (cost) credit	$	(5	)	$	(6	)	$	12		$	(5	)
Net actuarial gain (loss)		(708	)		(156	)		(8	)		7
Amounts included in net regulatory assets associated 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

Net Periodic Benefit Expense and Items Recognized in Other Comprehensive Income (Loss)

Net periodic benefit expense and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes for the years ended December 31, 2008, 2007, and 2006, consist of the following:


										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 in other 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 in other comprehensive income (loss)		551			(87	)					(2	)		(17	)


Total recognized in net periodic benefit expense and other comprehensive income (loss)	$	569		$	(63	)				$	10		$	(4	)

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with our FERC-regulated gas pipelines are recognized in net regulatory assets at December 31, 2008, and include net actuarial loss of $83 million, prior service credit of $22 million, and amortization of prior service credit of $1 million. At December 31, 2007, amounts recognized in net regulatory liabilities included net actuarial gain of $18 million and amortization of prior service credit of $2 million.

Pre-tax amounts expected to be amortized in net periodic benefit expense in 2009 are as follows:


			Other
	Pension		Postretirement
	Benefits		Benefits
	(Millions)
Amounts included in accumulated other comprehensive loss:
Prior service cost (credit)	$	1	$	(2	)
Net actuarial loss		45		—
Amounts included in net regulatory assets associated with our FERC-regulated gas pipelines:
Prior service credit		N/A	$	(5	)
Net actuarial loss		N/A		3

The differences in the amount of actuarially determined net periodic benefit expense for our other postretirement benefit plans and the other postretirement benefit costs recovered in rates for our FERC-regulated gas pipelines are deferred as a regulatory asset or liability. At December 31, 2008, we have net regulatory assets of $26 million and at December 31, 2007, we had net regulatory liabilities of $28 million related to these deferrals. These amounts will be reflected in future rates based on the gas pipelines’ rate structures.

Key Assumptions

The weighted-average assumptions utilized to determine benefit obligations as of December 31, 2008, and 2007, are as follows:


							Other
							Postretirement
	Pension Benefits						Benefits
	2008			2007			2008			2007
Discount rate		6.08	%		6.41	%		6.00	%		6.40	%
Rate of compensation increase		5.00			5.00			N/A			N/A

The weighted-average assumptions utilized to determine net periodic benefit expense for the years ended December 31, 2008, 2007, and 2006, are as follows:


										Other
	Pension Benefits									Postretirement Benefits
	2008			2007			2006			2008			2007			2006
Discount rate		6.41	%		5.80	%		5.65	%		6.40	%		5.80	%		5.60	%
Expected long-term rate of return on plan assets		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

The discount rates for our pension and other postretirement benefit plans were determined separately based on an approach specific to our plans. The year-end discount rates were determined considering a yield curve comprised of high-quality corporate bonds published by a large securities firm and the timing of the expected benefit cash flows of each plan.

The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy Statement, and capital market projections for the asset classifications in which the portfolio is invested and the target weightings of each asset classification.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The expected return on plan assets component of net periodic benefit expense is calculated using the market-related value of plan assets. For assets held in our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect amortization of gains or losses associated with the difference between the expected return on plan assets and the actual return on plan assets over a five-year period. The market-related value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.

The mortality assumptions used to determine the obligations for our pension and other postretirement benefit plans are related to the experience of the plans and the best estimate of expected plan mortality. The selected mortality tables are among the most recent tables available.

The assumed health care cost trend rate for 2009 is 8.6 percent, and systematically decreases to 5.1 percent by 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
	(Millions)
Effect on total of service and interest cost components	$	3	$	(4	)
Effect on other postretirement benefit obligation		53		(42	)

Plan Assets

The investment policy for our pension and other postretirement benefit plans articulates an investment philosophy in accordance with ERISA, which governs the investment of the assets in a diversified portfolio. The investment strategy for the assets of the pension plans and approximately one half of the assets of the other postretirement benefit plans include maximizing returns with reasonable and prudent levels of risk. The investment returns on the approximate one half of remaining assets of the other postretirement benefit plans is subject to federal income tax; therefore, the investment strategy also includes investing in a tax efficient manner.

The following table presents the weighted-average asset allocations at December 31, 2008, and 2007 and target asset allocations at December 31, 2008, by asset category.


										Other
	Pension Benefits									Postretirement Benefits
	2008			2007			Target			2008			2007			Target
Equity securities		78	%		84	%		84	%		71	%		79	%		80	%
Debt securities		17			12			16			17			12			20
Other		5			4			—			12			9			—

		100	%		100	%		100	%		100	%		100	%		100	%

Included in equity securities are investments in commingled funds that invest entirely in equity securities and comprise 24 percent at December 31, 2008, and 40 percent at December 31, 2007, of the pension plans’ weighted-average assets, and 13 percent at December 31, 2008, and 29 percent at December 31, 2007, of the other postretirement benefit plans’ weighted-average assets. During 2008, a commingled fund held within the pension plans and the other postretirement benefit plans was replaced with direct investments in certain equity securities. Other assets are comprised primarily of cash and cash 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 approximately 30-35 percent, as allowed in the investment policy. The reallocation is expected to be completed during the first quarter of 2009.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 2008, 11 active investment managers and one passive investment manager managed substantially all of the pension and other postretirement benefit plans’ funds. Each of the managers had responsibility for managing a specific portion of these assets.

Plan Benefit Payments and Employer Contributions

Following are the expected benefits to be paid by the plans and the expected federal prescription drug subsidy to be received in the next ten years. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions.


					Federal
			Other		Prescription
	Pension		Postretirement		Drug
	Benefits		Benefits		Subsidy
	(Millions)
2009	$	44	$	17	$	(2	)
2010		38		18		(2	)
2011		38		18		(2	)
2012		42		18		(2	)
2013		42		18		(2	)
2014 - 2018		263		96		(13	)

We expect to contribute approximately $61 million to our pension plans and approximately $16 million to our other postretirement benefit plans in 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 plans’ guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $24 million, $22 million, and $19 million in 2008, 2007, and 2006, respectively. A fund within one of our defined contribution plans is a nonleveraged employee stock ownership plan (ESOP). The shares held by the ESOP are treated as outstanding when computing earnings per share and the dividends on the shares held by the ESOP are recorded as a component of retained earnings. Since 2006 there have been no contributions to this ESOP, other than dividend reinvestment, as contributions for purchase of our stock are no longer allowed within this defined contribution plan.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8. Inventories

Inventories at December 31, 2008, and 2007, 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

Inventories are primarily determined using the average-cost method.

Note 9. Property, Plant and Equipment

Property, plant and equipment — net at December 31, 2008 and 2007, is as follows:


	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


(a)		Oil and gas properties are depleted using the units-of-production method. See Note 1 of Notes to Consolidated Financial Statements for more information. Balances include $571 million at December 31, 2008, and $378 million at December 31, 2007, of capitalized costs related to properties with unproven reserves not yet subject to depletion at Exploration & Production.

(b)		Estimated useful life and depreciation rates are presented as of December 31, 2008.

(c)		Certain assets above are currently pledged as collateral to secure debt. See Note 11 of Notes to Consolidated Financial Statements.

(d)		Construction in progress balances not yet subject to depreciation.

Depreciation, depletion and amortization expense for property, plant and equipment — net was $1.3 billion in 2008, $1.1 billion in 2007, and $863 million in 2006.

Regulated property, plant and equipment includes approximately $1.1 billion at December 31, 2008 and 2007 related to amounts in excess of the original cost of the regulated facilities within Gas Pipeline as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset Retirement Obligations

Our asset retirement obligations at December 31, 2008 and 2007 are $644 million and $399 million, respectively. The increases in the obligations in 2008 are primarily due to revisions in our estimation of our asset retirement

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligations in our Midstream and Gas Pipeline segments and increased asset additions in our Exploration and Production 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 of other assets and deferred charges and 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 to accounts payable. Accounts payable includes approximately $95 million of these negative balances at December 31, 2008 and $96 million at December 31, 2007.

Accrued liabilities at December 31, 2008, and 2007, are as follows:


	2008		2007
	(Millions)
Taxes other than income taxes	$	223	$	169
Interest		185		208
Employee costs		168		174
Income taxes		165		75
Accrual for Gulf Liquids litigation contingency*		51		94
Guarantees and payment obligations related to WilTel		38		39
Estimated rate refund liability		14		96
Other, including other loss contingencies		326		303

	$	1,170	$	1,158


*		Includes interest of $14 million in 2008 and $25 million in 2007.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11. Debt, Leases and Banking Arrangements

Long-Term Debt

Long-term debt at December 31, 2008 and 2007, is:


	Weighted-
	Average
	Interest			December 31,
	Rate (1)			2008 (2)			2007
				(Millions)
Secured (3)
6.62%-9.45%, payable through 2016		8.0	%	$	123		$	148
Adjustable rate, payable through 2016		3.9	%		54			64
Capital lease obligations		6.0	%		5			10
Unsecured
5.5%-10.25%, payable through 2033 (4)		7.6	%		7,447			7,103
Revolving credit loans		—			—			250
Adjustable rate, payable through 2012		1.2	%		250			325

Total long-term debt, including current portion					7,879			7,900
Long-term debt due within one year					(196	)		(143	)

Long-term debt				$	7,683		$	7,757


(1)		At December 31, 2008.

(2)		Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, repurchase equity and incur additional debt.

(3)		Includes $177 million and $212 million at December 31, 2008 and 2007, respectively, collateralized by certain fixed assets of two of our Venezuelan subsidiaries with a net book value of $324 million and $351 million at December 31, 2008 and 2007, respectively. The non-recourse debt at both subsidiaries is currently in technical default triggered by past due payments from their sole customer, Petróleos de Venezuela S.A. (PDVSA), under the related services contracts. We are in discussion with the associated lenders to obtain waivers. This has no impact on our other debt agreements or our liquidity.

(4)		2007 includes 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)

We have an unsecured, $1.5 billion credit facility with a maturity date of May 1, 2012. Northwest Pipeline and Transco each have access to $400 million under the credit facility to the extent not otherwise utilized by us. 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 0.125 percent) based on the unused portion of the credit facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the credit agreement include the following:

•

Our ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2008, we are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, is approximately 40 percent.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

•

Ratio of debt to capitalization must be no greater than 55 percent for Northwest Pipeline and Transco. At December 31, 2008, they are in compliance with this covenant as their ratio of debt to capitalization, as calculated under this covenant, is approximately 36 percent for Northwest Pipeline and 26 percent for Transco.

We 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 $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, 2008, they had a $250 million term loan outstanding and no amounts outstanding under the $200 million credit facility. Significant financial covenants under this credit agreement include the following:

	•		Williams Partners L.P. is required to maintain a ratio of indebtedness to EBITDA (each as defined in the credit agreement) of no greater than 5.0 to 1.0. At December 31, 2008, they are in compliance with this covenant as their ratio is 2.98.

	•		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.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2008, no loans are outstanding under our credit facilities. Letters of credit issued under 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 6.05 percent senior unsecured notes due 2018 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 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.

Aggregate minimum maturities of long-term debt (excluding capital leases and unamortized discount and premium) for each of the next five years are as follows:


	(Millions)
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.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash payments for interest (net of amounts capitalized) were as follows: 2008 — $592 million; 2007 — $634 million; and 2006 — $611 million.

Leases-Lessee

Future minimum annual rentals under noncancelable operating leases as of December 31, 2008, are payable as follows:


	(Millions)
2009	$	69
2010		53
2011		26
2012		23
2013		19
Thereafter		45

Total	$	235

Total rent expense was $87 million in 2008 and $68 million in 2007 and 2006. Rent expense reported as discontinued operations, primarily related to a tolling agreement, was $148 million and $175 million in 2007 and 2006, respectively. Rent expense in discontinued operations was offset by approximately $276 million in 2007 and $264 million in 2006 resulting from sales and other transactions made possible by the tolling agreement. This tolling agreement was included in the sale of our power business in 2007. (See Note 2.)

Note 12. Stockholders’ Equity

In July 2007, our Board of Directors authorized the repurchase of up to $1 billion of our common stock. During 2007, we purchased 16 million shares for $526 million (including transaction costs) at an average cost of $33.08 per share. During 2008, we purchased 13 million shares of our common stock for $474 million (including transaction costs) at an average cost of $36.76 per share. We completed our $1 billion stock repurchase program in July 2008. Our overall average cost per share was $34.74. This stock repurchase is recorded in treasury stock on our Consolidated Balance Sheet.

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 $220 million of the debentures in exchange for 20 million 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 noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheet. Due to the conversion of the subordinated units, these original issuances of partnership units no longer have preferential rights and now represent the lowest level of equity securities issued by Williams Partners L.P. In accordance with our policy regarding the issuance of equity of a consolidated subsidiary, such issuances of nonpreferential equity are accounted for as capital transactions and no gain or loss is recognized. Therefore, as a result of the first-quarter conversion, we recognized a decrease to noncontrolling interests in consolidated subsidiaries and a corresponding increase to capital in excess of par value of approximately $1.2 billion.

We maintain a Stockholder Rights Plan, as amended and restated on September 21, 2004, and further amended May 18, 2007, and October 12, 2007, under which each outstanding share of our common stock has a right (as defined in the plan) attached. Under certain conditions, each right may be exercised to purchase, at an exercise price

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of $50 (subject to adjustment), one two-hundredth of a share of Series A Junior Participating Preferred Stock. The rights may be exercised only if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or more of our common stock or commences an offer for 15 percent or more of our common stock. The plan contains a mechanism to divest of shares of common stock if such stock in excess of 14.9 percent was acquired inadvertently or without knowledge of the terms of the rights. The rights, which until exercised do not have voting rights, expire in 2014 and may be redeemed at a price of $.01 per right prior to their expiration, or within a specified period of time after the occurrence of certain events. In the event a person becomes the owner of more than 15 percent of our common stock, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, our common stock having a value equal to two times the exercise price of the right. In the event we are engaged in a merger, business combination, or 50 percent or more of our assets, cash flow or earnings power is sold or transferred, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the right.

Note 13. Stock-Based Compensation

Plan Information

On May 17, 2007, our stockholders approved a plan that provides common-stock-based awards to both employees and nonmanagement directors. The plan generally contains terms and provisions consistent with the previous plans. The plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options and reserves 19 million shares for issuance. Restricted stock units are valued at market value on the grant date of the award and generally vest over three years. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of the grant and can be subject to accelerated vesting if certain future stock prices or if specific financial performance targets are achieved. Stock options generally expire 10 years after grant. At December 31, 2008, 33 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 16 million shares were available for future grants. At December 31, 2007, 37 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 19 million shares were available for future grants.

Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorizes up to 2 million shares of our common stock to be available for sale under the plan. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of: (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the Plan was approved by the stockholders. The first offering under the ESPP commenced on October 1, 2007 and ended on December 31, 2007. Subsequent offering periods are from January through June and from July through December. Generally, all employees are eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an 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 WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following summary reflects stock option activity and related information for the year ending December 31, 2008.


				Weighted-
				Average		Aggregate
				Exercise		Intrinsic
Stock Options	Options			Price		Value
	(Millions)					(Millions)
Outstanding at December 31, 2007		13.2		$	16.62
Granted		1.0		$	36.50
Exercised		(2.3	)	$	14.45	$	49

Cancelled		(.4	)	$	33.44

Outstanding at December 31, 2008		11.5		$	18.10	$	35

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 was $49 million, $74 million, and $36 million, respectively.

The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 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 $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 $32 million, $56 million and $34 million during 2008, 2007 and 2006, respectively. The tax benefit realized from stock options exercised during 2008 was $17 million, $27 million for 2007, and $14 million for 2006.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Nonvested Restricted Stock Units

Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit expense, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2008.


				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 the end-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


	2008		2007		2006
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	30.13	$	30.79	$	23.39

Total fair value of restricted stock units vested during the year ($’s in millions)	$	48	$	33	$	15

Performance-based shares granted under the Plan represent 33 percent of nonvested restricted stock units outstanding at December 31, 2008. These grants are earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Note 14. Fair Value Measurements

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 FSP 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). 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.

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.

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 of exchange-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 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 WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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			Other
	Derivatives			Assets
	(Millions)
Balance as of January 1, 2008	$	(14	)	$	10
Realized and unrealized gains (losses):
Included in income from continuing operations		88			(3	)
Included in other 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 in income from continuing operations relating to instruments still held at December 31, 2008	$	—		$	—

Realized and unrealized gains (losses) included in income from continuing operations for the above period are reported in revenues in our Consolidated Statement of Income. Reclassification of fair value into and out of Level 3 is made at the end of each quarter.

Note 15. Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk

Financial Instruments

Fair-value methods

We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:

Cash and cash equivalents and restricted cash: The carrying amounts reported in the balance sheet approximate fair value due to the short-term maturity of these instruments.

Notes and other noncurrent receivables, 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.

Cost-based investments and other securities: This includes cost-based investments, auction rate securities, ARO Trust investments and held-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 in other current assets and deferred charges in the Consolidated Balance Sheet. In 2008, auction rate securities are classified within investments in the Consolidated Balance Sheet due to auction failures. The ARO Trust investments are classified as available-for-sale and are reported in other assets and deferred charges in 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 similar terms and credit ratings. At December 31, 2008 and 2007, approximately 95 percent and 90 percent, respectively, of our long-term debt was publicly traded.

Guarantees: The guarantees represented in the table below consist primarily of guarantees we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on certain lease performance obligations. To estimate the fair value of the guarantees, the estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate for each

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 futures, forwards, swaps, and options. See Note 14 for discussion of valuation of our energy derivatives.

Carrying amounts and fair values of our financial instruments


	2008						2007
	Carrying						Carrying
Asset (Liability)	Amount			Fair Value			Amount			Fair Value
	(Millions)
Cash and cash equivalents	$	1,439		$	1,439		$	1,699		$	1,699
Restricted cash (current and noncurrent)		133			133			127			127
Cost-based investments and other securities		37			20	(a)		45			20	(a)
Notes and other noncurrent receivables		2			2			4			4
Margin deposits		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		(30	)		(30	)		(10	)		(10	)
Net energy derivatives(c):
Energy commodity cash flow hedges		458			458			(268	)		(268	)
Other energy derivatives		24			24			(100	)		(100	)


(a)		Excludes certain international investments in companies that are not publicly traded and therefore it is not practicable to estimate fair value. (See Note 3.)

(b)		Excludes capital leases. (See Note 11.)

(c)		A portion of these derivatives is included in assets and liabilities of discontinued operations. (See Note 2.)

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 are over-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.

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 contracts are generally valued based on option pricing models considering prices of the

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 forecasted sales of NGLs attributable to commodity price risk. Certain of these derivatives have been designated as cash flow hedges under SFAS No. 133.

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 enter into natural gas futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Exploration & Production’s cash flow hedges are expected to be highly 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 into revenues in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During 2008, we reclassified approximately $2 million of net losses 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 in revenues of discontinued operations) associated with the reclassification of deferred net hedge gains of our former power business from accumulated other comprehensive income/loss to 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 $2 million and $14 million of net losses from hedge ineffectiveness are included in revenues during 2008 and 2007, respectively. For 2008 and 2007, there are no derivative gains or losses excluded from the assessment of hedge effectiveness. As of December 31, 2008, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to four years. Based on recorded values at December 31, 2008, approximately $189 million of net gains (net of income 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.

Other energy derivatives

Our Gas 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 in revenues in the Consolidated Statement of Income. Even though they do not qualify for hedge accounting (see derivative instruments and hedging activities in Note 1 for a description of hedge accounting), certain of these derivatives hedge our future cash flows on an economic basis.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Other energy-related contracts

We also hold significant nonderivative energy-related contracts, such as storage and transportation agreements, in our 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 16), we have issued guarantees and other similar arrangements as discussed below.

In connection with agreements executed to resolve take-or-pay and other contract claims and to amend gas purchase contracts, Transco entered into certain settlements with producers that 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, 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 exceed the minimum purchase price.

We are required by certain 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 taxes required to be paid by the 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.

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 $42 million at December 31, 2008, and $44 million at December 31, 2007. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is approximately $38 million at December 31, 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

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts and notes receivable

The following table summarizes concentration of receivables including those related to discontinued operations (see Note 2), net of allowances, by product or service at December 31, 2008 and 2007:


	2008		2007
	(Millions)
Receivables by product or service:
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		—		55
Other		49		53

Total	$	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. 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 within sale of natural gas and related products and services in 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 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. Additional collateral support could include letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2008 and 2007, we did not incur any significant losses due to counterparty bankruptcy filings.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2008, is summarized as follows.


	Investment
Counterparty Type	Grade(a)		Total
	(Millions)
Gas and electric utilities	$	2	$	2
Energy marketers and traders		127		896
Financial institutions		1,558		1,559

	$	1,687		2,457

Credit reserves				(6	)

Gross credit exposure from derivatives			$	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, 2008, excluding collateral support discussed below, is summarized as follows.


	Investment
Counterparty Type	Grade(a)		Total
	(Millions)
Gas and electric utilities	$	—	$	1
Energy marketers and traders		79		80
Financial institutions		600		600

	$	679		681

Credit reserves				(6	)

Net credit exposure from derivatives			$	675


(a)		We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s of BBB- or Moody’s Investors Service rating of Baa3 in 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 2008, 2007 and 2006, there were no customers for which our sales exceeded 10 percent of our consolidated revenues.

Note 16. Contingent Liabilities and Commitments

Issues Resulting from California Energy Crisis

Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the U.S. Federal Energy Regulatory Commission (FERC). These challenges included refund proceedings, summer 2002 90-day contracts, investigations of alleged market manipulation including withholding, gas indices and other gaming of the market, new long-term

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

power sales to the State of California that were subsequently challenged and civil litigation relating to certain of these issues. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.

As a result of a June 2008 U.S. Supreme Court decision, certain contracts that we entered into during 2000 and 2001 may be subject to partial refunds depending on the results of further proceedings at the FERC. These contracts, under which we sold electricity, totaled approximately $89 million in revenue. While we are not a party to the cases involved in the U.S. Supreme Court decision, the buyer of electricity from us is a party to the cases and claims that we must refund to the buyer any loss it suffers due to the FERC’s reconsideration of the contract terms at issue in the decision. The FERC has directed the parties to provide additional information on certain issues remanded by the U.S. Supreme Court, but delayed the submission of this information to permit the parties to explore possible settlements of the contractual disputes.

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 $24 million at December 31, 2008. Collection of the interest and the payment of interest on refund amounts from the escrow accounts is subject to the conclusion of this proceeding. Therefore, we continue to participate in the FERC refund case and related proceedings.

Challenges to virtually every aspect of the refund proceedings, including the refund period, continue to be made. Because of our settlements, we do not expect that the final resolution of refund obligations will have a material impact on 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

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in:

	•		State court litigation in California brought on behalf of certain business and governmental entities that purchased gas for their use.

	•		Class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri, Tennessee and Wisconsin brought on behalf of direct and indirect purchasers of gas in those states.

	•		A Missouri class action and the cases from other jurisdictions were transferred to the federal court in Nevada. In 2008, the federal court in Nevada granted summary judgment in the Colorado case in favor of us and most of the other defendants, and on January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal. We expect that the Colorado plaintiffs will appeal.

	•		On October 29, 2008, the Tennessee appellate court reversed the state 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.

	•		On January 13, 2009, the Missouri state court dismissed a case for lack of standing. We expect that the decision will be appealed.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Environmental Matters

Continuing operations

Since 1989, our Transco subsidiary has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At December 31, 2008, we had accrued liabilities of $5 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than $500,000, which is included in the environmental accrual discussed above. We expect that these costs will be recoverable through Transco’s rates.

Beginning in the mid-1980s, our Northwest Pipeline subsidiary evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is conducting additional remediation activities at certain sites to comply with Washington’s current environmental standards. At December 31, 2008, we have accrued liabilities of $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, 2008, we have accrued liabilities totaling $6 million for these costs.

In April 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued an NOV to Williams Four Corners, LLC (Four Corners) that alleged various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. In December 2007, the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV to Four Corners that alleged air emissions permit exceedances for three glycol dehydrators at one of our compressor facilities and proposed a penalty of approximately $103,000. We are discussing the proposed penalties with the NMED.

In March 2008, the EPA proposed a penalty of $370,000 for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in Colorado and for alleged permit violations at a compressor station. We met with the EPA and are exchanging information in order to resolve the issues.

In September 2007, the EPA requested, and our Transco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued NOVs alleging violations of Clean Air Act

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

requirements at these compressor stations. We met with the EPA in May 2008 and submitted our response denying the allegations in 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, 2008, we have accrued liabilities of $9 million for such excess costs.

Other

At December 31, 2008, we have accrued environmental liabilities of $14 million related primarily to our:

	•		Potential indemnification obligations to purchasers of our former retail petroleum and refining operations;

	•		Former propane marketing operations, bio-energy facilities, petroleum products and natural gas pipelines;

	•		Discontinued petroleum refining facilities;

	•		Former exploration and production and mining operations.

Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws.

Summary of environmental matters

Actual costs incurred for these matters could be substantially greater than amounts accrued depending on the actual number of contaminated sites identified, the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors, but the amount cannot be reasonably estimated at this time.

Other Legal Matters

Will Price (formerly Quinque)

In 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held in April 2005. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Grynberg

In 1998, the U.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 would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. The District Court dismissed all claims against us and our wholly owned subsidiaries. The matter is on appeal to the Tenth Circuit Court of Appeals.

In August 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 state court in Denver, Colorado. The plaintiffs alleged we used mismeasurement techniques that distorted the British Thermal Unit heating content of natural gas resulting in the underpayment of royalties to them and other independent natural gas producers. They also alleged we took inappropriate deductions from the gross value of their natural gas and made other royalty valuation errors. Under various theories of relief, they were seeking actual damages between $2 million and $20 million based on interest rate variations and punitive damages in the amount of approximately $1 million. In 2005, the parties agreed to dismiss mismeasurement claims. In September 2008, the court ruled in our favor on motions for summary judgment dismissing various claims. Trial on the remaining breach of contract and accounting claims occurred in 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 a subsidiary known as Williams Communications, and certain corporate officers, acted jointly and separately to inflate the price of WilTel securities. WilTel was dismissed as a defendant as a result of its bankruptcy.

On July 6, 2007, the court granted various defendants’ motions for summary 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 because our insurance coverage has been fully utilized by the settlement described above. The extent of any such obligation is presently unknown and cannot be estimated, but it is reasonably possible that our exposure could materially exceed amounts accrued for this matter.

TAPS Quality Bank

One of our subsidiaries, Williams Alaska Petroleum, Inc. (WAPI), has 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. In 2004, the FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions, and 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 WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In 2006, the FERC entered its final order, which the RCA 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 upheld the FERC’s order. We have paid substantially all amounts invoiced by the Quality Bank Administrator and third parties, except certain disputed amounts which remain accrued.

In 2008, we concluded that the likelihood of successful appeal by the counterparties was remote, and we reduced remaining amounts accrued in excess of our estimated remaining obligation by $54 million. On January 12, 2009, this matter concluded when the U.S. Supreme Court denied a counterparty’s request for a writ of certiorari to appeal the ruling of the D.C. Circuit Court of 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. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.

In 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual and punitive damages verdict against us and Gulf Liquids. Based on our interpretation of the jury verdicts, we recorded a charge based on our estimated exposure for actual damages of approximately $68 million plus potential interest of approximately $20 million. In addition, we concluded that it was reasonably possible that any ultimate judgment might have included additional amounts of approximately $199 million in excess of our accrual, which primarily represented our estimate of potential punitive damage exposure under Texas law.

From May through October 2007, the court entered seven post-trial orders in the case (interlocutory orders) which, among other things, overruled the verdict award of tort and punitive damages as well as any damages against us. The court also denied the plaintiffs’ claims for attorneys’ fees. On January 28, 2008, the court issued its judgment awarding damages against Gulf Liquids of approximately $11 million in favor of Gulsby and approximately $4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby, Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In February 2009, we settled with certain of these parties and reduced our liability as of December 31, 2008, by $43 million, including $11 million of interest. If the judgment is upheld on appeal, our remaining liability will be substantially less than the amount of our accrual for these matters.

Wyoming severance taxes

In August 2006, the Wyoming Department of Audit (DOA) assessed our subsidiary, Williams Production RMT Company, additional severance tax and interest for the production years 2000 through 2002. In addition, the DOA notified us of an increase in the taxable value of our interests for ad valorem tax purposes. We disputed the DOA’s interpretation of the statutory obligation and appealed this assessment to the Wyoming State Board of Equalization (SBOE). The SBOE upheld the assessment and remanded it to the DOA to address the disallowance of a credit. We appealed to the Wyoming Supreme Court. In December 2008, the Wyoming Supreme Court ruled against us. The negative assessment for the 2000-2002 time period resulted in additional severance and ad valorem taxes of $4 million. We have accrued a total liability of $39 million related to this matter representing our exposure, including interest, through 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 reached a partial settlement agreement for an amount that was previously accrued. The partial settlement has received preliminary approval by

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the court, and we anticipate trial in late 2009 on remaining issues related to royalty payment calculation and obligations under specific lease provisions. We are not able to estimate the amount of any additional exposure at this time.

Certain other royalty matters are currently being litigated by other producers with a federal regulatory agency in Colorado and with a state agency in New Mexico. Although we are not a party to these matters, the final outcome of those cases might lead to a 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.

At December 31, 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.

In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.

Summary

Litigation, arbitration, regulatory matters, and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

Commitments

Commitments for construction and acquisition of property, plant and equipment are approximately $472 million at December 31, 2008.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 17. Accumulated Other Comprehensive Loss

The table below presents changes in the components of accumulated other comprehensive loss.


	Income (Loss)
																Other
																Postretirement
										Pension Benefits						Benefits
				Foreign			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 noncontrolling interests		2			—			—			—			—			—			—			2

Balance at December 31, 2007		(157	)		129			—			(4	)		(97	)		(3	)		11			(121	)


2008 Change:
Pre-income tax amount		714			(76	)		—			—			(565	)		16			(15	)		74
Income tax (provision) benefit		(270	)		—			—			—			213			(8	)		6			(59	)
Net reclassification into earnings of derivative instrument losses (net of a $7 million income tax benefit)		11			—			—			—			—			—			—			11
Amortization included in net periodic benefit expense		—			—			—			1			13			1			—			15
Income tax provision on amortization		—			—			—			—			(5	)		—			—			(5	)

		455			(76	)		—			1			(344	)		9			(9	)		36

Allocation of other comprehensive income (loss) to noncontrolling interests		(2	)		—			—			—			7			—			—			5

Balance at December 31, 2008	$	296		$	53		$	—		$	(3	)	$	(434	)	$	6		$	2		$	(80	)


*		Includes $1 million for the Net Actuarial Loss of an equity method investee.

**		Includes a $429 million reclassification into earnings of deferred net hedge gains related to the sale of our power business. (See Note 2.)

Note 18. Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Our master limited partnerships, Williams Partners L.P. and Williams Pipeline Partners L.P., are consolidated within our Midstream and Gas Pipeline segments, respectively. (See Note 1.) Other primarily consists of corporate operations.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Performance Measurement

We currently evaluate performance based on segment profit (loss) from operations, which includes segment revenues from external and internal customers, segment costs and expenses, equity earnings (losses) and income (loss) from investments. The accounting policies of the segments are the same as those described in Note 1. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

The primary types of costs and operating expenses by segment can be generally summarized as follows:

	•		Exploration & Production — depletion, depreciation and amortization, lease operating expenses and operating taxes;

	•		Gas Pipeline — depreciation and operation and maintenance expenses;

	•		Midstream Gas & Liquids — commodity purchases (primarily for NGL, crude and olefin marketing, shrink, feedstock and fuel), depreciation, and operation and maintenance expenses;

	•		Gas Marketing Services — commodity purchases primarily in support of commodity marketing and risk management activities.

Energy commodity hedging by our business units may be done through intercompany derivatives with our Gas Marketing Services segment which, in turn, enters into offsetting derivative contracts with unrelated third parties. Gas Marketing Services bears the counterparty performance risks associated with the unrelated third parties in these transactions. Additionally, Exploration & Production may enter into transactions directly with third parties under their credit agreement. (See Note 11.) Exploration & Production bears the counterparty performance risks associated with the unrelated third parties in these transactions.

External revenues of our Exploration & Production segment include 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 includes revenues from external customers based on product shipment origin and long-lived assets based upon physical location.


	United States		Other		Total
	(Millions)
Revenues from external customers:
2008	$	11,924	$	428	$	12,352
2007		10,065		421		10,486
2006		8,905		394		9,299
Long-lived assets:
2008	$	18,419	$	659	$	19,078
2007		16,279		713		16,992
2006		14,487		682		15,169

Our foreign operations are primarily located in Venezuela, Canada, and Argentina. Long-lived assets are comprised of property, plant and equipment, goodwill and other intangible assets.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table reflects the reconciliation of segment revenues and segment profit (loss) to revenues and operating income (loss) as reported in the Consolidated Statement of Income and other financial information related to long-lived assets.


						Midstream		Gas
	Exploration &			Gas		Gas &		Marketing
	Production			Pipeline		Liquids		Services			Other			Eliminations			Total
	(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	$	(266	)	$	1,336	$	4,094	$	4,128		$	7		$	—		$	9,299
Internal		1,677			12		65		921			20			(2,695	)		—

Total revenues	$	1,411		$	1,348	$	4,159	$	5,049		$	27		$	(2,695	)	$	9,299

Segment profit (loss)	$	552		$	467	$	675	$	(195	)	$	(13	)	$	—		$	1,486
Less equity earnings		22			37		40		—			—			—			99

Segment operating income (loss)	$	530		$	430	$	635	$	(195	)	$	(13	)	$	—			1,387

General corporate expenses																		(132	)
Securities litigation settlement and related costs																		(167	)

Total operating income																	$	1,088

Other financial information:
Additions to long-lived assets	$	1,496		$	913	$	279	$	1		$	18		$	—		$	2,707
Depreciation, depletion & amortization	$	360		$	282	$	203	$	7		$	11		$	—		$	863

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table reflects total assets and equity method investments by reporting segment.


	Total Assets									Equity Method Investments
	December 31,			December 31,			December 31,			December 31,		December 31,		December 31,
	2008			2007			2006			2008		2007		2006
	(Millions)
Exploration & Production (1)	$	10,286		$	8,692		$	7,851		$	87	$	72	$	59
Gas Pipeline		9,149			8,624			8,332			570		483		432
Midstream Gas & Liquids		7,024			6,604			5,562			290		321		323
Gas Marketing Services (2)		3,064			4,437			5,519			—		—		—
Other		3,532			3,592			3,923			—		—		—
Eliminations		(7,055	)		(7,073	)		(7,187	)		—		—		—

		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 2008 increase in Exploration & Production’s total assets is due to an increase in property, plant and equipment — net as a result of increased drilling activity.

(2)		The decrease in Gas Marketing Services’ total assets for 2008 and 2007 is due primarily to the fluctuations in derivative assets as a result of the impact of changes in commodity prices on existing forward derivative contracts. Gas Marketing Services’ derivative assets are substantially offset by their derivative liabilities.

Note 19. Subsequent Events (Unaudited)

Our Venezuela operations are primarily within our Midstream segment and have been operated under long-term agreements for the exclusive benefit of the Venezuelan state-owned oil company, PDVSA. These operations include majority ownership in entities that own and operate gas compression facilities, as well as our equity investment in Accroven, which owns gas processing facilities and an NGL fractionation plant. Construction of these assets was funded through project financing that is collateralized by the stock, assets, and contract rights of the entities and is otherwise nonrecourse to us.

Throughout 2009, PDVSA’s continued lack of payment of amounts due to us and lack of communications with us caused us to revise our assessment of the collectibility of past-due receivables for first-quarter 2009 reporting. The past due receivables from PDVSA had triggered technical default of the related project debt in the fourth quarter of 2008 (see Note 11), which resulted in classification of the entire debt balance as current. We subsequently determined it was probable that PDVSA would not cure the defaults and provided PDVSA with default notices for our majority-owned operations.

As a result of these circumstances and our assessment of the low likelihood of PDVSA curing the defaults, we fully reserved accounts receivable from PDVSA in our reported first-quarter 2009 results. In addition, we ceased revenue recognition of these operations for the first quarter of 2009 as we no longer believed that the collectibility of revenues was reasonably assured. This indicator of impairment caused us to review our Venezuelan property, plant and equipment and investments for recoverability and to record impairment charges. Certain deferred charges and credits were also written off. The impact of these net charges, after taxes and amounts attributable to noncontrolling interests, resulted in reporting a first-quarter 2009 net charge of $241 million attributable to The Williams Companies, Inc.

After these adjustments, our carrying value as of March 31, 2009, associated with these operations was primarily comprised of $67 million of restricted cash, $106 million of property, plant and equipment, and $161 million of secured debt.

In May 2009, the Venezuelan government seized the physical assets of our majority-owned entities. We have not reached any settlements with the Venezuelan government, but the seizure entitles us to receive payment for these assets under our contracts. The contracts also provide for international arbitration to resolve any disputes concerning such payment. Though we would expect to ultimately prevail in any arbitration claim, it would likely be a lengthy process and our ability to collect is uncertain.

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA
(Unaudited)

Summarized quarterly financial data are as follows (millions, except per-share amounts).


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter

2008
Revenues	$	3,204	$	3,701	$	3,245	$	2,202
Costs and operating expenses		2,353		2,719		2,364		1,720
Income from continuing operations		455		482		424		147
Net income		539		500		421		132
Amounts attributable to The Williams Companies, Inc.:
Income from continuing operations		416		419		369		130
Net income		500		437		366		115
Basic earnings per common share:
Income from continuing operations		.71		.72		.63		.23
Diluted earnings per common share:
Income from continuing operations		.70		.70		.62		.23

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		184		268		257		228
Net income		148		458		227		247
Amounts attributable to The Williams Companies, Inc.:
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 reduced revenues and reduced costs and operating expenses by 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 for fourth-quarter 2008 includes both the unfavorable impact of the significant decline in energy commodity prices and the following pre-tax items:

	•		$129 million impairment of certain natural gas producing properties at Exploration & Production (see Note 4 of Notes to Consolidated Financial Statements);

	•		$43 million of income including associated interest related to the partial settlement of the Gulf Liquids litigation at Midstream (see Notes 4 and 16);

	•		$38 million accrual for Wyoming severance taxes and associated interest expense at Exploration & Production (see Notes 4 and 16);

	•		$12 million gain related to the favorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Note 2).

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA — (Continued)
(Unaudited)

Net income for fourth-quarter 2008 also includes a $46 million adjustment to decrease state income taxes (net of federal benefit) due to a reduction in our estimate of the effective deferred state rate (see Note 5).

Net income for third-quarter 2008 includes the following pre-tax items:

	•		$14 million impairment of certain natural gas producing properties at Exploration & Production (see Note 4);

	•		$10 million gain from the sale of certain south Texas assets at Gas Pipeline (see Note 4).

Net income for second-quarter 2008 includes the following pre-tax items:

	•		$54 million gain related to the favorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Note 2);

	•		$30 million gain recognized upon receipt of the remaining proceeds related to the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production (see Note 4);

	•		$10 million charge associated with a settlement primarily related to the sale of natural gas liquids pipeline systems in 2002 (see summarized results of discontinued operations at Note 2);

	•		$10 million charge associated with an oil purchase contract related to our former Alaska refinery (see summarized results of discontinued operations at Note 2).

Net income for first quarter 2008 includes the following pre-tax items:

	•		$118 million gain on the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production (see Note 4);

	•		$74 million gain related to the favorable resolution of a matter involving pipeline transportation rates associated with our former Alaska operations (see summarized results of discontinued operations at Note 2);

	•		$54 million of income related to a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank (see summarized results of discontinued operations at Note 2).

Net income for fourth-quarter 2007 includes a $23 million adjustment to increase the tax provision relating to an income tax contingency and the following pre-tax items:

	•		$156 million mark-to-market loss recognized at Gas Marketing Services on a legacy derivative natural gas sales contract that we expect to assign to another party in 2008 under an asset transfer agreement that we executed in December 2007;

	•		$20 million accrual for litigation contingencies at Gas Marketing Services (see Note 4);

	•		$19 million in premiums, fees and expenses related to early debt retirement;

	•		$12 million of income related to a favorable litigation outcome at Midstream (see Note 4);

	•		$10 million charge related to an impairment of the Carbonate Trend pipeline at Midstream (see Note 4);

	•		$9 million charge related to the reserve for certain international receivables at Midstream;

	•		$6 million net loss, including transaction expenses, related to the sale of our discontinued power business (see summarized results of discontinued operations at Note 2).

100

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA — (Continued)
(Unaudited)

Net income for third-quarter 2007 includes the following pre-tax items:

	•		$17 million of expenses related to the sale of our discontinued power business (see summarized results of discontinued operations at Note 2);

	•		$12 million of income associated with the payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral (see Note 4).

Net income for second-quarter 2007 includes the following pre-tax items:

	•		$429 million gain associated with the reclassification of deferred net hedge gains to earnings related to the sale of our discontinued power business (see summarized results of discontinued operations at Note 2);

	•		$111 million impairment of the carrying value of certain derivative contracts related to the sale of our discontinued power business (see summarized results of discontinued operations at Note 2);

	•		$17 million of income associated with a change in estimate related to a regulatory liability at Northwest Pipeline (see Note 4);

	•		$15 million impairment of our Hazelton facility included in discontinued operations (see summarized results of discontinued operations at Note 2);

	•		$14 million of gains from the sales of cost-based investments (see Note 3);

	•		$14 million of expenses related to the sale of our discontinued power business (see summarized results of discontinued operations at Note 2);

	•		$6 million of income associated with the payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral (see Note 4).

Net income for the first-quarter 2007 includes the following pre-tax items:

•

$8 million of income due to the reversal of a planned major maintenance accrual at Midstream.

101

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES
(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 oil- and gas-producing activities, primarily in Argentina. However, proved reserves and revenues related to international activities are approximately 3.6 percent and 2.3 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,
	2008			2007
	(Millions)
Proved properties	$	8,099		$	6,409
Unproved properties		806			542

		8,905			6,951
Accumulated depreciation, depletion and amortization and valuation provisions		(2,353	)		(1,754	)

Net capitalized costs	$	6,552		$	5,197

	•		Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $726 million and $505 million, net, for 2008 and 2007, respectively. The capitalized cost amounts for 2008 and 2007 do not include approximately $1 billion of goodwill related to the purchase of Barrett Resources Corporation (Barrett) in 2001.

	•		Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves; development wells including uncompleted development well costs; and successful exploratory wells.

	•		Unproved properties consist primarily of acreage related to probable/possible reserves acquired through transactions in 2001 and 2008.

Costs Incurred


	For the Year Ended
	December 31,
	2008		2007		2006
	(Millions)
Acquisition	$	543	$	82	$	84
Exploration		38		38		20
Development		1,699		1,374		1,173

	$	2,280	$	1,494	$	1,277

	•		Costs incurred include capitalized and expensed items.

	•		Acquisition costs are as follows: The 2008 and 2007 costs are primarily for additional leasehold and reserve acquisitions in the Piceance and Fort Worth basins. Included in the 2008 acquisition amounts are $140 million of proved property values and $71 million related to an interest in a portion of acquired assets that a third party subsequently exercised its contractual option to purchase from us, on the same terms and conditions. The 2006 cost is primarily for additional leasehold and reserve acquisitions in the Fort Worth basin.

	•		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.

102

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)

Results of Operations


	For the Year Ended December 31,
	2008			2007			2006
	(Millions)
Revenues:
Oil and gas revenues	$	2,644		$	1,725		$	1,238
Other revenues		405			232			109

Total revenues		3,049			1,957			1,347

Costs:
Production costs		555			360			309
General & administrative		169			144			111
Exploration expenses		27			21			18
Depreciation, depletion & amortization		724			523			351
(Gains)/Losses on sales of interests in oil and gas properties		1			(1	)		—
Impairment of certain natural gas properties in the Arkoma basin		143			—			—
Other expenses		349			198			59

Total costs		1,968			1,245			848

Results of operations		1,081			712			499
Provision for income taxes		(406	)		(273	)		(174	)

Exploration and production net income	$	675		$	439		$	325

	•		Results of operations for producing activities consist of all related domestic activities within the Exploration & Production reporting unit and excludes the $148 million gain on sale of a contractual right to a production payment on certain future international hydrocarbon production.

	•		Prior period amounts have been adjusted to reflect the presentation of certain revenues and costs on a net basis. These adjustments reduced other revenues and reduced other expenses by the same amount, with no net impact on segment profit. The reductions were $72 million in 2007 and $77 million in 2006.

	•		Oil and gas revenues consist primarily of natural gas production sold to the Gas Marketing Services subsidiary and includes the impact of hedges, including intercompany hedges.

	•		Other revenues and other expenses consist of activities within the Exploration & Production segment that are not a direct part of the producing activities. These nonproducing activities include acquisition and disposition of other working interest gas and the movement of gas from the wellhead to the tailgate of the respective plants for sale to the Gas Marketing Services subsidiary or third-party purchasers. In addition, other revenues include recognition of income from transactions which transferred certain nonoperating benefits to a third party.

	•		Production costs consist of costs incurred to operate and maintain wells and related equipment and facilities used in the production of petroleum liquids and natural gas. These costs also include production taxes other than income taxes and administrative expenses in support of production activity. Excluded are depreciation, depletion and amortization of capitalized costs.

	•		Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes, and the cost of retaining undeveloped leaseholds including lease amortization and impairments.

	•		Depreciation, depletion and amortization includes depreciation of support equipment.

103

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)

Proved Reserves


	2008			2007			2006
	(Bcfe)
Proved reserves at beginning of period		4,143			3,701			3,382
Revisions		(220	)		(106	)		(113	)
Purchases		31			19			41
Extensions and discoveries		791			863			669
Wellhead production		(406	)		(334	)		(277	)
Sale of minerals in place		—			—			(1	)

Proved reserves at end of period		4,339			4,143			3,701

Proved developed reserves at end of period		2,456			2,252			1,945

	•		The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

	•		Approximately one-half of the revisions for 2008 relate to the impact of lower average year-end natural gas prices used in 2008 compared to the prior year.

	•		Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. Crude oil reserves are insignificant and have been included in the proved reserves on a basis of billion cubic feet equivalents (Bcfe).

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-end natural gas prices used in the following estimates were $4.41, $5.78, and $4.81 per MMcfe at December 31, 2008, 2007, and 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 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 $3,772 million of future development costs, approximately 72 percent is estimated to be spent in 2009, 2010 and 2011.

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.

104

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)
(Unaudited)

Standardized Measure of Discounted Future Net Cash Flows


	At December 31,
	2008		2007
	(Millions)
Future cash inflows	$	19,127	$	23,937
Less:
Future production costs		5,516		5,345
Future development costs		3,772		3,497
Future income tax provisions		3,284		5,416

Future net cash flows		6,555		9,679
Less 10 percent annual discount for estimated timing of cash flows		3,382		4,876

Standardized measure of discounted future net cash flows	$	3,173	$	4,803

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows


	2008			2007			2006
	(Millions)
Standardized measure of discounted future net cash flows beginning of period	$	4,803		$	2,856		$	5,281
Changes during the year:
Sales of oil and gas produced, net of operating costs		(2,091	)		(1,426	)		(1,179	)
Net change in prices and production costs		(2,548	)		2,019			(4,052	)
Extensions, discoveries and improved recovery, less estimated future costs		1,423			2,163			647
Development costs incurred during year		817			738			881
Changes in estimated future development costs		(724	)		(931	)		(1,022	)
Purchase of reserves in place, less estimated future costs		55			48			63
Sales of reserves in place, less estimated future costs		—			—			(2	)
Revisions of previous quantity estimates		(395	)		(266	)		(140	)
Accretion of discount		714			434			790
Net change in income taxes		1,108			(1,108	)		1,468
Other		11			276			121

Net changes		(1,630	)		1,947			(2,425	)

Standardized measure of discounted future net cash flows end of period	$	3,173		$	4,803		$	2,856

105