exv99w1

Exhibit 99.1

Item 6. Selected Financial Data

The following financial data at December 31, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, should be read in conjunction with 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.


	2009			2008		2007		2006			2005
	(Millions, except per-share amounts)
Revenues (1)	$	8,255		$	11,890	$	10,239	$	9,144		$	9,537
Income from continuing operations (2)		584			1,467		910		366			458
Income (loss) from discontinued operations (3)		(223	)		125		170		(17	)		(116	)
Cumulative effect of change in accounting principle (4)		—			—		—		—			(2	)
Amounts attributable to The Williams Companies, Inc.:
Income from continuing operations		438			1,306		829		332			446
Income (loss) from discontinued operations		(153	)		112		161		(23	)		(130	)
Cumulative effect of change in accounting principle		—			—		—		—			(2	)
Diluted earnings (loss) per common share:
Income from continuing operations		.75			2.21		1.37		.55			.75
Income (loss) from discontinued operations		(.26	)		.19		.26		(.04	)		(.22	)
Total assets at December 31		25,280			26,006		25,061		25,402			29,443
Short-term notes payable and long-term debt due within one year at December 31		17			18		108		358			88
Long-term debt at December 31		8,259			7,683		7,580		7,410			7,344
Stockholders’ equity at December 31		8,447			8,440		6,375		6,073			5,427
Cash dividends declared per common share		.44			.43		.39		.345			.25


(1)		Amounts for 2008 and 2007 have been adjusted to reflect the presentation of certain revenues and costs on a net basis. These adjustments reduced previously reported revenues and costs and operating expenses by the same amounts, with no impact to segment profit. The reductions were $295 million in 2008 and $99 million in 2007.

(2)		See Note 4 of Notes to Consolidated Financial Statements in Item 8 of this Exhibit 99.1 for discussion of asset sales, impairments, and other accruals in 2009, 2008, and 2007. Income from continuing operations for 2006 includes a $73 million charge for a litigation contingency. Income from continuing operations for 2005 includes an $82 million charge for litigation contingencies and a $110 million charge for impairments of certain equity investments.

(3)		See Note 2 of Notes to Consolidated Financial Statements for the analysis of the 2009, 2008, and 2007 income (loss) from discontinued operations. The discontinued operations results for 2006 includes our former power business, discontinued Venezuela operations, as well as amounts associated with our former chemical fertilizer business, a former exploration business, our former Alaska refinery, and our former distributive power business. The discontinued operations results for 2005 includes our former power business and discontinued Venezuela operations.

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

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Strategic Restructuring

On February 17, 2010, we completed a strategic restructuring, which involved contributing a substantial majority of our domestic midstream and gas pipeline businesses, including our limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), into Williams Partners L.P. (WPZ). As consideration for the asset contributions, we received proceeds from WPZ’s debt issuance of approximately $3.5 billion, less WPZ’s transaction fees and expenses, as well as 203 million WPZ Class C units, which are identical to common units, except for a prorated initial distribution. We also maintained our 2 percent general partner interest. WPZ assumed approximately $2 billion of existing debt associated with the gas pipeline assets. In connection with the restructuring, we retired $3 billion of our debt and paid $574 million in related premiums. These amounts, as well as other transaction costs, were primarily funded with the cash consideration received from WPZ. The premiums paid and certain other transaction costs will be recorded as expense in the first quarter of 2010. As a result of our restructuring, we are better positioned to drive additional growth and pursue value-adding growth strategies. Our new structure is designed to lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. (See Note 19 of Notes to Consolidated Financial Statements.)

In conjunction with the restructuring, WPZ intends to make an exchange offer for the publicly held units of WMZ at a future date.

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.

As a result of the strategic restructuring, we have changed our segment reporting structure to align with the new parent-level focus employed by our chief operating decision-maker, considering the resource allocation and governance associated with managing WPZ as a distinctly separate entity. Our reporting segments are now Williams Partners, Exploration & Production, and Other. Exploration & Production includes our former Gas Marketing Services segment, and Other includes certain midstream and gas pipeline businesses that were not contributed to WPZ, such as our Canadian midstream and domestic olefins businesses and a 25.5 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream), as well as corporate operations. (See Note 1 of Notes to Consolidated Financial Statements 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 2009

The overall economic recession, related lower energy commodity price environment, and challenging financial markets during the past year had a significant impact on our business. While we began to see improvement in the second half of the year, these conditions have resulted in sharply lower results of operations, cash flow from operations and capital expenditures in 2009 compared to 2008. Anticipating these circumstances, our plan for 2009 was built around the transition from significant growth to a focus on sustaining our current operations and reducing costs where appropriate. Although capital expenditures were reduced compared to the prior year, we continued to invest in our businesses with a focus on completing major projects, meeting legal, regulatory, and/or contractual commitments, and maintaining a reduced level of natural gas production development. Objectives and highlights of this plan included:


Objectives		Highlights
Continuing to invest in our gathering and processing and interstate natural gas pipeline systems.		We invested $513 million in capital expenditures in our midstream businesses, primarily Deepwater Gulf expansion projects and gas-processing capacity in the western United States. We also invested $485 million in capital expenditures in our gas pipelines during 2009.

Continuing to invest in our natural gas production development, although at a lower level than in recent years.		We invested $1.3 billion in drilling activity and the acquisition of additional producing properties in Exploration & Production.

Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions, as well as seizing attractive opportunities.		During 2009, capital and investment purchases were funded primarily through cash flow from operations while maintaining liquidity of at least $1 billion from cash and cash equivalents and unused revolving credit facilities. In addition, our Williams Partners and Exploration & Production segments seized growth opportunities to enter the Marcellus Shale, while Exploration & Production also expanded its footprint in the Piceance basin. (See further discussion in Other Significant 2009 Events.)

Our 2009 income from continuing operations attributable to The Williams Companies, Inc., decreased by $868 million compared to 2008. This decrease is primarily reflective of the overall unfavorable commodity price environment for the full year of 2009 as compared to 2008. Commodity prices declined sharply in the fourth quarter of 2008, but have improved in the latter half of 2009. See additional discussion in Results of Operations.

Our net cash provided by operating activities for 2009 decreased $783 million compared to 2008, primarily due to the decrease in our operating results. See additional discussion in Management’s Discussion and Analysis of Financial Condition and Liquidity.

Other Significant 2009 Events

In March 2009, we issued $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to certain institutional investors in a private debt placement. In August 2009, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

In April 2009, we announced our plan to build a 261-mile natural gas liquids pipeline in Canada at an estimated cost of $283 million. Construction is expected to begin in 2010 with completion expected in 2012.

In May 2009, certain of our Venezuela operations were expropriated by the Venezuelan government. As a result, these operations are now reflected as discontinued operations and have been deconsolidated. (See Note 2 of Notes to Consolidated Financial Statements.)

In June 2009, we finalized the formation of a new joint venture in the Marcellus Shale located in southwest Pennsylvania. (See Results of Operations — Segments, Williams Partners.)

In June 2009, we entered into an agreement to develop properties in the Marcellus Shale. (See Results of Operations — Segments, Exploration & Production.)

In September 2009, we completed the purchase of additional properties in the Piceance basin of Colorado for $253 million. (See Results of Operations — Segments, Exploration & Production.)

In September 2009, we received approval from the Federal Energy Regulatory Commission (FERC) to begin construction of the 85 North expansion project at an estimated cost of $241 million. (See Results of Operations — Segments, Williams Partners.)

Outlook for 2010

We believe we are well positioned to execute on our 2010 business plan and to capture attractive growth opportunities. The economic environment in the latter half of 2009 has improved compared to conditions earlier in the year. In addition, economic and commodity price indicators for 2010 and beyond reflect continued improvement in the economic environment. However, given the potential volatility of these measures, it is reasonably possible that the economy could worsen and/or commodity prices could decline, negatively impacting future operating results and increasing the risk of nonperformance of counterparties or impairments of goodwill and long-lived assets.

As a result of our 2010 restructuring, as previously discussed, we are better positioned to drive additional growth and pursue value-adding growth strategies. Our new structure is designed to lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions.

We continue to operate with a focus on EVA^® and invest in our businesses in a way that meets customer needs and enhances our competitive position by:

	•		Continuing to invest in and grow our gathering and processing and interstate natural gas pipeline systems;

	•		Continuing to invest in our natural gas drilling at a level generally consistent with the prior year and maintaining capacity to consider additional investment in attractive opportunities to diversify our reserves;

	•		Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions.

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

	•		Lower than anticipated commodity prices;

	•		Lower than expected levels of cash flow from operations;

	•		Availability of capital;

	•		Counterparty credit and performance risk;

	•		Decreased drilling success at Exploration & Production;

	•		Decreased volumes from third parties served by our midstream businesses;

	•		General economic, financial markets, or industry downturn;

	•		Changes in the political and regulatory environments;

	•		Physical damages to facilities, especially damage to offshore facilities by named windstorms for which our aggregate insurance policy limit is $37.5 million in the event of a material loss.

We continue to address these risks through utilization of commodity hedging strategies, disciplined investment strategies, and maintaining at least $1 billion in liquidity from cash and cash equivalents and unused revolving credit facilities. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.

Accounting Pronouncements Issued But Not Yet Adopted

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

See Accounting Standards Issued But Not Yet Adopted in Note 1 of Notes to Consolidated Financial Statements for further information on recently issued accounting standards.

Critical Accounting Estimates

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

Impairments of Long-Lived Assets and Goodwill

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

We assess our natural gas-producing properties and associated unproved leasehold costs for impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. Considering market-based pricing at December 31, 2009, we are not currently aware of any significant properties that are approaching impairment thresholds.

In addition to those long-lived assets for which impairment charges were recorded (see Note 4 of Notes to Consolidated Financial Statements), certain others were reviewed for which no impairment was required. These reviews included Exploration & Production’s properties and utilized inputs consistent with those described above. Certain assets within our Williams Partners segment were also evaluated for impairment utilizing judgments and assumptions including future fees, margins, and volumes. These underlying variables are subjective and susceptible to change. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

We have goodwill of approximately $1 billion at Exploration & Production related to its domestic exploration and production operations (the reporting unit) primarily resulting from a 2001 acquisition. We assess goodwill for impairment annually as of the end of the year. Because quoted market prices are not available for the reporting unit, management applies a range of reasonable judgments (including market supported assumptions when available) in estimating a range of fair values for the reporting unit.

We estimate the fair value of the reporting unit on a stand-alone basis and also consider our market capitalization in corroborating our estimate of the fair value of the reporting unit. As of December 31, 2009, the estimated fair value of the reporting unit exceeds its carrying value, including goodwill, indicating no impairment of Exploration & Production’s goodwill.

We estimated the fair value of the reporting unit on a stand-alone basis primarily by valuing proved and unproved reserves. We used an income approach (discounted cash flows) for valuing reserves. The significant inputs into the valuation of proved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, and appropriate discount rates. Unproved reserves were valued using similar assumptions adjusted further for the uncertainty associated with these reserves. We corroborated our fair value estimates with recent market transactions where possible.

In estimating the inputs, management must make assumptions that require judgments and are subject to change in response to changing market conditions and other future events. Significant assumptions in valuing proved reserves included reserves quantities of more than 4.7 Tcfe, forward natural gas prices, adjusted for locational differences, averaging approximately $5.97 per Mcfe, and an after-tax discount rate of 11 percent.

At December 31, 2009, we believe that an overall 20 percent or greater reduction to our estimates of future revenues, which are a component of our estimates of future cash flows, could result in an impairment of goodwill. Future revenue estimates are largely impacted by estimated prices and reserves. This sensitivity does not include any

related changes in operating taxes or production costs. We currently do not consider such a decrease in future revenues across all future periods to be likely.

We further reviewed the fair value of the reporting unit estimated on a stand-alone basis, by considering our market capitalization in a reconciliation of the fair values of all our businesses, including the reporting unit. In this reconciliation, we determined our market capitalization, including a control premium, and estimated the fair values of all our businesses considering certain financial performance metrics. The range of control premiums that we considered were consistent with historical market sales transactions and also considered the current market environment. Market capitalization was based on our traded stock price for a reasonably short period of time before and after December 31, 2009. In evaluating the items in our reconciliation analysis, management considered a range of reasonable judgments. This analysis allowed management to consider market expectations in corroborating the reasonableness of the estimated fair value of the reporting unit.

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

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

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

	•		A significant decline in forward natural gas prices or reserve quantities;

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

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

	•		Industry trends.

We cannot predict future market conditions and events that might adversely affect the estimated fair value of the reporting unit and possibly the reported value of goodwill. The estimated fair value of the reporting unit is significantly affected by natural gas prices, reserve quantities, and market expectations for required rates of return. There are numerous uncertainties inherent in estimating quantities of reserves that could affect our reserve quantities. Low prices for natural gas, regulatory limitations, or the lack of available capital for projects could adversely affect the development and production of additional reserves. Given the challenges affecting our businesses and the energy industry in 2010, these factors could impact us and require us to perform interim assessments of goodwill for possible impairment during 2010, which could result in a material impairment of our goodwill.

Accounting for Derivative Instruments and Hedging Activities

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

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

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

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

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

The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in offsetting the cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of

occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur, and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of 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, approximately 99 percent of our reserve estimates are either audited or prepared by independent experts. 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 properties and/or goodwill and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $72 million and $87 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserve categories.

Forward market prices, which are utilized in our impairment analyses, include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating our drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the forward price curve could result in an impairment of our oil and gas properties and/or goodwill.

Contingent Liabilities

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

Valuation of Deferred Tax Assets and Tax Contingencies

We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of the book basis and from tax carry-forwards generated in the current and prior years. We must evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. At December 31, 2009, we have $681 million of deferred tax assets for which a $4 million valuation allowance has been established. When assessing the need for a valuation allowance, we consider forecasts of future company performance, the estimated impact of potential asset dispositions, and our ability and intent to execute tax planning strategies to utilize tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.

We regularly face challenges from domestic and foreign tax authorities regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. We evaluate the liability associated with our various filing positions by applying the two step process of recognition and measurement. The ultimate disposition of these contingencies could have a significant impact on operating results and net cash flows. To the extent we were to prevail in matters for which accruals have been established or were required to pay amounts in excess of our accrued liability, our effective tax rate in a given financial statement period may be materially impacted.

See Note 5 of Notes to Consolidated Financial Statements for additional information.

Pension and Postretirement Obligations

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit expense and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute expense and the benefit obligations are shown in Note 7 of Notes to Consolidated Financial Statements.

The following table presents the estimated increase (decrease) in net periodic benefit expense and obligations resulting from a one-percentage-point change in the specified assumption.


	Benefit Expense						Benefit Obligation
	One-Percentage-			One-Percentage-			One-Percentage-			One-Percentage-
	Point Increase			Point Decrease			Point Increase			Point Decrease
				(Millions)
Pension benefits:
Discount rate	$	(9	)	$	10		$	(114	)	$	135
Expected long-term rate of return on plan assets		(9	)		9			—			—
Rate of compensation increase		3			(2	)		12			(10	)
Other postretirement benefits:
Discount rate		(2	)		3			(30	)		36
Expected long-term rate of return on plan assets		(1	)		1			—			—
Assumed health care cost trend rate		2			(2	)		33			(27	)

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rate of return on plan assets using our expectations of capital market results, which includes an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a long-term period of at least ten years and consider our investment strategy and mix of assets, which is weighted toward domestic and international equity securities. We develop our expectations using input from several external sources, including consultation with our third-party independent investment consultant. The forward-looking capital market projections are developed using a consensus of economists’ expectations for inflation, GDP growth, and dividend yield along with expected changes in risk premiums. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rate is an estimate of future results and, thus, likely to be different than actual results.

The capital markets improved in 2009 and the benefit plans’ assets reflect this improvement. While the 2009 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans has been 7.75 percent since 2006. The 2009 actual return on plan assets for our pension plans was a gain of approximately 21.8 percent. The ten-year average rate of return on pension plan assets through December 2009 was approximately 2.2 percent and is largely affected by the approximately 34.1 percent loss experienced in 2008.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related expense. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 7 of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term high-quality debt securities as well as by the duration of our plans’ liabilities.

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

The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and expense to increase.

Fair Value Measurements

Certain of our energy derivative assets and liabilities and other assets trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. At December 31, 2009, less than 1 percent of the total assets and total liabilities measured at fair value on a recurring basis are included in Level 3. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.

The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2009, the credit reserve is less than $1 million on our net derivative assets and $3 million on our net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.

At December 31, 2009, 82 percent of our derivatives portfolio expires in the next 12 months and more than 99 percent of our derivatives portfolio expires in the next 36 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.

At December 31, 2009, Level 2 includes option contracts that hedge future sales of production from our Exploration & Production segment; these options are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Prior to the third quarter of 2009, these options were included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. However, due to the increased transparency, we now consider this input to be observable and have included these options in Level 2.

The instruments included in Level 3 at December 31, 2009, consist of natural gas liquids swaps for our Williams Partners segment, as well as natural gas index transactions that are used to manage the physical requirements of our Exploration & Production segment. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices.

Exploration & Production has an unsecured credit agreement through December 2013 with certain banks that, so long as certain conditions are met, serves to reduce our usage of cash and other credit facilities for margin requirements related to instruments included in the facility.

For the year ended December 31, 2009, we have recognized impairments of certain assets that have been measured at fair value on a nonrecurring basis. These impairment measurements are included in Level 3 as they include significant unobservable inputs, such as our estimate of future cash flows and the probabilities of alternative scenarios. (See Note 14 of notes to Consolidated Financial Statements.)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Years Ended December 31,
				$ Change		% Change						$ Change		% Change
				from		from						from		from
	2009			2008*		2008*			2008			2007*		2007*			2007
									(Millions)
Revenues	$	8,255			-3,635		-31	%	$	11,890			+1,651		+16	%	$	10,239
Costs and expenses:
Costs and operating expenses		6,081			+2,695		+31	%		8,776			-944		-12	%		7,832
Selling, general and administrative expenses		512			-8		-2	%		504			-43		-9	%		461
Other (income) expense — net		17			-89	NM				(72	)		+70	NM				(2	)
General corporate expenses		164			-15		-10	%		149			+12		+7	%		161

Total costs and expenses		6,774								9,357								8,452

Operating income		1,481								2,533								1,787
Interest accrued — net		(585	)		-8		-1	%		(577	)		+55		+9	%		(632	)
Investing income		46			-143		-76	%		189			-63		-25	%		252
Early debt retirement costs		(1	)		—		—			(1	)		+18		+95	%		(19	)
Other income — net		2			+2	NM				—			-12		-100	%		12

Income from continuing operations before income taxes		943								2,144								1,400
Provision for income taxes		359			+318		+47	%		677			-187		-38	%		490

Income from continuing operations		584								1,467								910
Income (loss) from discontinued operations		(223	)		-348	NM				125			-45		-26	%		170

Net income		361								1,592								1,080
Less: Net income attributable to noncontrolling interests		76			+98		+56	%		174			-84		-93	%		90

Net income attributable to The Williams Companies, Inc.	$	285							$	1,418							$	990


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

2009 vs. 2008

Our consolidated results in 2009 declined significantly compared to 2008. These results reflect a rapid decline in energy commodity prices that began in the fourth quarter of 2008 as a result of the weakened economy. Energy commodity prices have generally improved during 2009, but not to levels experienced early in 2008.

The decrease in revenues is primarily due to decreased gas management and production revenues at Exploration & Production, reflecting a decrease in average natural gas prices, partially offset by an increase in production volumes sold. Natural gas liquid (NGL) production and marketing revenues at Williams Partners, as well as NGL and olefin production revenues at Other, also decreased reflecting lower average prices.

The decrease in costs and operating expenses is primarily due to decreased costs at Exploration & Production reflecting a decrease in average natural gas prices associated with gas management activities, as well as decreased marketing purchases and decreased costs associated with our NGL production businesses at Williams Partners. In addition, NGL and olefin production costs at Other decreased primarily due to lower average per-unit feedstock costs.

Other (income) expense — net within operating income in 2009 includes:

•

Gain of $40 million on the sale of our Cameron Meadows NGL processing plant at Williams Partners;

	•		Expense of $32 million related to penalties from the early termination of certain drilling rig contracts at Exploration & Production;

	•		Impairment charges totaling $20 million at Exploration & Production.

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

	•		Gain of $148 million on the sale of our Peru interests at Exploration & Production;

	•		Net gains of $39 million on foreign currency exchanges at Other;

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

	•		Gain of $10 million on the sale of certain south Texas assets at Williams Partners;

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

	•		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 Williams Partners.

General corporate expenses increased primarily due to an increase in employee-related expenses, partially offset by a decrease in outside services.

The decrease in operating income generally reflects an overall unfavorable energy commodity price environment in 2009 compared to 2008 and other changes as previously discussed.

The decrease in investing income is primarily due to a $75 million impairment of our Accroven investment at Other and an $11 million impairment of a cost-based investment at Exploration & Production. (See Note 3 of Notes to Consolidated Financial Statements.) A decrease in interest income, primarily due to lower average interest rates in 2009 compared to 2008, also contributed to the decrease in investing income.

Provision for income taxes decreased primarily due to lower pre-tax income. See Note 5 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.

See Note 2 of Notes to Consolidated Financial Statements for a discussion of the items in income (loss) from discontinued operations.

Net income attributable to noncontrolling interests decreased reflecting the first-quarter 2009 impairments and related charges associated with our discontinued Venezuela operations (see Note 2 of Notes to Consolidated Financial Statements) and the decline in Williams Partners L.P.’s operating results primarily driven by lower NGL margins.

2008 vs. 2007

Our consolidated results in 2008 improved significantly compared to 2007. However, these results were considerably influenced by favorable results in the first three quarters of the year, followed by a sharp decline in the fourth quarter due to a rapid decline in energy commodity prices.

The increase in revenues is primarily due to higher production and gas management revenues at Exploration & Production resulting from both higher average natural gas prices and increased production volumes sold, as well as 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. Other also experienced higher NGL and olefin production revenues primarily due to higher average prices and volumes. Williams Partners’ revenue increased primarily due to higher NGL production revenues resulting from higher average prices, partially offset by lower volumes.

The increase in costs and operating expenses is primarily due to increased costs at Exploration & Production reflecting an increase in average natural gas prices associated with gas management activities and higher depreciation, depletion and amortization and operating taxes. Costs also increased in our NGL and olefins production business at Other due to higher average per-unit feedstock and volumes while increased costs at our NGL production business in Williams Partners reflect higher natural gas costs.

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

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

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

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

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

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

	•		Expense of $20 million related to an accrual for litigation contingencies at Exploration & Production;

	•		Net losses of $11 million on foreign currency exchanges at Other;

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

The increase in operating income reflects improved operating results at Exploration & Production due to higher average natural gas prices, natural gas production growth, favorable price movements on derivative positions economically hedging the anticipated withdrawals of natural gas from storage, the absence of a loss recognized on a legacy derivative sales contract in 2007, and a gain of $148 million on the sale of our Peru interests. These increases in operating income are partially offset by increased operating costs and $143 million of property impairments in 2008 at Exploration & Production and a decrease in operating income at Williams Partners primarily due to a sharp decline in energy commodity prices in the latter part of 2008.

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

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

Early debt retirement costs in 2007 includes $19 million of premiums and fees related to the December 2007 repurchase of senior unsecured notes.

Provision for income taxes increased primarily due to higher pre-tax income partially offset by a reduction in our estimate of the effective deferred state tax rate in 2008. See Note 5 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rate compared to the federal statutory rate for both years.

See Note 2 of Notes to Consolidated Financial Statements for a discussion of the items in income (loss) from discontinued operations.

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

Results of Operations — Segments

We are organized into the following segments: Williams Partners, Exploration & Production, and Other. Our management evaluates performance based on segment profit (loss) from operations. (See Note 18 of Notes to Consolidated Financial Statements.)

Williams Partners

Our Williams Partners segment reflects the results of operations of our consolidated master limited partnership WPZ. WPZ includes two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies, which serve regions from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington and from the Gulf of Mexico to the northeastern United States. WPZ also includes natural gas gathering and processing and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain and Gulf Coast regions of the United States. Upon completing our strategic restructuring, we own approximately 84 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights.

Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures 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 and utilizing our low cost-of-capital to invest in growing markets.

Williams Partners’ interstate transmission and related 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.

Overview of 2009

Significant events during 2009 include the following:

Cameron Meadows Plant

In November 2009, we sold our Cameron Meadows plant and recognized a pre-tax gain of $40 million. This plant sustained hurricane damage twice in recent years and is, therefore, considered incongruent with our strategy of providing the most reliable service in the industry.

Laurel Mountain Midstream, LLC

In June 2009, we completed the formation of a new joint venture in the Marcellus Shale located in southwest Pennsylvania. Our partner in the venture contributed its existing Appalachian basin gathering system, which currently has an average throughput of approximately 100 MMcf/d. In exchange for a 51 percent interest in the venture, we contributed $100 million and issued a $26 million note payable. We account for this investment under the equity method due to the significant participatory rights of our partner such that we do not control the investment. We have transitioned operational control from our partner to us.

Volatile commodity prices

NGL prices, especially ethane prices, have generally improved during 2009, following significant declines in the fourth quarter of 2008 as a result of the weakened economy. Our NGL margins also benefited from a period of declining natural gas prices during 2009. While average annual per-unit NGL margins in 2009 were still significantly lower than 2008, they improved during 2009 to levels currently above the rolling five-year average per-unit margin. We continued to benefit from favorable natural gas price differentials in the Rocky Mountain area, although the differentials narrowed during 2009. These differentials contributed to realized per-unit margins that were generally greater than that of the industry benchmarks for natural gas processed in the Henry Hub area and for liquids fractionated and sold at Mont Belvieu, Texas.

NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants.

Hurricane impact to insurance coverage

While our insurance expense has increased modestly in 2009 compared to 2008, the overall level of coverage on our offshore assets in the Gulf Coast region against named windstorm events has substantially decreased, including the absence of coverage on certain of our assets. (See Note 9 of Notes to Consolidated Financial Statements.)

Williams Pipeline Partners L.P.

Upon completing the strategic restructuring, WPZ owns approximately 47.7 percent of WMZ, including the interests of the general partner, which is wholly owned by WPZ, and incentive distribution rights. WPZ consolidates WMZ due to its control through the general partner. In conjunction with our previously discussed restructuring, WPZ intends to make an exchange offer for the publicly held units of WMZ at a future date.

Completed expansion projects

Gulfstream Phase IV

Gulfstream, our equity investee of which WPZ owns a 24.5 percent interest following the completion of the strategic restructuring, received FERC approval to construct 17.8 miles of 20-inch pipeline and to install a new compressor facility in September 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 cost of this project is $190 million.

Willow Creek

The Willow Creek facility in western Colorado began processing natural gas production and extracting NGLs in early August and achieved full processing operations in September 2009. Currently, the 450 MMcf/d gas processing plant primarily processes Exploration & Production’s wellhead production, has a peak capacity of

30,000 barrels of NGLs per day, and is recovering approximately 20,000 barrels per day. In the current processing arrangement with Exploration & Production, we receive a volumetric-based processing fee and a percent of the NGLs extracted.

Sentinel

In August 2008, we received FERC approval to construct an expansion in the northeast United States. The cost of the project is estimated to be $229 million. We placed Phase I into service in December 2008 increasing capacity by 40 Mdt/d. Phase II provided an additional 102 Mdt/d and was placed into service in November 2009.

Colorado Hub Connection

In April 2009, we received approval from the FERC to construct a 27-mile pipeline to provide increased access to the Rockies natural gas supplies. Construction began in June 2009 and the project was placed into service in November 2009. We combined lateral capacity with existing mainline capacity to provide approximately 363 Mdt/d of firm transportation from various receipt points for delivery to Ignacio, Colorado. The estimated cost of the project is $60 million.

Outlook for 2010

The following factors could impact our business in 2010.

Commodity price changes

	•		NGL, crude and natural gas prices are highly volatile and difficult to predict. However, we expect per-unit NGL margins in 2010 to be higher than our average per-unit margins in 2009 and our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil. Margins in our NGL business are highly dependent upon continued demand within the global economy. Although forecasted domestic and global demand for polyethylene, or plastics, has been impacted by the weakness in the global economy, NGL products are currently the preferred feedstock for ethylene and propylene production, which are the building blocks of polyethylene. Propylene and ethylene production processes have increasingly shifted from the more expensive crude-based feedstocks to NGL-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets. As natural gas pipeline transportation capacity increases in the Rocky Mountain area, we anticipate that historically favorable natural gas price differentials will decline.

	•		As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of a small portion of our anticipated NGL sales for 2010. In addition, we have entered into financial contracts to fix the price of a portion of our shrink gas requirements for 2010.

Gathering, processing, and NGL sales volumes

	•		The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities. Our customers are generally large producers and we have not experienced and do not anticipate an overall significant decline in volumes due to reduced drilling activity.

	•		In the onshore midstream businesses, we expect higher fee revenues, NGL volumes, depreciation expense and operating expenses in 2010 compared to 2009 as our Willow Creek facility moves into a full year of operation, and our expansion at Echo Springs is completed late in 2010.

	•		We expect fee revenues, NGL volumes, depreciation expense, and operating expenses in our Gulf Coast midstream businesses to increase from 2009 levels as our new Perdido Norte expansion begins start-up operations in the first quarter of 2010. Increases from our Perdido Norte expansion are expected to be partially offset by lower volumes in other Gulf Coast areas due to expected changes in gas processing contracts, as described below, and natural declines.

•

Certain of our gas processing contracts contain provisions that allow customers to periodically elect processing services on either a fee basis, keep-whole, or percent-of-liquids basis. If customers switch from keep-whole to fee-based processing, this would reduce our NGL equity sales volumes.

Expansion projects

We expect to spend $950 million to $1.2 billion in 2010 on capital projects and additional investments in partially owned equity investments. The ongoing major expansion projects include:

Perdido Norte

The Perdido Norte project, in the western deepwater of the Gulf of Mexico, which includes an expansion of our Markham gas processing facility and oil and gas lines that will expand the scale of our existing infrastructure. Significant milestones have been reached and, considering the progress of our customer’s drilling and tie-in construction, we expect this project to begin start-up operations in the first quarter of 2010.

Mobile Bay South

A compression facility in Alabama allowing transportation service to various southbound delivery points. The cost of the project is estimated to be $37 million. The estimated project in-service date is May 2010 and will increase capacity by 253 Mdt/d.

85 North

An expansion of our existing natural gas transmission system from Alabama to various delivery points as far north as North Carolina. The cost of the project is estimated to be $241 million. Phase I service is anticipated to begin in July 2010 and will increase capacity by 90 Mdt/d. Phase II service is anticipated to begin in May 2011 and will increase capacity by 218 Mdt/d.

Sundance Trail

A 16-mile, 30-inch natural gas pipeline between our existing compressor stations in Wyoming. The project also includes an upgrade to our existing compressor station and is estimated to cost $65 million. The estimated in-service date is November 2010 and will increase capacity by 150 Mdt/d.

Echo Springs

Additional processing and NGL production capacities at our Echo Springs facility and related gathering system expansions in the Wamsutter area of Wyoming, which we expect to be in service at the end of 2010.

Mobile Bay South II

Additional compression facilities and modifications to existing facilities in Alabama allowing natural gas transportation service to various southbound delivery points. The cost of the project is estimated to be $36 million. The estimated project in-service date is May 2011 and will increase capacity by 380 Mdt/d.

Marcellus Shale

A 28-mile natural gas gathering pipeline in the Marcellus Shale region, which we will construct and operate in conjunction with a long-term agreement with a major producer. Construction on the 20-inch pipeline, which will deliver gas into the Transco pipeline, is expected to begin in the latter part of 2010, and it is expected to be placed into service during 2011.

Laurel Mountain

Additional capital within our Laurel Mountain joint venture to grow the existing gathering infrastructure in 2010 and beyond.

In addition to the various in-progress expansion projects previously discussed, we have several other proposed projects to meet customer demands. Subject to regulatory approvals, construction of some of these projects could begin as early as 2010.

Year-Over-Year Operating Results


	Years Ended December 31,
	2009		2008		2007
	(Millions)
Segment revenues	$	4,512	$	5,762	$	5,616

Segment profit	$	1,308	$	1,416	$	1,560

2009 vs. 2008

The decrease in segment revenues is largely due to:

	•		A $716 million decrease in revenues associated with the production of NGLs primarily due to lower average NGL prices.

	•		A $513 million decrease in marketing revenues primarily due to lower average NGL and crude prices, partially offset by higher NGL volumes.

	•		A $53 million decrease in revenues from lower transportation imbalance settlements in 2009 compared to 2008 (offset in costs and operating expenses).

These decreases are partially offset by a $60 million increase in fee revenues primarily due to higher volumes resulting from connecting new supplies in the deepwater Gulf of Mexico in the latter part of 2008 and new fees for processing Exploration & Production’s natural gas production at Willow Creek as well as by a $17 million increase in other service revenues and expansion projects placed into service by Transco.

Segment costs and expenses decreased $1,137 million primarily as a result of:

	•		A $643 million decrease in marketing purchases primarily due to lower average NGL and crude prices, including the absence of a $9 million charge in 2008 to write-down the value of NGL inventories, partially offset by higher NGL volumes.

	•		A $435 million decrease in costs associated with the production of NGLs primarily due to lower average natural gas prices.

	•		A $53 million decrease in costs associated with lower transportation imbalance settlements in 2009 compared to 2008 (offset in segment revenues).

	•		A $40 million gain on the 2009 sale of our Cameron Meadows processing plant.

	•		The absence of $17 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations.

	•		A $16 million decrease in gas pipeline project developments costs in 2009 compared to 2008.

	•		$11 million of income from an adjustment of state franchise taxes.

These decreases are partially offset by:

	•		A $13 million increase in depreciation expense in our gas pipeline businesses primarily due to projects placed into service.

	•		A $10 million increase in transportation related fuel expense in our gas pipeline businesses resulting from less favorable recovery from customers due to pricing differences.

	•		The absence of a $10 million gain on the sale of certain south Texas assets in 2008.

	•		The absence of a $9 million gain on the sale of excess inventory gas in 2008.

The decrease in segment profit reflects $281 million of lower NGL production margins primarily due to lower average NGL and natural gas prices, partially offset by $124 million of higher margins related to the marketing of NGLs and a $40 million gain in 2009 on the sale of the Cameron Meadows plant. The higher NGL marketing margins are largely due to favorable changes in pricing while product was in transit during 2009 as compared to significant unfavorable changes in pricing while product was in transit in 2008.

2008 vs. 2007

The increase in segment revenues is largely due to:

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

	•		A $52 million increase in transportation revenues resulting from Transco’s new rates, which were approved by the FERC as part of a general rate case and became effective March 2007, and expansion projects that Transco placed into service in the fourth quarter of 2007.

	•		A $48 million increase in fee-based revenues primarily due to the onshore midstream businesses, the deepwater Gulf Coast businesses and at our Conway fractionation and storage facilities.

	•		A $28 million increase in revenues from higher transportation imbalance settlements in 2008 compared to 2007 (offset in costs and operating expenses).

These increases are partially offset by an $85 million decrease in marketing revenues primarily due to lower volumes, partially offset by higher prices, and a $59 million decrease due to the absence of a 2007 sale of excess inventory gas (offset in costs and operating expenses).

Segment costs and expenses increased $287 million primarily as a result of:

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

	•		A $73 million increase in midstream operating costs including higher depreciation, repair costs and property insurance deductibles related to the hurricanes, gas transportation expenses in the eastern Gulf of Mexico, and employee costs.

	•		A $28 million increase in costs from higher transportation imbalance settlements in 2008 compared to 2007 (offset in segment revenues).

	•		A $21 million increase in gas pipeline project development costs in 2008 compared to 2007.

	•		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.

	•		The absence of $17 million of income recorded in 2007 for a change in estimate related to a regulatory liability at Northwest Pipeline.

	•		A $12 million increase in marketing purchases primarily due to a $9 million charge in 2008 to write-down the value of NGL inventories and higher average NGL and crude prices, partially offset by lower volumes.

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

These increases are partially offset by:

	•		A $59 million decrease in costs due to the absence of a 2007 sale of excess inventory gas (offset in segment revenues).

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

	•		A $10 million gain on the sale of certain south Texas assets in 2008.

	•		A $9 million gain on the sale of excess inventory gas in 2008.

The decrease in segment profit reflects $95 million of lower margins related to the marketing of NGLs due to the impact of a significant and rapid decline in NGL prices during the fourth quarter of 2008 on a higher volume of product inventory in transit and $28 million lower NGL production margins primarily due to higher natural gas prices and lower volumes sold, as well as other previously described changes in segment revenues and segment costs and expenses.

Exploration & Production

Exploration & Production includes natural gas development, production and gas management activities primarily in the Rocky Mountain and Mid-Continent regions of the United States, development activities in the Eastern portion of the United States and oil and natural gas interests in South America. The gas management activities include procuring fuel and shrink gas for our midstream businesses and providing marketing services to third parties, such as producers. Additionally, gas management activities include managing various natural gas related contracts such as transportation, storage, related hedges and proprietary trading positions not utilized for our own production.

Overview of 2009

Domestic production revenues and segment profit for 2009 were significantly lower than 2008 primarily due to a sharp decline in net realized average prices partially offset by higher production volumes. Additionally, 2009 results include expense of $32 million associated with contractual penalties from the early termination of drilling rig contracts and $20 million of impairment charges. Highlights of the comparative periods include:


	For the Years Ended December 31,
	2009		2008		% Change
Average daily domestic production (MMcfe) (1)		1,182		1,094		+8	%
Average daily total production (MMcfe) (1)		1,236		1,144		+8	%
Domestic production net realized average price ($/Mcfe) (2)	$	4.22	$	6.48		-35	%
Capital expenditures incurred ($ millions)	$	1,291	$	2,519		-49	%
Domestic production revenues ($ millions)	$	2,093	$	2,819		-26	%

Segment revenues ($ millions)	$	3,705	$	6,221		-40	%
Segment profit ($ millions)	$	400	$	1,262		-68	%


(1)		MMcfe is equal to one million cubic feet of gas equivalent.

(2)		Mcfe is equal to one thousand cubic feet of gas equivalent. Net realized average prices include market prices, net of fuel and shrink and hedge gains and losses, less gathering and transportation expenses. The realized hedge gain per Mcfe was $1.43 and $.09 for 2009 and 2008, respectively.

The increased production is primarily within the Piceance, Powder River, and Fort Worth basins. We reduced development activities and related capital expenditures in 2009, which resulted in production peaking during the first quarter of 2009, then decreasing slightly thereafter.

We drilled 875 gross domestic productive development wells in 2009 with a success rate of 99 percent. On January 14, 2009, the Securities and Exchange Commission (SEC) issued the Final Rule for Modernization of Oil and Gas Reporting which affects how oil and gas companies report their reserves. These changes included: (1) applying the expanded definition of oil and gas reserves used for reserves estimation supported by reliable technologies and reasonable certainty; (2) revising proved undeveloped reserve estimates based on new guidance; and (3) estimating proved reserves for disclosure in SEC filings using the 12-month average, first-of-the-month price instead of a single-day, period-end price. The FASB substantially conformed its requirements to the SEC rule with the issuance of its Accounting Standards Update 2010-03, Oil and Gas Reserve Estimation and Disclosures. Our estimated domestic proved reserves as of December 31, 2009 are 4,255 Bcfe.

Significant Events

In June 2009, we entered into an agreement that allows us to acquire, through a “drill-to-earn” structure, a 50 percent interest in approximately 44,000 net acres in Pennsylvania’s Marcellus Shale in the Appalachian basin. This agreement requires us to fund $33 million of drilling and completion costs on behalf of our partner and $41 million of our own costs and expenses prior to the end of 2011 to earn our 50 percent interest. This growth opportunity leverages our experience in developing nonconventional natural gas reserves. Through December 2009, we have funded $14 million of the $33 million.

In September 2009, we completed the purchase of additional unproved leasehold acreage and proved properties in the Piceance basin for $253 million. In December 2009, we increased our working interest in these properties through a $22 million acquisition.

Outlook for 2010

We expect natural gas prices to increase in 2010, resulting in higher segment revenues and segment profit. We plan to maintain capital expenditures at a level similar to 2009 with a consistent level of drilling rigs operating in 2010 compared to 2009. We have the following expectations and objectives for 2010:

	•		Continuation of our development drilling program in the Piceance, Fort Worth, Powder River, San Juan and Appalachian basins. Our capital expenditures for 2010 are projected to be between $1 billion and $1.4 billion. This includes our drilling program in the Marcellus Shale that will enable us to meet the terms of our agreement as previously discussed.

	•		Annual average daily domestic production level consistent with 2009, with fourth quarter 2010 volumes likely to be higher than the prior year comparable period.

	•		Stability in the costs of services and materials associated with development activities.

Risks to achieving our expectations and objectives include unfavorable natural gas market price movements which are impacted by numerous factors, including weather conditions, domestic natural gas production levels and demand, and a slower recovery in the global economy than expected. A significant decline in natural gas prices could impact these expectations for 2010, although the impact would be somewhat mitigated by our hedging program, which hedges a significant portion of our expected production.

In addition, changes in laws and regulations may impact our development drilling program. For example, the Colorado Oil & Gas Conservation Commission enacted new rules effective in April 2009 which increased our costs of permitting and environmental compliance and could potentially delay drilling permits. The new rules included additional environmental and operational requirements as part of permit approvals, tracking of certain chemicals brought on location, increased wildlife stipulations, new pit and waste management procedures and increased notifications and approvals from surface landowners. Our current outlook incorporates these changes; however, the extent and magnitude of other changes in laws and regulations could be greater than our current assumptions.

Commodity Price Risk Strategy

To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative contracts for a portion of our future production. For 2010, we have the following contracts for our daily domestic production, shown at weighted average volumes and basin-level weighted average prices:


	2010
			Price ($/Mcf)
	Volume		Floor-Ceiling
	(MMcf/d)		for Collars
Collars — Rockies		100	$	6.53 - $8.94
Collars — San Juan		233	$	5.75 - $7.82
Collars — Mid-Continent		105	$	5.37 - $7.41
Collars — Southern California		45	$	4.80 - $6.43
Collars — Other		28	$	5.63 - $6.87
NYMEX and basis fixed-price		120	$ 4.40

The following is a summary of our contracts for daily production for the years ended December 31, 2009, 2008 and 2007:


	2009				2008				2007
			Price ($/Mcf)				Price ($/Mcf)				Price ($/Mcf)
	Volume		Floor-Ceiling		Volume		Floor-Ceiling		Volume		Floor-Ceiling
	(MMcf/d)		for Collars		(MMcf/d)		for Collars		(MMcf/d)		for Collars
Collars — NYMEX		—		—		—		—		15	$	6.50 - $8.25
Collars — Rockies		150	$	6.11 - $9.04		170	$	6.16 - $9.14		50	$	5.65 - $7.45
Collars — San Juan		245	$	6.58 - $9.62		202	$	6.35 - $8.96		130	$	5.98 - $9.63
Collars — Mid-Continent		95	$	7.08 - $9.73		63	$	7.02 - $9.72		76	$	6.82 - $10.77
NYMEX and basis fixed-price		106	$ 3.67			70	$ 3.97			172	$ 3.90

Additionally, we utilize contracted pipeline capacity to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We hold a long-term obligation to deliver on a firm basis 200,000 MMbtu per day of gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance basin. Our interest in the Piceance basin holds sufficient reserves to meet this obligation.

Year-Over-Year Operating Results


	Years Ended December 31,
	2009		2008		2007
	(Millions)
Segment revenues:
Domestic production revenues	$	2,093	$	2,819	$	1,869
Gas management revenues		1,456		3,244		2,865
Net forward unrealized mark-to-market gains (losses) and ineffectiveness		18		29		(331	)
Other revenues		138		129		114

Total segment revenues	$	3,705	$	6,221	$	4,517

Segment profit	$	400	$	1,262	$	419

2009 vs. 2008

The decrease in total segment revenues is primarily due to the following:

•

$726 million, or 26 percent, decrease in domestic production revenues reflecting $946 million associated with a 31 percent decrease in realized average prices, partially offset by an increase of $220 million associated with a 8 percent increase in production volumes sold. Production revenues in 2009 and 2008 include approximately $93 million and $85 million, respectively, related to natural gas liquids (NGL) and approximately $38 million and $62 million, respectively, related to condensate. While NGL volumes were significantly higher than the prior year, NGL prices were significantly lower;

	•		$1,788 million, or 55 percent, decrease in gas management revenues primarily due to a decrease in physical natural gas revenue as a result of a 56 percent decrease in average prices on physical natural gas sales, slightly offset by a 2 percent increase in natural gas sales volumes. This is primarily related to gas sales associated with our transportation and storage contracts and is substantially offset by a similar decrease in segment costs and expenses;

	•		The decrease in net forward unrealized mark-to-market gains (losses) and ineffectiveness is primarily related to the absence of a $10 million favorable impact in 2008 for the initial consideration of our own nonperformance risk in estimating the fair value of our derivative liabilities.

Total segment costs and expenses decreased $1,656 million, primarily due to the following:

	•		$1,752 million decrease in gas management expenses, primarily due to a 55 percent decrease in average prices on physical natural gas purchases, slightly offset by a 2 percent increase in natural gas purchase volumes. This decrease is primarily related to the gas purchases associated with our previously discussed transportation and storage contracts and is substantially offset by a similar decrease in segment revenues. Gas management expenses in 2009 and 2008 include $7 million and $35 million, respectively, related to adjustments to the carrying value of natural gas inventories in storage;

	•		$163 million lower operating taxes due primarily to 56 percent lower average market prices (excluding the impact of hedges), partially offset by higher production volumes sold. The lower operating taxes include a net decrease of $39 million reflecting a $34 million charge in 2008 and $5 million of favorable revisions in 2009 relating to Wyoming severance and ad valorem tax issues;

	•		$143 million due to the absence of property impairments recorded in 2008 in the Arkoma basin;

	•		$8 million lower lease and other operating expenses due to lower industry costs and activity partially offset by the effect of an increase in production volumes;

	•		$7 million lower SG&A expenses, which includes lower bad debt expense related to the partial recovery of certain receivables previously reserved for in 2008 resulting from a bankrupt counterparty.

Partially offsetting the decreased costs are increases due to the following:

	•		The absence of a $148 million gain recorded in 2008 associated with the sale of our Peru interests;

	•		$152 million higher depreciation, depletion and amortization expense primarily due to the impact of higher capitalized drilling costs from prior years and higher production volumes compared to the prior year. Also, we recorded an additional $17 million of depreciation, depletion, and amortization in the fourth quarter of 2009 primarily due to new SEC reserves reporting rules. Our proved reserves decreased primarily due to the new SEC reserves reporting rules and the related price impact;

	•		$46 million higher gathering, processing and transportation expense primarily due to higher production volumes and the processing fees for natural gas liquids at Williams Partners’ Willow Creek plant, which began processing in August 2009;

	•		$32 million of expense related to penalties from the early release of drilling rigs as previously discussed;

	•		$31 million higher exploratory expense in 2009, primarily related to $20 million of increased seismic costs and $12 million related to higher amortization and the write-off of lease acquisition costs. Dry hole costs for 2009 and 2008 were $11 million and $12 million, respectively. As of December 31, 2009, we have approximately $14 million of capitalized drilling costs and $24 million of undeveloped leasehold costs related to continuing exploratory activities in the Paradox basin;

•

$20 million of impairment costs in the Fort Worth and Arkoma basins. We recorded a $15 million impairment in 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth basin. This impairment was based on our assessment of estimated future discounted cash flows and additional information obtained from drilling and other activities in 2009. We also recorded a $5 million impairment in the Arkoma basin in 2009 related to facilities.

The $862 million decrease in segment profit is primarily due to the 31 percent decrease in realized average domestic prices and the other previously discussed changes in segment revenues and segment costs and expenses.

2008 vs. 2007

The increase in total segment revenues is primarily due to the following:

	•		$950 million, or 51 percent, increase in domestic production revenues reflecting $572 million associated with a 25 percent increase in realized average prices and $378 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;

	•		$379 million, or 13 percent, increase in gas management revenues primarily due to an increase in physical natural gas revenue as a result of a 25 percent increase in average prices on physical natural gas sales, partially offset by a 10 percent decrease in natural gas sales volumes. This increase is offset by a similar increase in segment costs and expenses;

	•		The $360 million favorable change in net forward unrealized mark-to-market gains (losses) and ineffectiveness includes the effect of a $156 million loss realized in December 2007 related to a legacy derivative natural gas sales contract. We had previously accounted for this contract on an accrual basis under the normal purchases and normal sales exception. We discontinued normal purchase and normal sales treatment because it was no longer probable that the contract would not be 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 $856 million, primarily due to the following:

	•		$403 million increase in gas management expenses, primarily due to a 25 percent increase in average prices on physical natural gas purchases, partially offset by a 10 percent decrease in natural gas purchase volumes. This increase is substantially offset by a similar increase in segment revenues. Gas management expenses in 2008 also includes a $35 million adjustment to the carrying value of natural gas inventories in storage;

	•		$196 million higher depreciation, depletion and amortization expense, primarily due to higher production volumes and increased capitalized drilling costs;

	•		$143 million of property impairments in 2008 in the Arkoma basin;

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

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

	•		$47 million higher gathering, processing, and transportation expense primarily due to higher production volumes;

	•		$35 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 of expense in 2008 related to the write-off of certain exploratory drilling costs for our domestic and international operations.

Partially offsetting the increased costs and expenses are decreases due to the following:

	•		$148 million due to the gain associated with the sale of our Peru interests in 2008;

	•		The absence of a $20 million accrual for litigation contingencies in 2007.

The $843 million increase in segment profit is primarily due to the 25 percent increase in domestic realized average prices, the 20 percent increase in domestic production volumes sold, and the favorable change in net forward unrealized mark-to-market gains (losses) and ineffectiveness, partially offset by the increase in total segment costs and expenses.

Other

Our Other segment primarily includes our Canadian midstream and domestic olefins operations and a 25.5 percent interest in Gulfstream, as well as corporate operations.

Overview of 2009

Venezuela

In May 2009, the Venezuelan government expropriated the El Furrial and PIGAP II assets that we operated in Venezuela. As a result, these operations are now reflected as discontinued operations for all periods presented. Our investment in Accroven, whose assets have not been expropriated, is included in our Other segment and reflects a first-quarter 2009 impairment charge of $75 million. (See Notes 2 and 3 of Notes to Consolidated Financial Statements.)

Outlook for 2010

The following factors could impact our business in 2010.

Commodity price changes

	•		Margins in our Canadian midstream and domestic olefins business are highly dependent upon continued demand within the global economy. Forecasted domestic and global demand for polyethylene, or plastics, has been impacted by the weakness in the global economy. In addition, projected new third-party international ethylene production capacity may lower future demand for domestic ethylene. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has increasingly shifted away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production.

	•		In our olefin production business, we anticipate margins in 2010 to show an improvement over 2009, similarly benefiting from the dynamics discussed above.

Allocation of capital to expansion projects

We expect to spend $125 million to $175 million in 2010 on capital projects. The ongoing major expansion projects include construction in 2010 on a 12-inch diameter pipeline in Canada which will transport recovered natural gas liquids and olefins from our extraction plant in Ft. McMurray to our Redwater fractionation facility. The pipeline will have sufficient capacity to transport additional recovered liquids in excess of those from our current agreements. We anticipate an in-service date in 2012.

Year-Over-Year Operating Results


	Years Ended December 31,
	2009			2008		2007
	(Millions)
Segment revenues	$	780		$	1,257	$	1,113

Segment profit (loss)	$	(2	)	$	142	$	106

2009 vs. 2008

Segment revenues decreased primarily due to:

	•		A $457 million decrease in NGL and olefins production revenues resulting from lower average product prices, partially offset by higher volumes.

	•		A $19 million decrease in marketing revenues primarily due to lower average NGL and olefin prices, partially offset by higher NGL and olefin volumes.

Segment costs and expenses decreased $413 million primarily as a result of:

	•		A $445 million decrease in costs in our NGL and olefins production business primarily due to lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin inventories, partially offset by higher volumes.

	•		A $34 million decrease in marketing purchases primarily due to lower average NGL and olefin prices, including the absence of an $11 million charge in 2008 to write-down the value of our NGL inventories, partially offset by higher volumes.

These decreases were partially offset by:

	•		A $39 million unfavorable change primarily due to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•		The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation (see Note 16 of Notes to Consolidated Financial Statements).

The unfavorable change in segment profit (loss) was primarily due to:

	•		A $75 million loss from investment related to the 2009 impairment of our investment in Accroven.

	•		A $39 million unfavorable change primarily due to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•		The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation.

	•		A $12 million decrease in NGL and olefins production margins primarily due to lower average prices, partially offset by lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin production inventories, and higher volumes in 2009 related to the impact of third-party operational issues in 2008 that reduced off-gas supplies to our plant in Canada.

	•		The absence of an $8 million gain recognized in 2008 related to a final earn-out payment on a 2005 asset sale.

These decreases were partially offset by $15 million higher marketing margins in our NGL and olefins production business primarily due to the absence of an $11 million charge in 2008 to write-down the value of NGL inventories.

2008 vs. 2007

Segment revenues increased largely due to $210 million higher NGL and olefins production revenues resulting from higher average product prices and higher volumes sold associated with the increase of our ownership interest in the Geismar olefins facility effective July 2007. These increases were partially offset by $72 million lower marketing revenues primarily due to lower volumes, partially offset by higher prices.

Segment costs and expenses increased $117 million primarily as a result of:

	•		A $213 million increase in costs in our NGL and olefins production business due to higher feedstock prices and 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 $24 million increase in 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 were partially offset by:

	•		A $52 million favorable change in foreign currency exchange gains primarily due to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•		A $46 million decrease in marketing purchases primarily due to lower volumes, partially offset by higher average prices and an $11 million charge in 2008 to write-down the value of NGL inventories.

	•		$32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation.

The favorable change in segment profit (loss) was primarily due to:

	•		A $52 million favorable change in foreign currency exchange gains primarily due to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•		$32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation.

These increases were partially offset by:

	•		$26 million in lower margins related to the marketing of our olefins production products primarily due to the impact of a significant and rapid decline in olefin prices during 2008 on product inventory in transit. This also includes an $11 million charge in 2008 to write-down the value of NGL inventories.

	•		$24 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.

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2009, we continued to focus upon growth through disciplined investments in our natural gas businesses. Examples of this growth included:

	•		Continued investment in Exploration & Production’s development drilling programs, as well as the acquisition of additional producing properties and our initial entry into the Marcellus Shale area.

	•		Expansion of Williams Partners’ interstate natural gas pipeline system to meet the demand of growth markets.

	•		Continued investment in Williams Partners’ Deepwater Gulf expansion projects and gas processing capacity in the western United States and our initial entry into the Marcellus Shale area.

These investments were primarily funded through our cash flow from operations, which totaled nearly $2.6 billion for 2009.

During 2009, global credit markets experienced significant instability, markets witnessed significant reductions in value, and energy commodity prices experienced significant and rapid declines. In consideration of our liquidity under these conditions, we note the following:

	•		We reduced our levels of capital expenditures.

	•		As of December 31, 2009, we have approximately $1.9 billion of cash and cash equivalents and approximately $2.1 billion of available credit capacity under our credit facilities. Our $1.5 billion credit facility does not expire until May 2012. Additionally, Exploration & Production has an unsecured credit agreement that serves to reduce our margin requirements related to our hedging activities. (See additional discussion in the following Available Liquidity section.)

	•		We have no significant debt maturities until 2011.

	•		Our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support. (See Note 15 of Notes to Consolidated Financial Statements.)

Strategic Restructuring

On February 17, 2010, we completed a strategic restructuring, which involved contributing a substantial majority of our domestic midstream and gas pipeline businesses, including our limited and general partner interests in WMZ, into WPZ. Upon completing our strategic restructuring, we own approximately 84 percent of WPZ. We intend to hold our limited partner and general partner units for the long-term. As consideration for the asset contributions, we received proceeds from WPZ’s debt issuance of approximately $3.5 billion, less WPZ’s transaction fees and expenses, as well as 203 million WPZ Class C units, which are identical to common units, except for a prorated initial distribution. We also maintained our 2 percent general partner interest. WPZ assumed approximately $2 billion of existing debt associated with the gas pipeline assets. In connection with the restructuring, we retired $3 billion of our debt and paid $574 million in related premiums. These amounts, as well as other transaction costs, were primarily funded with the cash consideration we received from WPZ. As a result of our restructuring, we are better positioned to drive additional growth and pursue value-adding growth strategies. Our new structure is designed to lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. (See Note 19 of Notes to Consolidated Financial Statements.)

Outlook

For 2010, we expect operating results and cash flows to improve from 2009 levels due to the impact of expected higher energy commodity prices. Lower-than-expected energy commodity prices would be somewhat mitigated by certain of our cash flow streams that are substantially insulated from changes in commodity prices as follows:

	•		Firm demand and capacity reservation transportation revenues under long-term contracts from our gas pipelines;

	•		Hedged natural gas sales at Exploration & Production related to a significant portion of its production;

	•		Fee-based revenues from certain gathering and processing services in our midstream businesses.

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 consolidated liquidity of at least $1 billion from cash and cash equivalents and unused revolving credit facilities.

	•		We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, utilization of our revolving credit facilities, and proceeds from debt issuances and sales of equity securities as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.2 billion and $2.975 billion in 2010.

We expect capital and investment expenditures to total between $2.05 billion and $2.775 billion in 2010. Of this total, approximately 64 percent is considered nondiscretionary to meet legal, regulatory, and/or contractual requirements, to fund committed growth projects or to preserve the value of existing assets.

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

	•		Lower than expected levels of cash flow from operations;

	•		Sustained reductions in energy commodity prices from the range of current expectations.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2010. Our internal and external sources of consolidated liquidity include cash generated from our operations, cash and cash equivalents on hand, and our credit facilities. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. These sources are available to us at the parent level and are expected to be available to certain of our subsidiaries, particularly equity and debt issuances from WPZ. WPZ is expected to be self-funding through its cash flows from operations, use of its credit facility, and its access to capital markets. Cash held by WPZ is available to us only through distributions in accordance with its partnership agreement. Our ability to raise funds in the capital markets will be impacted by our financial condition, interest rates, market conditions, and industry conditions.


Available Liquidity	Credit Facilities	Year Ended
	Expiration	December 31, 2009
		(Millions)
Cash and cash equivalents (1)		$	1,867
Available capacity under our unsecured revolving and letter of credit facilities:
$700 million facilities (2)	October 2010		480
$1.5 billion facility (3)	May 2012		1,430
Available capacity under Williams Partners L.P.’s $200 million senior unsecured credit facility (3)	December 2012		188

		$	3,965


(1)		Cash and cash equivalents includes $31 million of funds received from third parties as collateral. The obligation for these amounts is reported as accrued liabilities on the Consolidated Balance Sheet. Also included is $648 million of cash and cash equivalents that is being utilized by certain subsidiary and international operations. The remainder of our cash and cash equivalents is primarily held in government-backed instruments.


(2)		These facilities were originated primarily in support of our former power business.

(3)		At December 31, 2009, we are in compliance with the financial covenants associated with these credit agreements. These credit facilities were impacted by our previously discussed restructuring transactions. WPZ, Northwest Pipeline, and Transco entered into a new $1.75 billion, three-year, senior unsecured revolving credit facility, which replaced WPZ’s unsecured $450 million credit facility (which was comprised of a $250 million term loan and a $200 million revolving credit facility). The full amount of the new credit facility is available to WPZ, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be increased by up to an additional $250 million. Transco and Northwest Pipeline are co-borrowers and are each able to borrow up to $400 million under this new facility to the extent not otherwise utilized by WPZ. WPZ utilized $250 million of the new facility to repay a term loan that was outstanding under its existing facility. As WPZ will be funding projects for its midstream and gas pipeline businesses, we reduced our approximately $1.5 billion unsecured credit facility that expires May 2012 to $900 million and removed Transco and Northwest Pipeline as borrowers. See the financial covenants of the new facility in Note 19 of Notes to Consolidated Financial Statements.

WMZ filed a shelf registration statement for the issuance of up to $1.5 billion aggregate principal amount of debt and limited partnership unit securities. The registration statement was declared effective on August 3, 2009.

WPZ filed a shelf registration statement as a well-known, seasoned issuer in October 2009 that allows it to issue an unlimited amount of registered debt and limited partnership unit securities.

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

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

Credit Ratings

Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. Following the closing of our 2010 restructuring, our investment-grade ratings were affirmed and the ratings for WPZ were upgraded to investment grade. The current ratings are as follows:


	WMB	WPZ
Standard and Poor’s (1)
Corporate Credit Rating	BBB-	BBB-
Senior Unsecured Debt Rating	BB+	BBB-
Outlook	Positive(4)	Positive(4)
Moody’s Investors Service (2)
Senior Unsecured Debt Rating	Baa3	Baa3(5)
Outlook	Stable	Stable(6)
Fitch Ratings (3)
Senior Unsecured Debt Rating	BBB-	BBB-(7)
Outlook	Stable	Stable


(1)		A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

(2)		A rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1,” “2,” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates the lower end of the category.


(3)		A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

(4)		On January 12, 2010, Standard & Poor’s revised to positive from stable.

(5)		On February 17, 2010, Moody’s Investor Service revised to Baa3 from Ba2.

(6)		On February 17, 2010, Moody’s Investor Service revised to stable from negative.

(7)		On February 2, 2010, Fitch Ratings revised to BBB- from BB.

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2009, we estimate that a downgrade to a rating below investment grade would require us to post up to $585 million in additional collateral with third parties.

Sources (Uses) of Cash


	Years Ended December 31,
	2009			2008			2007
				(Millions)
Net cash provided (used) by:
Operating activities	$	2,572		$	3,355		$	2,237
Financing activities		166			(432	)		(511	)
Investing activities		(2,310	)		(3,183	)		(2,296	)

Increase (decrease) in cash and cash equivalents	$	428		$	(260	)	$	(570	)

Operating activities

Our net cash provided by operating activities in 2009 decreased from 2008 primarily due to the decrease in our operating results.

Significant transactions in 2008 include:

	•		We received $140 million of cash related to a favorable resolution of matters involving pipeline transportation rates associated with our former Alaska operations. (See Note 2 of Notes to Consolidated Financial Statements.)

	•		Transco paid $144 million of required refunds related to a general rate case with the FERC.

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

Financing activities

Significant transactions include:

2009

	•		We received $595 million net cash from the issuance of $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to fund general corporate expenses and capital expenditures. (See Note 11 of Notes to Consolidated Financial Statements.)

	•		We paid $256 million of quarterly dividends on common stock for the year ended December 31, 2009.

2008

	•		We received $362 million from the completion of the WMZ initial public offering.

	•		We paid $474 million for the repurchase of our common stock. (See Note 12 of Notes to Consolidated Financial Statements.)

	•		Transco received $75 million net proceeds from debt transactions.

	•		We paid $250 million of quarterly dividends on common stock for the year ended December 31, 2008.

2007

	•		We paid $526 million for the repurchase of our common stock. (See Note 12 of Notes to Consolidated Financial Statements.)

	•		We repurchased $22 million of our 8.125 percent senior unsecured notes due March 2012 and $213 million of our 7.125 percent senior unsecured notes due September 2011. Early retirement premiums paid were approximately $19 million.

	•		Northwest Pipeline issued $185 million of 5.95 percent senior unsecured notes due 2017 and retired $175 million of 8.125 percent senior unsecured notes due 2010. Early retirement premiums paid were approximately $7 million.

	•		WPZ acquired certain of our membership interests in Wamsutter LLC, the limited liability company that owns the Wamsutter system, from us for $750 million. WPZ completed the transaction after successfully closing a public equity offering of 9.25 million common units that yielded net proceeds of approximately $335 million. The partnership financed the remainder of the purchase price primarily through utilizing $250 million term loan borrowings under their $450 million five-year senior unsecured credit facility and issuing approximately $157 million of common units to us.

	•		We paid $233 million of quarterly dividends on common stock for the year ended December 31, 2007.

Investing activities

2009

	•		Capital expenditures totaled $2.4 billion, more than half of which related to Exploration & Production. Included was a $253 million payment by Exploration & Production for the purchase of additional properties in the Piceance basin. (See Results of Operations—Segments, Exploration & Production.)

	•		We received $148 million as a distribution from Gulfstream following its debt offering.

	•		We contributed $142 million to our investments, including $106 million related to our Laurel Mountain equity investment and $20 million related to our Gulfstream equity investment.

2008

	•		Capital expenditures totaled $3.4 billion and was primarily related to Exploration & Production’s drilling activity. This total includes Exploration & Production’s acquisitions of certain interests in the Piceance and Fort Worth basins.

	•		We received $148 million of cash from Exploration & Production’s sale of a contractual right to a production payment.

	•		We contributed $111 million to our investments, including $90 million related to our Gulfstream equity investment.

2007

	•		Capital expenditures totaled $2.9 billion and was primarily related to Exploration & Production’s drilling activity, mostly in the Piceance basin.

	•		We received $496 million of gross proceeds from the sale of substantially all of our power business.

	•		We purchased $304 million and received $353 million from the sale of auction rate securities. These were utilized as a component of our overall cash management program.

Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other Commitments

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

Contractual Obligations

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


			2011-		2013-
	2010		2012		2014		Thereafter		Total
	(Millions)
Long-term debt, including current portion:
Principal (1)	$	15	$	2,139	$	—	$	6,155	$	8,309
Interest		619		1,113		938		4,273		6,943
Capital leases		2		—		1		—		3
Operating leases		70		64		45		138		317
Purchase obligations (2)		1,147		1,728		1,474		3,621		7,970
Other long-term liabilities, including current portion:
Physical and financial derivatives (3)(4 )		418		287		125		62		892
Other (5)(6)		—		—		—		—		—

Total	$	2,271	$	5,331	$	2,583	$	14,249	$	24,434


(1)		In February 2010, we completed our strategic restructuring and retired $3 billion of aggregate principal corporate debt and issued $3.5 billion aggregate principal amount of senior unsecured notes of WPZ. Additionally, WPZ established a new $1.75 billion three-year unsecured revolving credit facility which replaces its previous $450 million credit facility. WPZ utilized $250 million of the new facility to repay a term loan that was outstanding under the previous facility. Williams has reduced its existing $1.5 billion unsecured revolving credit facility, which matures in May 2012, to $900 million. The below table shows the impact by period of this transaction:


			2011-			2013-
	2010		2012			2014		Thereafter			Total
	(Millions)
Long-term debt, including current portion:
Retirement of $3 billion of aggregate principle corporate debt	$	—	$	(1,030	)	$	—	$	(1,970	)	$	(3,000	)
Issuance of the $3.5 billion WPZ senior notes		—		—			—		3,500			3,500
Retirement of the $250 million term loan under WPZ’s $450 million credit facility		—		(250	)		—		—			(250	)
Borrowing of $250 million under WPZ’s new $1.75 billion credit facility		—		—			250		—			250

Total	$	—	$	(1,280	)	$	250	$	1,530		$	500


(2)		Includes $3.2 billion of natural gas purchase obligations at market prices at our Exploration & Production segment. The purchased natural gas can be sold at market prices.


(3)		The obligations for physical and financial derivatives are based on market information as of December 31, 2009, and assumes contracts remain outstanding for their full contractual duration. Because market information changes daily and has the potential to be volatile, significant changes to the values in this category may occur.

(4)		Expected offsetting cash inflows of $3.9 billion at December 31, 2009, resulting from product sales or net positive settlements, are not reflected in these amounts. In addition, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.

(5)		Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $77 million in 2009 and $75 million in 2008. In 2010, we expect to contribute approximately $77 million to these plans (see Note 7 of Notes to Consolidated Financial Statements). During 2009, we contributed $60 million to our tax-qualified pension plans which was greater than the minimum funding requirements. We expect to contribute approximately $60 million to these pension plans again in 2010, which is expected to be greater than the minimum funding requirements. Estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations.

(6)		As of December 31, 2009, we have accrued approximately $72 million for unrecognized tax benefits. We cannot make reasonably reliable estimates of the timing of the future payments of these liabilities. Therefore, these liabilities have been excluded from the table above. See Note 5 of Notes to Consolidated Financial Statements for information regarding our contingent tax liability reserves.

Effects of Inflation

Our operations have benefited from relatively low inflation rates. Approximately 37 percent of our gross property, plant, and equipment is comprised of our interstate gas pipelines. These assets are 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 $42 million, all of which are recorded as liabilities on our balance sheet at December 31, 2009. We will seek recovery of approximately $12 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2009, we paid approximately $8 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $10 million in 2010 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2009, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

We are subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990, which require the EPA to issue new regulations. We are also subject to regulation at the state and local level. In September 1998, the EPA promulgated rules designed to mitigate the migration of ground-level ozone in certain states. Revisions to those rules were proposed in January 2010 and may result in additional controls. In March 2004 and June 2004, the EPA promulgated additional regulation regarding hazardous air pollutants, which may result in additional controls. Capital expenditures necessary to install emission control devices on our Transco gas pipeline system to comply with rules were approximately $400 thousand in 2009 and are estimated to be between $5 million and $10 million through 2013. The actual costs incurred will depend on the final implementation plans developed by each state to comply with these regulations. We consider these costs on our Transco system associated with compliance with these environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.

We have established systems and procedures to meet our reporting obligations under the Mandatory Reporting Rule related to greenhouse gas emissions issued by the EPA in late 2009. Also, certain states in which we have operations have established reporting obligations. We have not incurred significant capital investment to meet the obligations imposed by these new rules. The EPA is developing additional regulations that will expand the scope of the Mandatory Reporting Rule, with particular emphasis on natural gas operations. We are participating directly and through trade associations in developmental aspects of that prospective rulemaking. It is likely that additional rules will be issued in 2010 which may expand our reporting obligations as early as 2011. As those rules are still being developed, at this time we are unable to estimate any capital investment that may be required to comply.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. The majority of our debt portfolio is comprised of fixed rate debt in order to mitigate the impact of fluctuations in interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. In February 2010, we completed a strategic restructuring that involved retiring $3 billion of our debt and issuing $3.5 billion aggregate principal amount of senior unsecured notes of WPZ. (See Note 19 of Notes to Consolidated Financial Statements.)

The tables below provide information by maturity date about our interest rate risk-sensitive instruments included in continuing operations as of December 31, 2009 and 2008. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.


																					Fair Value
																					December 31,
	2010			2011			2012			2013			2014			Thereafter(1)			Total		2009
										(Millions)
Long-term debt, including current portion (2):
Fixed rate	$	15		$	936		$	953		$	—		$	—		$	6,119		$	8,023	$	8,905
Interest rate		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%		8.0	%
Variable rate	$	—		$	—		$	250		$	—		$	—		$	—		$	250	$	237
Interest rate (3)


																					Fair Value
																					December 31,
	2009			2010			2011			2012			2013			Thereafter(1)			Total		2008
	(Millions)
Long-term debt, including current portion (2):
Fixed rate	$	15		$	—		$	927		$	953		$	—		$	5,551		$	7,446	$	5,907
Interest rate		7.6	%		7.6	%		7.6	%		7.6	%		7.5	%		7.9	%
Variable rate	$	—		$	—		$	—		$	250		$	—		$	—		$	250	$	233
Interest rate (3)


(1)		Includes unamortized discount and premium.

(2)		Excludes capital leases.

(3)		The interest rate at December 31, 2009 and 2008 is LIBOR plus 1 percent and 0.75 percent, respectively.

Commodity Price Risk

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

Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-

risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.

Trading

Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives is a net liability of $11 million at December 31, 2009. Our value at risk for contracts held for trading purposes was less than $1 million at December 31, 2009 and 2008.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from the following activities:


Segment		Commodity Price Risk Exposure

Exploration & Production		• Natural gas purchases and sales

Williams Partners		• Natural gas purchases
		• NGL sales

The fair value of our nontrading derivatives is a net asset of $99 million at December 31, 2009.

The value at risk for derivative contracts held for nontrading purposes was $34 million at December 31, 2009, and $33 million at December 31, 2008. During the year ended December 31, 2009, our value at risk for these contracts ranged from a high of $37 million to a low of $27 million.

Certain of the derivative contracts held for nontrading purposes are accounted for as cash flow hedges. Of the total fair value of nontrading derivatives, cash flow hedges have a net asset value of $178 million as of December 31, 2009. Though these contracts are included in our value-at-risk calculation, any change in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

Trading Policy

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

Foreign Currency Risk

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

International investments accounted for under the cost method totaled $2 million at December 31, 2009, and $17 million at December 31, 2008. These investments are primarily in nonpublicly traded companies for which it is 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.

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, 2009 and 2008, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed at the accompanying Index 9.01(d), 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 9 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
February 25, 2010, 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 26, 2010

THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF INCOME


	Years Ended December 31,
	2009			2008			2007
	(Millions, except per-share amounts)
Revenues:
Williams Partners	$	4,512		$	5,762		$	5,616
Exploration & Production		3,705			6,221			4,517
Other		780			1,257			1,113
Intercompany eliminations		(742	)		(1,350	)		(1,007	)

Total revenues		8,255			11,890			10,239


Segment costs and expenses:
Costs and operating expenses		6,081			8,776			7,832
Selling, general and administrative expenses		512			504			461
Other (income) expense — net		17			(72	)		(2	)

Total segment costs and expenses		6,610			9,208			8,291


General corporate expenses		164			149			161


Operating income (loss):

Williams Partners		1,227			1,340			1,481
Exploration & Production		382			1,242			394
Other		36			100			73
General corporate expenses		(164	)		(149	)		(161	)

Total operating income		1,481			2,533			1,787


Interest accrued		(661	)		(636	)		(664	)
Interest capitalized		76			59			32
Investing income		46			189			252
Early debt retirement costs		(1	)		(1	)		(19	)
Other income — net		2			—			12


Income from continuing operations before income taxes		943			2,144			1,400
Provision for income taxes		359			677			490


Income from continuing operations		584			1,467			910
Income (loss) from discontinued operations		(223	)		125			170

Net income		361			1,592			1,080
Less: Net income attributable to noncontrolling interests		76			174			90

Net income attributable to The Williams Companies, Inc.	$	285		$	1,418		$	990


Amounts attributable to The Williams Companies, Inc.:
Income from continuing operations	$	438		$	1,306		$	829
Income (loss) from discontinued operations		(153	)		112			161

Net income	$	285		$	1,418		$	990


Basic earnings (loss) per common share:
Income from continuing operations	$	.75		$	2.25		$	1.39
Income (loss) from discontinued operations		(.26	)		.19			.27

Net income	$	.49		$	2.44		$	1.66

Weighted-average shares (thousands)		581,674			581,342			596,174


Diluted earnings (loss) per common share:
Income from continuing operations	$	.75		$	2.21		$	1.37
Income (loss) from discontinued operations		(.26	)		.19			.26

Net income	$	.49		$	2.40		$	1.63

Weighted-average shares (thousands)		589,385			592,719			609,866

See accompanying notes.

THE WILLIAMS COMPANIES, INC.
CONSOLIDATED BALANCE SHEET


	December 31,
	2009			2008
	(Millions, except
	per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,867		$	1,438
Accounts and notes receivable (net of allowance of $22 at December 31, 2009 and $29 at December 31, 2008)		829			884
Inventories		222			260
Derivative assets		650			1,464
Assets of discontinued operations		1			142
Other current assets and deferred charges		224			223

Total current assets		3,793			4,411
Investments		886			971
Property, plant, and equipment — net		18,644			17,741
Derivative assets		444			986
Goodwill		1,011			1,011
Assets of discontinued operations		—			387
Other assets and deferred charges		502			499

Total assets	$	25,280		$	26,006


LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	934		$	1,052
Accrued liabilities		948			1,139
Derivative liabilities		578			1,093
Liabilities of discontinued operations		—			217
Long-term debt due within one year		17			18

Total current liabilities		2,477			3,519
Long-term debt		8,259			7,683
Deferred income taxes		3,656			3,315
Derivative liabilities		428			875
Liabilities of discontinued operations		—			82
Other liabilities and deferred income		1,441			1,478
Contingent liabilities and commitments (Note 16)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 618 million shares issued at December 31, 2009, and 613 million shares issued at December 31, 2008)		618			613
Capital in excess of par value		8,135			8,074
Retained earnings		903			874
Accumulated other comprehensive loss		(168	)		(80	)
Treasury stock, at cost (35 million shares of common stock)		(1,041	)		(1,041	)

Total stockholders’ equity		8,447			8,440
Noncontrolling interests in consolidated subsidiaries		572			614

Total equity		9,019			9,054

Total liabilities and equity	$	25,280		$	26,006

See accompanying notes.

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


	The Williams Companies, Inc., Stockholders
								Accumulated
			Capital in		Retained			Other						Total
	Common		Excess of		Earnings			Comprehensive			Treasury			Stockholders’			Noncontrolling
	Stock		Par Value		(Deficit)			Loss			Stock			Equity			Interests			Total
	(Millions, except per-share amounts)
Balance, December 31, 2006	$	603	$	6,605	$	(1,034	)	$	(60	)	$	(41	)	$	6,073		$	1,081		$	7,154
Comprehensive income:
Net income		—		—		990			—			—			990			90			1,080
Other comprehensive loss:
Net change in cash flow hedges (Note 17)		—		—		—			(177	)		—			(177	)		(2	)		(179	)
Foreign currency translation adjustments		—		—		—			53			—			53			—			53
Pension benefits:
Net actuarial gain		—		—		—			53			—			53			—			53
Other postretirement benefits:
Prior service cost		—		—		—			1			—			1			—			1
Net actuarial gain		—		—		—			9			—			9			—			9

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

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

Balance, December 31, 2007		608		6,748		(293	)		(121	)		(567	)		6,375			1,430			7,805
Comprehensive income:
Net income		—		—		1,418			—			—			1,418			174			1,592
Other comprehensive income:
Net change in cash flow hedges (Note 17)		—		—		—			453			—			453			2			455
Foreign currency translation adjustments		—		—		—			(76	)		—			(76	)		—			(76	)
Pension benefits:
Prior service cost		—		—		—			1			—			1			—			1
Net actuarial loss		—		—		—			(337	)		—			(337	)		(7	)		(344	)
Other postretirement benefits:
Prior service cost		—		—		—			9			—			9			—			9
Net actuarial loss		—		—		—			(9	)		—			(9	)		—			(9	)

Total other comprehensive income															41			(5	)		36

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

Balance, December 31, 2008		613		8,074		874			(80	)		(1,041	)		8,440			614			9,054
Comprehensive income:
Net income		—		—		285			—			—			285			76			361
Other comprehensive loss:
Net change in cash flow hedges (Note 17)		—		—		—			(221	)		—			(221	)		—			(221	)
Foreign currency translation adjustments		—		—		—			83			—			83			—			83
Pension benefits:
Net actuarial gain		—		—		—			46			—			46			7			53
Other postretirement benefits:
Prior service cost		—		—		—			4			—			4			—			4

Total other comprehensive loss															(88	)		7			(81	)

Total comprehensive income															197			83			280
Cash dividends — Common stock ($.44 per share)		—		—		(256	)		—			—			(256	)		—			(256	)
Dividends and distributions to noncontrolling interests		—		—		—			—			—			—			(129	)		(129	)
Issuance of common stock from 5.5% debentures conversion (Note 12)		3		25		—			—			—			28			—			28
Stock-based compensation, including tax benefit		2		36		—			—			—			38			—			38
Other		—		—		—			—			—			—			4			4

Balance, December 31, 2009	$	618	$	8,135	$	903		$	(168	)	$	(1,041	)	$	8,447		$	572		$	9,019

See accompanying notes.

THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS


	Years Ended December 31,
	2009			2008			2007
				(Millions)
OPERATING ACTIVITIES:
Net income	$	361		$	1,592		$	1,080
Adjustments to reconcile to net cash provided by operating activities:
Reclassification of deferred net hedge gains related to sale of power business		—			—			(429	)
Depreciation, depletion and amortization		1,469			1,310			1,082
Provision for deferred income taxes		249			611			370
Provision for loss on investments, property and other assets		386			166			162
Net (gain) loss on dispositions of assets and business		(44	)		(36	)		16
Gain on sale of contractual production rights		—			(148	)		—
Early debt retirement costs		1			1			19
Provision for doubtful accounts and notes		48			15			12
Amortization of stock-based awards		43			31			70
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		67			329			(122	)
Inventories		33			(48	)		29
Margin deposits and customer margin deposits payable		4			88			(135	)
Other current assets and deferred charges		(8	)		(76	)		(10	)
Accounts payable		5			(343	)		26
Accrued liabilities		(170	)		7			(200	)
Changes in current and noncurrent derivative assets and liabilities		36			(121	)		370
Other, including changes in noncurrent assets and liabilities		92			(23	)		(103	)

Net cash provided by operating activities		2,572			3,355			2,237


FINANCING ACTIVITIES:
Proceeds from long-term debt		595			674			684
Payments of long-term debt		(33	)		(665	)		(806	)
Proceeds from issuance of common stock		6			32			56
Proceeds from sale of limited partner units of consolidated partnerships		—			362			333
Tax benefit of stock-based awards		1			21			32
Dividends paid		(256	)		(250	)		(233	)
Purchase of treasury stock		—			(474	)		(526	)
Premiums paid on early debt retirements and tender offer		—			—			(27	)
Dividends and distributions paid to noncontrolling interests		(129	)		(122	)		(75	)
Changes in cash overdrafts		(51	)		—			52
Other — net		33			(10	)		(1	)

Net cash provided (used) by financing activities		166			(432	)		(511	)


INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures*		(2,387	)		(3,394	)		(2,868	)
Net proceeds from dispositions		72			119			12
Purchases of investments/advances to affiliates		(142	)		(111	)		(60	)
Purchases of auction rate securities		—			—			(304	)
Purchases of ARO trust investments		(46	)		(31	)		—
Proceeds from sales of ARO trust investments		41			14			—
Proceeds from sale of business		—			22			471
Proceeds from dispositions of investments and other assets		3			41			92
Proceeds from sales of auction rate securities		—			—			353
Proceeds from sale of contractual production rights		—			148			—
Distribution from Gulfstream Natural Gas System, L.L.C.		148			—			—
Other — net		1			9			8

Net cash used by investing activities		(2,310	)		(3,183	)		(2,296	)

Increase (decrease) in cash and cash equivalents		428			(260	)		(570	)
Cash and cash equivalents at beginning of year		1,439			1,699			2,269

Cash and cash equivalents at end of year	$	1,867		$	1,439		$	1,699


* Increases to property, plant and equipment	$	(2,314	)	$	(3,475	)	$	(2,816	)
Changes in related accounts payable and accrued liabilities		(73	)		81			(52	)

Capital expenditures	$	(2,387	)	$	(3,394	)	$	(2,868	)

See accompanying notes.

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: Williams Partners, Exploration & Production, and Other.

Williams Partners consists of our consolidated master limited partnership, Williams Partners L.P. (WPZ) and the gas pipeline and midstream businesses that were contributed as part of our first quarter 2010 restructuring (see Note 19). The contributed gas pipeline businesses include 100 percent of Transcontinental Gas Pipe Line Company, LLC (Transco), 65 percent of Northwest Pipeline GP (Northwest Pipeline), and 24.5 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream). The remaining 35 percent of Northwest Pipeline is owned by Williams Pipeline Partners L.P. (WMZ), which is consolidated by WPZ (see Basis of Presentation below). WPZ’s midstream operations are composed of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in Pennsylvania’s Marcellus Shale region, and various equity investments in domestic processing and fractionation assets. WPZ’s midstream assets also include substantial operations and investments in the Four Corners and Gulf Coast regions, as well as a natural gas liquids (NGLs) fractionator and storage facilities near Conway, Kansas.

Exploration & Production includes natural gas development, production and gas management activities primarily in the Rocky Mountain and Mid-Continent regions of the United States, development activities in the Eastern portion of the United States and oil and gas interests in South America. The gas management activities include procuring fuel and shrink gas for our midstream businesses and providing marketing to third parties, such as producers. Additionally, gas management activities include managing various natural gas related contracts such as transportation, storage, related hedges and proprietary trading positions not utilized for our own production.

Other includes our Canadian midstream and domestic olefins operations, a 25.5 percent interest in Gulfstream, as well as corporate operations.

Basis of Presentation

In February 2010, we completed our strategic restructuring that resulted in a revision to our segment reporting structure. Our revised reporting segments have been described above. These consolidated financial statements and notes have been recast to reflect this revised segment reporting structure.

Prior period amounts have been adjusted for certain contracts involving the purchase and resale of NGLs and/or oil with the same counterparties that should have been reported on a net, rather than gross, basis. The error in presentation overstated both revenues and costs and operating expenses by equal amounts and had no impact on segment profit, operating income, net income, net cash provided by operating activities or any other key internal measures of operating performance. These adjustments reduced previously reported revenues and costs and operating expenses by $295 million in 2008 and $99 million in 2007.

Master limited partnerships

Upon completing our strategic restructuring in February 2010 (see Note 19), we own approximately 84 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. Prior to the restructuring, we owned approximately 23.6 percent of WPZ and consolidated it due to our control of the general partner.

WPZ is expected to be self-funding and maintains separate lines of bank credit and cash management accounts. Cash distributions from WPZ to us, including any associated with our incentive distribution rights, are expected to occur through the normal partnership distributions from WPZ to all partners.

Notes (continued)

Upon completing the restructuring, WPZ owns approximately 47.7 percent of the interests in WMZ, including the interests of the general partner, which is wholly owned by WPZ, and incentive distribution rights. WPZ consolidates WMZ due to its control through the general partner.

Discontinued operations

The accompanying consolidated financial statements and notes reflect the results of operations and financial position of certain of our Venezuela operations and our former power business as discontinued operations. (See Note 2). Our former power business included a 7,500-megawatt portfolio of power-related contracts that was sold in 2007 and our natural gas-fired electric generating plant located in Hazleton, Pennsylvania (Hazleton) that was sold in March 2008, in addition to other power-related assets.

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

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of our corporate parent and our majority-owned or controlled subsidiaries and investments. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20 to 50 percent of the voting interest, otherwise exercise significant influence over operating and financial policies of the company, or where majority ownership does not provide us with control due to significant participatory rights of other owners.

Use of estimates

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

Significant estimates and assumptions include:

•

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

•

Litigation-related contingencies;

•

Valuations of derivatives;

•

Hedge accounting correlations and probability;

•

Environmental remediation obligations;

•

Realization of deferred income tax assets;

•

Valuation of Exploration & Production’s reserves;

•

Asset retirement obligations;

•

Pension and postretirement valuation variables.

These estimates are discussed further throughout these notes.

Notes (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.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

Inventory valuation

All inventories are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method. We determine the cost of certain natural gas inventories held by Transco using the last-in, first-out (LIFO) cost method. LIFO inventory at December 31, 2009 and 2008, is $7 million and $11 million, respectively.

Property, plant, and equipment

Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values.

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

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

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

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

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

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

Notes (continued)

Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated at least annually for impairment by first comparing our management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. We also consider our market capitalization to corroborate our estimate of the fair value of the reporting unit. We have goodwill of approximately $1 billion at December 31, 2009 and 2008, attributable to the domestic exploration and production reporting unit of our Exploration & Production segment.

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

Judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements. Given the challenges affecting our businesses and the energy industry in 2010, we may be required to perform interim assessments of goodwill for possible impairment during 2010, which could result in a material impairment of our goodwill.

Treasury stock

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

Derivative instruments and hedging activities

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

We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheet in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:


Derivative Treatment		Accounting Method
Normal purchases and normal sales exception		Accrual accounting
Designated in a qualifying hedging relationship		Hedge accounting
All other derivatives		Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We have also designated a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the

Notes (continued)

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 or costs and operating expenses dependent upon the underlying hedge transaction.

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

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

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

•

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

•

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

•

Realized gains and losses on all derivatives that settle financially other than natural gas derivatives for NGL processing activities;

•

Realized gains and losses on derivatives held for trading purposes;

•

Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Williams Partners’ revenues

Revenues from our gas pipeline businesses 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.

Notes (continued)

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.

Revenues from our midstream operations include those derived from natural gas gathering and processing services and are performed under volumetric-based fee contracts, keep-whole agreements and percent-of-liquids arrangements. Revenues under volumetric-based fee contracts are recorded when services have been performed. Under keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.

Oil gathering and transportation revenues and offshore production handling fees of our midstream operations are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

We market NGLs that we purchase from our producer customers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.

Storage revenues under prepaid contracted storage capacity contracts are recognized evenly over the life of the contract as services are provided.

Exploration & Production revenues

Revenues for sales of natural gas are recognized when the product is sold and delivered. 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.

Other revenues

We have NGLs and 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.

Revenues from marketing NGLs and olefins are recognized when the product is sold and 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.

Notes (continued)

For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows. Estimating future cash flows involves the use of complex judgments such as estimation of the oil and gas reserve quantities, risk associated with the different categories of oil and gas reserves, timing of development and production, expected future commodity prices, capital expenditures, and production costs.

Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. A majority of the costs of acquired unproved reserves are associated with areas to which proved developed producing reserves are also attributed. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of potentially recoverable reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. Costs of acquired unproved reserves are assessed annually, or as conditions warrant, for impairment using estimated future discounted cash flows on a field basis and considering our future drilling plans. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.

We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment.

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

Capitalization of interest

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

Employee stock-based awards

Total stock-based compensation expense for the years ending December 31, 2009, 2008, and 2007 was $43 million, $31 million, and $70 million, respectively, of which $1 million and $9 million in 2008 and 2007, respectively, is included in income (loss) from discontinued operations. Measured but unrecognized stock-based compensation expense at December 31, 2009, was approximately $44 million, which does not include the effect of estimated forfeitures of $2 million. This amount is comprised of approximately $7 million related to stock options

Notes (continued)

and approximately $37 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.7 years.

Income taxes

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

Earnings (loss) per common share

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

Foreign currency translation

Certain of our foreign subsidiaries use their local currency as their functional currency. These foreign currencies include the Canadian dollar, British pound and Euro. Assets and liabilities of certain foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of operations are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of accumulated other comprehensive loss.

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

Issuance of equity of consolidated subsidiary

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

Accounting Standards Issued But Not Yet Adopted

In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This Update requires new disclosures regarding the amount of transfers in or out of Levels 1 and 2 along with the reason for such transfers and also requires a greater level of disaggregation when disclosing valuation techniques and inputs used in estimating Level 2 and Level 3 fair value measurements. This Update also includes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plan assets. The disclosures will be required for reporting beginning in the first quarter 2010. Also, beginning with the first quarter 2011, the Standard requires additional categorization of items included in the rollforward of activity for Level 3 inputs on a gross basis. We are assessing the application of this Standard to disclosures in our Consolidated Financial Statements.

Note 2. Discontinued Operations

Our Venezuela operations include majority ownership in entities that owned and operated the El Furrial and PIGAP II gas compression facilities prior to their expropriation by the Venezuelan government in May 2009. We previously operated these assets under long-term agreements for the exclusive benefit of the state-owned oil company, Petróleos de Venezuela S.A. (PDVSA). Construction of these assets was funded through project financing that is collateralized by the stock, assets, and contract rights of the entities that operated the Venezuela assets and is nonrecourse to us. We and the secured lenders are pursuing rights available to us under our agreements, including contractual and international arbitration. These operations met the accounting definition of a component of an entity.

Notes (continued)

As a result of the expropriation of the assets and the termination of the associated contracts, we consider these assets to be disposed and thus qualified for reporting as discontinued operations.

Considering the expropriation of the assets and the significant controlling rights of the secured lenders, we no longer control these entities and no longer meet the criteria to consolidate them. In conjunction with the deconsolidation of these entities in the second quarter of 2009, we recorded our retained investment in these entities at zero and recognized a pre-tax gain of $9 million. This carrying value was based on our estimates of probability-weighted discounted cash flows that considered: (1) alternate arbitration venues, (2) estimated levels of arbitration awards, (3) the subsequent likelihood and timing of collection, (4) the duration of the arbitration process, (5) a discount rate of 20 percent, and (6) the allocation of arbitration proceeds between parties, including the secured lenders. The use of alternate judgments and/or assumptions would have resulted in a different gain on deconsolidation. The carrying value of our retained investment in these entities was significantly impacted by our assumptions and is not representative of our underlying claims against PDVSA or the country of Venezuela.

The expropriations in the second quarter of 2009 followed an extended period of nonpayment by PDVSA and default notices that we provided in accordance with our agreements. The collection of receivables from PDVSA was historically slower and required more effort than with other customers due to PDVSA’s policies and the political environment in Venezuela. In our year-end 2008 analysis, we expected PDVSA to resume regular payments following a February 15, 2009, referendum vote in Venezuela; however, that did not happen. PDVSA’s continued nonperformance across the industry, their financial distress, and lack of communications with us caused us to revise our assessment in the first quarter of 2009.

As a result of this and our first-quarter assessment of the low likelihood of PDVSA curing the defaults, we fully reserved $48 million of accounts receivable from PDVSA in the first quarter of 2009. In addition, we ceased revenue recognition of these operations in the first quarter of 2009 as we no longer believed that the collectability of revenues was reasonably assured. This indicator of impairment required us to review our Venezuela property, plant, and equipment for recoverability, which resulted in recording a $211 million impairment charge at March 31, 2009. We estimated this impairment charge using probability-weighted discounted cash flow estimates that considered expected cash flows from: (1) the continued operation of the assets considering a complete cure of the default or a partial payment and renegotiation of the contracts, (2) the purchase of the assets by PDVSA, and (3) the results of arbitration with varying degrees of award and collection. Considering the risk associated with operating in Venezuela, we utilized an after-tax discount rate of 20 percent. The use of alternate judgments and/or assumptions would have resulted in the recognition of a different or no impairment charge. Certain deferred charges and credits, which netted to a $30 million charge, were also written off because the related future cash inflows and outflows were no longer expected to occur.

The past due payments from PDVSA triggered technical default of the related project debt under our financing agreements in the fourth quarter of 2008, which resulted in classification of the entire debt balance as current at December 31, 2008.

The summarized results of discontinued operations primarily reflect the results of the above described Venezuela operations in 2009 and 2008 and our former power business in 2007, except where noted otherwise. The summarized assets and liabilities of discontinued operations primarily reflect the above described Venezuela operations. In November 2007, we sold substantially all of our power business for approximately $496 million in cash. In 2008, we received an additional $22 million of proceeds, including the final purchase price adjustments and $8 million from the sale of Hazleton.

Notes (continued)

Summarized Results of Discontinued Operations


	Years Ended December 31,
	2009			2008			2007
				(Millions)
Revenues	$	—		$	172		$	2,584

Income (loss) from discontinued operations before (impairments) and gain (loss) on sales, gain on deconsolidation, and income taxes	$	(87	)	$	241		$	454
(Impairments) and gain (loss) on sales		(211	)		8			(162	)
Gain on deconsolidation		9			—			—
(Provision) benefit for income taxes		66			(124	)		(122	)

Income (loss) from discontinued operations	$	(223	)	$	125		$	170


Income (loss) from discontinued operations:
Attributable to noncontrolling interests	$	(70	)	$	13		$	9
Attributable to The Williams Companies, Inc.	$	(153	)	$	112		$	161

Income (loss) from discontinued operations before (impairments) and gain (loss) on sales, gain on deconsolidation, and income taxes for 2009 primarily includes losses related to our discontinued Venezuela operations, including the previously discussed $48 million of bad debt expense related to fully reserving accounts receivable from PDVSA and the $30 million net charge related to the write-off of certain deferred charges and credits. Offsetting these losses is a $15 million gain related to our former coal operations.

Income (loss) from discontinued operations before (impairments) and gain (loss) on sales, gain on deconsolidation, and income taxes for 2008 includes:

•

$140 million of gains related to the favorable resolution of matters involving pipeline transportation rates associated with our former Alaska operations;

•

$77 million of income related to our discontinued Venezuela operations;

•

$54 million of income related to a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank;

•

An $11 million charge associated with an oil purchase contract related to our former Alaska refinery;

•

A $10 million charge associated with a settlement primarily related to the sale of NGL pipeline systems in 2002.

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

(Impairments) and gain (loss) on sales for 2009 reflects the previously described $211 million impairment of our Venezuela property, plant, and equipment.

(Impairments) and gain (loss) on sales for 2008 includes the final proceeds from the sale of our former power business.

(Impairments) and gain (loss) on sales for 2007 includes a pre-tax loss of $37 million on the sale of substantially all of our power business. We also recognized impairments of $111 million related to the carrying value of certain derivative contracts for which we had previously elected the normal purchases and normal sales exception and,

Notes (continued)

accordingly, were no longer recording at fair value, and $14 million related to Hazleton. These impairments were based on our comparison of the carrying value to the estimate of fair value less cost to sell.

(Provision) benefit for income taxes for 2009 includes a $76 million benefit from the reversal of deferred tax balances related to our discontinued Venezuela operations.

Summarized Assets and Liabilities of Discontinued Operations


	December 31,
	2009		2008
	(Millions)
Cash and cash equivalents	$	—	$	1
Accounts receivable — net		1		62
Other current assets		—		79

Total current assets		1		142

Property, plant, and equipment — net		—		324
Other noncurrent assets		—		63

Total noncurrent assets		—		387

Total assets	$	1	$	529


Long-term debt due within one year	$	—	$	177
Other current liabilities		—		40

Total current liabilities		—		217

Total noncurrent liabilities		—		82

Total liabilities	$	—	$	299

Note 3. Investing Activities

Investing Income


	Years Ended December 31,
	2009			2008			2007
				(Millions)
Equity earnings*	$	136		$	137		$	137
Income (loss) from investments*		(75	)		1			—
Impairment of cost-based investments		(22	)		(4	)		(1	)
Interest income and other		7			55			116

Total investing income	$	46		$	189		$	252


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

Income (loss) from investments in 2009 reflects a $75 million impairment charge related to an other-than-temporary loss in value associated with our Venezuelan investment in Accroven SRL (Accroven). Accroven owns and operates gas processing facilities and a NGL fractionation plant for the exclusive benefit of PDVSA. The deteriorating circumstances in the first quarter of 2009 for our Venezuelan operations (see Note 2) caused us to review our investment in Accroven. We utilized a probability-weighted discounted cash flow analysis, which included an after-tax discount rate of 20 percent to reflect the risk associated with operating in Venezuela. (See Note 14.) Accroven was not part of the operations that were expropriated by the Venezuelan government in May 2009. We have been engaged in discussions regarding the eventual disposition of Accroven.

Impairment of cost-based investments in 2009 includes an $11 million impairment related to our 4 percent interest in a Venezuelan corporation that owns and operates oil and gas activities. This investment resulted from our previous 10 percent direct working interest in a concession that was converted to a reduced interest in a mixed company at the direction of the Venezuelan government in 2006. Considering our evaluation of the deteriorating financial condition of this corporation, we recorded an other-than-temporary decline in value of our remaining investment balance.

Notes (continued)

The unfavorable change in interest income and other in 2009 and 2008 is primarily due to lower average interest rates.

Investments


	December 31,
	2009		2008
	(Millions)
Equity method:
Gulfstream — 50%	$	383	$	525
Discovery Producer Services LLC — 60%*		189		184
Laurel Mountain Midstream, LLC — 51%*		133		—
Petrolera Entre Lomas S.A. — 40.8%		81		73
Accroven — 49.3%		—		69
Other		98		96

		884		947
Cost method		2		24

	$	886	$	971


*		We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control the investments.

Differences between the carrying value of our equity investments and the underlying equity in the net assets of the investees are primarily related to impairments we previously recognized.

In 2009, we invested $132 million in Laurel Mountain Midstream, LLC. In addition, we contributed $20 million in 2009 and $90 million in 2008 to Gulfstream.

Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $291 million in 2009 and $167 million in 2008. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:


	2009		2008
	(Millions)
Gulfstream	$	223	$	58
Discovery Producer Services LLC		32		56
Aux Sable Liquid Products LP.		15		28

In 2009, we received a $148 million distribution from Gulfstream following its debt offering.

Summarized Financial Position and Results of Operations of Equity Method Investments


	December 31,
	2009		2008
	(Millions)
Current assets	$	383	$	342
Noncurrent assets		3,723		3,505
Current liabilities		266		253
Noncurrent liabilities		1,511		1,278


	Years Ended December 31,
	2009		2008		2007
			(Millions)
Gross revenue	$	1,115	$	1,246	$	1,163
Operating income		516		521		515
Net income		396		405		385

Notes (continued)

Note 4. Asset Sales, Impairments and Other Accruals

The following table presents significant gains or losses reflected in other (income) expense — net within segment costs and expenses.


	Years Ended December 31,
	2009			2008			2007
				(Millions)
Williams Partners
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	)		—
Income from favorable litigation outcome		—			—			(12	)
Impairment of Carbonate Trend pipeline		—			6			10
Involuntary conversion gains related to Ignacio plant		(4	)		(12	)		—
Gain on sale of Cameron Meadows plant		(40	)		—			—
Exploration & Production
Gain on sale of contractual right to an international production payment		—			(148	)		—
Impairment of certain properties		20			143			—
Penalties from early release of drilling rigs		32			—			—
Accrual for litigation contingencies		—			—			20
Other
Gulf Liquids litigation contingency accrual reversal (see Note 16)		—			(32	)		—

Other (income) expense — net within segment costs and expenses also includes net foreign currency exchange gains of $38 million in 2008 and net foreign currency exchange losses of $12 million in 2007. The net gain in 2008 primarily relates to the remeasurement of current assets held in U.S. dollars within our Canadian operations in the Other segment.

Impairment of certain Exploration & Production properties

Based on a comparison of the estimated fair value to the carrying value, Exploration & Production recorded a $15 million impairment in December 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth basin. Additionally, Exploration & Production recorded impairment charges of $5 million and $143 million in 2009 and 2008, respectively, related to properties in the Arkoma basin. Our impairment analysis included an assessment of undiscounted (except for the unproved reserves) and discounted future cash flows, which considered information obtained from drilling, other activities, and year-end natural gas reserve quantities.

Additional Items

In 2009, Exploration & Production recognized $11 million of income related to the recovery of certain royalty overpayments from prior periods, which is reflected within revenues.

In 2008, Exploration & Production recorded a $34 million accrual for Wyoming severance taxes, which is reflected in costs and operating expenses within segment costs and expenses. Associated with this charge is an interest expense accrual of $4 million, which is included in interest accrued. (See Note 16.)

Notes (continued)

Note 5. Provision for Income Taxes

The provision for income taxes from continuing operations includes:


	2009		2008			2007
			(Millions)
Current:
Federal	$	10	$	179		$	29
State		12		24			9
Foreign		21		8			21

		43		211			59
Deferred:
Federal		271		466			422
State		42		(11	)		(4	)
Foreign		3		11			13

		316		466			431

Total provision	$	359	$	677		$	490

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


	2009			2008			2007
				(Millions)
Provision at statutory rate	$	330		$	750		$	490
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)		35			8			4
Foreign operations — net		25			(16	)		1
Impact of nontaxable noncontrolling interests		(49	)		(54	)		(25	)
Other — net		18			(11	)		20

Provision for income taxes	$	359		$	677		$	490

State income taxes (net of federal benefit) were reduced by $46 million in 2008 due to a reduction in our estimate of the effective deferred state rate reflective of a change in the mix of jurisdictional attribution of taxable income.

Income from continuing operations before income taxes includes $36 million of foreign loss, and $139 million and $127 million of foreign income in 2009, 2008, and 2007, respectively.

During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within other — net in our reconciliation of the tax provision to the federal statutory rate.

Notes (continued)

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2009 and 2008, are as follows:


	2009		2008
	(Millions)
Deferred tax liabilities:
Property, plant, and equipment	$	3,658	$	3,288
Derivatives — net		66		263
Investments		491		380
Other		108		112

Total deferred tax liabilities		4,323		4,043


Deferred tax assets:
Accrued liabilities		557		581
Foreign carryovers		4		3
Minimum tax credits		62		—
Other		58		55

Total deferred tax assets		681		639

Less valuation allowance		4		3

Net deferred tax assets		677		636

Overall net deferred tax liabilities	$	3,646	$	3,407

The valuation allowance at December 31, 2009 and 2008 serves to reduce the recognized tax benefit associated with foreign carryovers to an amount that will, more likely than not, be realized. We do not expect to be able to utilize our $4 million of foreign deferred tax assets.

Undistributed earnings of certain consolidated foreign subsidiaries, inclusive of discontinued operations, at December 31, 2009, totaled approximately $165 million. No provision for deferred U.S. income taxes has been made for these subsidiaries because we intend to permanently reinvest such earnings in foreign operations.

Cash payments for income taxes (net of refunds and including discontinued operations) were $14 million, $155 million, and $384 million in 2009, 2008, and 2007, respectively. Cash tax payments include settlements with taxing authorities associated with prior period audits of $9 million, $47 million, and $94 million in 2009, 2008, and 2007, respectively.

As of December 31, 2009, we had approximately $72 million of unrecognized tax benefits. If recognized, approximately $61 million, net of federal tax expense, would be recorded as a reduction of income tax expense. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	2009			2008
	(Millions)
Balance at beginning of period	$	79		$	76
Additions based on tax positions related to the current year		—			3
Additions for tax positions for prior years		4			8
Reductions for tax positions of prior years		(7	)		(8	)
Settlement with taxing authorities		(4	)		—

Balance at end of period	$	72		$	79

We recognize related interest and penalties as a component of income tax expense. Total interest and penalties recognized as part of income tax expense were $17 million, $2 million, and $60 million for 2009, 2008, and 2007, respectively. Approximately $93 million and $81 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2009 and 2008, respectively.

As of December 31, 2009, the Internal Revenue Service (IRS) examination of our consolidated U.S. income tax return for 2008 is in process. IRS examinations for 1997 through 2007 have been completed at the field level but the years remain open for certain unagreed issues. The statute of limitations for most states expires one year after expiration of the IRS statute.

Notes (continued)

Generally, tax returns for our Venezuelan, Argentine, and Canadian entities are open to audit from 2002 through 2009. Certain Canadian entities are currently under examination.

During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with a domestic or international matter will result in a significant increase or decrease of our unrecognized tax benefit. However, certain matters we have contested to the Internal Revenue Service Appeals Division could be resolved and result in a reduction to our unrecognized tax benefit.

Note 6. Earnings Per Common Share from Continuing Operations


	Years Ended December 31,
	2009		2008		2007
	(Dollars in millions, except per-share
	amounts; shares in thousands)
Income from continuing operations attributable to The Williams Companies, Inc., available to common stockholders for basic and diluted earnings per common share (1)	$	438	$	1,306	$	829

Basic weighted-average shares (2)(3)		581,674		581,342		596,174
Effect of dilutive securities:
Nonvested restricted stock units		2,216		1,334		1,627
Stock options		2,065		3,439		4,743
Convertible debentures (3)		3,430		6,604		7,322

Diluted weighted-average shares		589,385		592,719		609,866

Earnings per common share from continuing operations:
Basic	$	.75	$	2.25	$	1.39

Diluted	$	.75	$	2.21	$	1.37


(1)		The years of 2009, 2008, and 2007 include $1 million, $2 million and $3 million, respectively, of interest expense, net of tax, associated with our 5.5 percent convertible debentures. (See Note 12.) These amounts have been added back to income from continuing operations attributable to The Williams Companies, Inc., available to common stockholders to calculate diluted earnings per common share.

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

(3)		During 2009 and 2008, we issued 3 million shares and 2 million shares, respectively, of our common stock in exchange for a portion of our 5.5 percent convertible debentures. (See Note 12.)

The table below includes information related to stock options that were outstanding at the end of each respective year but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares.


	2009		2008		2007
Options excluded (millions)		3.7		6.4		.8
Weighted-average exercise prices of options excluded	$	30.21	$	26.41	$	40.07
Exercise price ranges of options excluded	$	20.28 - $42.29	$	16.40 - $42.29	$	36.66 - $42.29
Fourth quarter weighted-average market price	$	19.81	$	16.37	$	35.14

Note 7. Employee Benefit Plans

We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump sum payment, or a combination of lump sum and annuity payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not

Notes (continued)

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.

Benefit Obligations

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated. The annual measurement date for our plans is December 31.


							Other
							Postretirement
	Pension Benefits						Benefits
	2009			2008			2009			2008
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,035		$	896		$	273		$	284
Service cost		32			23			2			2
Interest cost		62			60			16			18
Plan participants’ contributions		—			—			5			5
Benefits paid		(59	)		(70	)		(24	)		(23	)
Medicare Part D subsidy		—			—			2			2
Plan amendment		—			—			(18	)		(38	)
Actuarial loss		48			126			3			23

Benefit obligation at end of year		1,118			1,035			259			273

Change in plan assets:
Fair value of plan assets at beginning of year		705			1,074			126			192
Actual return on plan assets		153			(360	)		25			(62	)
Employer contributions		61			61			16			14
Plan participants’ contributions		—			—			5			5
Benefits paid		(59	)		(70	)		(24	)		(23	)

Fair value of plan assets at end of year		860			705			148			126

Funded status — underfunded	$	(258	)	$	(330	)	$	(111	)	$	(147	)

Accumulated benefit obligation	$	1,075		$	959

The underfunded status of our pension plans and other postretirement benefit plans presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:


	December 31,
	2009		2008
	(Millions)
Underfunded pension plans:
Current liabilities	$	1	$	1
Noncurrent liabilities		257		329
Underfunded other postretirement benefit plans:
Current liabilities		8		8
Noncurrent liabilities		103		139

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

The 2009 benefit obligation actuarial loss of $48 million for our pension plans is primarily due to the impact of decreases in the discount rate utilized to calculate the benefit obligation. The 2008 benefit obligation actuarial losses of $126 million for our pension plans and $23 million for our other postretirement benefit plans are primarily due to the impact of decreases in the discount rate utilized to calculate the benefit obligation as well as changes to the mortality assumptions. The other postretirement benefits plan amendments of $18 million in 2009 and $38 million in

Notes (continued)

2008 are due to consecutive increases in the retirees’ cost-sharing percentage within our subsidized retiree medical benefit plans.

At December 31, 2009 and 2008, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets.

The current accounting rules for the determination of net periodic benefit expense allow for the delayed recognition of gains and losses caused by differences between actual and assumed outcomes for items such as estimated return on plan assets, or caused by changes in assumptions for items such as discount rates or estimated future compensation levels. The net actuarial gain (loss) presented in the following table and recorded in accumulated other comprehensive loss and net regulatory assets represents the cumulative net deferred gain (loss) from these types of differences or changes which have not yet been recognized in the Consolidated Statement of Income. A portion of the net actuarial gain (loss) is amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 12 years for our other postretirement benefit plans.

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


							Other
							Postretirement
	Pension Benefits						Benefits
	2009			2008			2009			2008
	(Millions)
Amounts included in accumulated other comprehensive loss:
Prior service (cost) credit	$	(4	)	$	(5	)	$	15		$	12
Net actuarial loss		(621	)		(708	)		(9	)		(8	)
Amounts included in net regulatory assets associated with our FERC-regulated gas pipelines:
Prior service credit		N/A			N/A		$	28		$	24
Net actuarial loss		N/A			N/A			(40	)		(57	)

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

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


										Other
	Pension Benefits									Postretirement Benefits
	2009			2008			2007			2009			2008			2007
	(Millions)
Components of net periodic benefit expense:
Service cost	$	32		$	23		$	23		$	2		$	2		$	3
Interest cost		62			60			54			16			18			17
Expected return on plan assets		(61	)		(79	)		(73	)		(9	)		(13	)		(12	)
Amortization of prior service cost (credit)		1			1			—			(11	)		—			—
Amortization of net actuarial loss		43			13			19			3			—			—
Amortization of regulatory asset		1			—			1			5			5			5

Net periodic benefit expense	$	78		$	18		$	24		$	6		$	12		$	13


Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss):
Net actuarial (gain) loss	$	(44	)	$	565		$	(68	)	$	1		$	15		$	(15	)
Prior service credit		—			—			—			(7	)		(16	)		—
Amortization of prior service (cost) credit		(1	)		(1	)		—			4			(1	)		(2	)
Amortization of net actuarial loss		(43	)		(13	)		(19	)		—			—			—

Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss)		(88	)		551			(87	)		(2	)		(2	)		(17	)


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

Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with our FERC-regulated gas pipelines are recognized in net regulatory assets at December 31, 2009, and include net

Notes (continued)

actuarial gain of $14 million, prior service credit of $11 million, amortization of prior service credit of $7 million, and amortization of net actuarial loss of $3 million. At December 31, 2008, amounts recognized in net regulatory assets included net actuarial loss of $83 million, prior service credit of $22 million, and amortization of prior service credit of $1 million. At December 31, 2007, amounts recognized in net regulatory liabilities included net actuarial gain of $18 million and amortization of prior service credit of $2 million.

Pre-tax amounts expected to be amortized in net periodic benefit expense in 2010 are as follows:


			Other
	Pension		Postretirement
	Benefits		Benefits
	(Millions)
Amounts included in accumulated other comprehensive loss:
Prior service cost (credit)	$	1	$	(5	)
Net actuarial loss		34		—
Amounts included in net regulatory assets associated with our FERC-regulated gas pipelines:
Prior service credit		N/A	$	(9	)
Net actuarial loss		N/A		2

The differences in the amount of actuarially determined net periodic benefit expense for our other postretirement benefit plans and the other postretirement benefit costs recovered in rates for our FERC-regulated gas pipelines are deferred as a regulatory asset or liability. At December 31, 2009, we have net regulatory liabilities of $3 million and at December 31, 2008, we had net regulatory assets of $26 million related to these deferrals. These amounts will be reflected in future rates based on the gas pipelines’ rate structures.

Key Assumptions

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


							Other
							Postretirement
	Pension Benefits						Benefits
	2009			2008			2009			2008
Discount rate		5.78	%		6.08	%		5.80	%		6.00	%
Rate of compensation increase		5.00			5.00			N/A			N/A

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


										Other
	Pension Benefits									Postretirement Benefits
	2009			2008			2007			2009			2008			2007
Discount rate		6.08	%		6.41	%		5.80	%		6.00	%		6.40	%		5.80	%
Expected long-term rate of return on plan assets		7.75			7.75			7.75			7.00			7.00			6.97
Rate of compensation increase		5.00			5.00			5.00			N/A			N/A			N/A

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

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

The expected return on plan assets component of net periodic benefit expense is calculated using the market-related value of plan assets. For assets held in our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect amortization of gains or losses associated with the difference between

Notes (continued)

the expected return on plan assets and the actual return on plan assets over a five-year period. Additionally, the market-related value of plan assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.

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

The assumed health care cost trend rate for 2010 is 8.2 percent, and systematically decreases to 5.0 percent by 2020. The health care cost trend rate assumption has a significant effect on the amounts reported. A one-percentage-point change in assumed health care cost trend rates would have the following effects:


	Point increase		Point decrease
	(Millions)
Effect on total of service and interest cost components	$	2	$	(2	)
Effect on other postretirement benefit obligation		33		(27	)

Plan Assets

The investment policy for our pension and other postretirement benefit plans articulates an investment philosophy in accordance with ERISA, which governs the investment of the assets in a diversified portfolio. The investment strategy for the assets of the pension plans and approximately one half of the assets of the other postretirement benefit plans include maximizing returns with reasonable and prudent levels of risk. The investment returns on the approximate one half of remaining assets of the other postretirement benefit plans is subject to federal income tax; therefore, the investment strategy also includes investing in a tax efficient manner. The target allocation ranges at December 31, 2009, for the pension plan assets were 65 percent to 90 percent equity securities, which includes commingled investment funds, and 10 percent to 30 percent debt securities and cash management.

The assets are invested in accordance with the target allocations identified previously. Additional target allocation ranges are identified for U.S. equities and non-U.S. equities. The target allocation ranges at December 31, 2009, were a minimum of 45 percent and a maximum of 70 percent for U.S. equities and a minimum of 20 percent and a maximum of 45 percent for non-U.S. equities. The asset allocation ranges established by the investment policy are based upon a long-term investment perspective. The ranges are weighted toward equity securities since the liabilities of the pension and other postretirement benefit plans are long-term in nature and historically equity securities have outperformed other asset classes over long periods of time.

Equity security investments are restricted to high-quality, readily marketable securities that are actively traded on the major U.S. and foreign national exchanges. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited in the pension plans except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation. No more than 25 percent of stock valued at market may be held in any one industry category. No more than 10 percent of the total capitalization of any one issuer shall be held in the total stock portfolio. The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Investment strategies using the direct holding of options or futures require approval and, historically, have not been used; however, these instruments may be used in commingled investment funds.

Fixed income securities are restricted to high-quality, marketable securities that include U.S. Treasuries, U.S. government guaranteed and nonguaranteed mortgage-backed securities, government and municipal bonds, and investment grade corporate issues. The overall rating of the debt security assets is required to be at least “A,” according to the Moody’s or Standard & Poor’s rating systems. No more than 5 percent of the total portfolio at the time of purchase may be invested in the debt securities of any one issuer with the exception of U.S. government guaranteed and agency securities.

During 2009, ten active investment managers and one passive investment manager managed substantially all of the pension plans’ funds and five active investment managers managed the other postretirement benefit plans’ funds.

Notes (continued)

Each of the managers had responsibility for managing a specific portion of these assets and each investment manager was responsible for 2 percent to 17 percent of the assets.

We believe the pension and other postretirement benefit plans have no significant concentrations of risk because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments in the plan are publicly traded, therefore, minimizing liquidity risk in the portfolio.

The pension and other postretirement benefit plans participate in securities lending programs under which securities are loaned to selected securities brokerage firms. The title of the securities is transferred to the borrower, but the plans are entitled to all distributions made by the issuer of the securities during the term of the loan and retain the right to redeem the securities on short notice. All loans require collateralization by U.S. government securities, cash, or letters of credit that equal at least 102 percent of the fair value of the loaned securities plus accrued interest. There are limitations on the aggregate fair value of securities that may be loaned to any one broker and to all brokers as a group. The collateral is invested in repurchase agreements, asset-backed securities, bank notes, corporate floating rate notes, and certificates of deposit. At December 31, 2009, the fair values of the loaned securities are $63 million for the pension plans and $9 million for the other postretirement benefit plans and are included in the following tables. At December 31, 2009, the fair values of securities held as collateral, and the obligation to return the collateral, are $66 million for the pension plans and $9 million for the other postretirement benefit plans and are not included in the following tables.

The fair values (see Note 14) of our pension plan assets at December 31, 2009, by asset category are as follows:


	Level 1		Level 2		Level 3		Total
	(Millions)
Pension assets:
Cash management fund (1)	$	23	$	—	$	—	$	23
Equity securities:
U.S. large cap		244		—		—		244
U.S. small cap		103		—		—		103
International developed markets large cap growth		2		58		—		60
Emerging markets growth		10		9		—		19
Commingled investment funds:
U.S. large cap (2)		—		84		—		84
Emerging markets value (3)		—		29		—		29
International developed markets large cap value (4)		—		74		—		74
Fixed income securities (5):
U.S. treasuries		11		3		—		14
Mortgage-backed securities		—		53		—		53
Corporate bonds		—		149		—		149
Insurance company investment contracts and other		—		8		—		8


Total assets at fair value	$	393	$	467	$	—	$	860

Notes (continued)

The fair values of our other postretirement benefits plan assets at December 31, 2009, by asset category are as follows:


	Level 1		Level 2		Level 3		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds (1)	$	15	$	—	$	—	$	15
Equity securities:
U.S. large cap		49		—		—		49
U.S. small cap		19		—		—		19
International developed markets large cap growth		—		13		—		13
Emerging markets growth		2		2		—		4
Commingled investment funds:
U.S. large cap (2)		—		8		—		8
Emerging markets value (3)		—		3		—		3
International developed markets large cap value (4)		—		7		—		7
Fixed income securities (6):
U.S. treasuries		1		—		—		1
Government and municipal bonds		—		8		—		8
Mortgage-backed securities		—		6		—		6
Corporate bonds		—		15		—		15


Total assets at fair value	$	86	$	62	$	—	$	148


(1)		These funds invest in high credit-quality, short-term corporate, and government money market debt securities that have remaining maturities of approximately one year or less, and are deemed to have minimal credit risk.

(2)		This fund invests primarily in equity securities comprising the Standard & Poor’s 500 Index. The investment objective of the fund is to match the return of the Standard & Poor’s 500 Index. There are certain restrictions that limit the amount that can be withdrawn from the fund to 4 percent per month of the plans’ total net asset value in the fund. If the plans do not withdraw the percentage allowed in a month, the plans accumulate the right to redeem the percentage not withdrawn in future months. As of December 31, 2009, 37 percent was eligible for withdrawal.

(3)		This fund invests in equity securities of international emerging markets for the purpose of capital appreciation. The fund invests primarily in common stocks of the financial, telecommunications, consumer goods, energy, industrial, materials, and utilities sectors, as well as forward foreign currency exchange contracts.

(4)		This fund invests in a diversified portfolio of international equity securities for the purpose of capital appreciation. The fund invests primarily in common stock of the consumer goods, materials, financial, energy, information technology, telecommunications, industrial, utilities, and health care sectors, as well as forward foreign currency exchange contracts.

(5)		The weighted-average credit quality rating of the pension assets fixed income security portfolio is investment grade with a weighted-average duration of 5.1 years.

(6)		The weighted-average credit quality rating of the other postretirement benefit assets fixed income security portfolio is investment grade with a weighted-average duration of 4.5 years.

The asset’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Shares of the cash management funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.

The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on

Notes (continued)

the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.

The fair value of all commingled investment funds has been estimated based on the net asset values per unit of each of the funds. The net asset values per unit of the fund represent the aggregate value of the fund’s assets less liabilities, divided by the number of units outstanding. Common stocks traded in active markets comprise the majority of each commingled investment fund’s assets. The fair value of these common stocks is derived from quoted market prices as of the close of business on the last business day of the year.

The fair value of fixed income securities, except U.S. treasury notes and bonds, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The treasury notes and bonds are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.

The investment contracts with insurance companies are valued at fair value by discounting the cash flow of a bond using a yield to maturity based on an investment grade index or comparable index with a similar maturity value, maturity period, and nominal coupon rate.

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


				Other
	Pension			Postretirement
	Benefits			Benefits
Equity securities		78	%		71	%
Debt securities		17			17
Other		5			12

		100	%		100	%

Equity securities include investments in commingled investment funds that invest entirely in equity securities and comprise 24 percent of the pension plans’ weighted-average assets and 13 percent of the other postretirement benefit plans’ weighted-average assets at December 31, 2008.

Plan Benefit Payments and Employer Contributions

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


					Federal
			Other		Prescription
	Pension		Postretirement		Drug
	Benefits		Benefits		Subsidy
	(Millions)
2010	$	44	$	18	$	(2	)
2011		44		18		(3	)
2012		51		18		(3	)
2013		52		18		(3	)
2014		66		18		(3	)
2015-2019		466		99		(19	)

In 2010, we expect to contribute approximately $60 million to our tax-qualified pension plans and approximately $1 million to our nonqualified pension plans, for a total of approximately $61 million, and approximately $16 million to our other postretirement benefit plans.

Notes (continued)

Defined Contribution Plans

We also maintain defined contribution plans for the benefit of substantially all of our employees. Generally, plan participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the plans’ guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $25 million in 2009, $24 million in 2008, and $22 million in 2007. A fund within one of our defined contribution plans is a nonleveraged employee stock ownership plan (ESOP). The shares held by the ESOP are treated as outstanding when computing earnings per share and the dividends on the shares held by the ESOP are recorded as a component of retained earnings. There were no contributions in 2009, 2008, and 2007 to this ESOP, other than dividend reinvestment, as contributions for purchase of our stock are no longer allowed within this defined contribution plan.

Note 8. Inventories


	December 31,
	2009		2008
	(Millions)
Natural gas liquids and olefins	$	70	$	56
Natural gas in underground storage		47		97
Materials, supplies and other		105		107

	$	222	$	260

Inventories are primarily determined using the average-cost method.

Note 9. Property, Plant, and Equipment


	Estimated	Depreciation
	Useful Life (a)	Rates (a)	December 31,
	(Years)	(%)	2009			2008
			(Millions)
Nonregulated:
Oil and gas properties	(b)		$	9,854		$	8,507
Natural gas gathering and processing facilities	5 - 40			5,461			4,823
Construction in progress	(c)			1,227			1,411
Other	2 - 45			816			765
Regulated:
Natural gas transmission facilities		.01 - 7.25		8,814			8,441
Construction in progress		(c)		152			120
Other		.01 - 50		1,301			1,293

Total property, plant, and equipment, at cost				27,625			25,360
Accumulated depreciation, depletion & amortization				(8,981	)		(7,619	)

Property, plant, and equipment — net			$	18,644		$	17,741


(a)		Estimated useful life and depreciation rates are presented as of December 31, 2009. Depreciation rates for regulated assets are prescribed by the FERC.

(b)		Oil and gas properties are depleted using the units-of-production method. See Note 1 of Notes to Consolidated Financial Statements for more information. Balances include $704 million at December 31, 2009, and $571 million at December 31, 2008, of capitalized costs related to properties with unproved reserves not yet subject to depletion at Exploration & Production.

(c)		Construction in progress balances not yet subject to depreciation and depletion.

Depreciation, depletion and amortization expense for property, plant, and equipment — net was $1.5 billion in 2009, $1.3 billion in 2008, and $1.0 billion in 2007. Our fourth-quarter depletion includes an unfavorable adjustment of $17 million. This adjustment was primarily the result of new oil and gas accounting guidance (Accounting Standards Update 2010-03) that requires we value our reserves using an average price. This price is calculated using prices at the beginning of the month for the preceding 12 months. This accounting guidance has been adopted on a prospective basis beginning in the fourth quarter of 2009.

Notes (continued)

Regulated property, plant, and equipment — net includes $946 million and $985 million at December 31, 2009 and 2008, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset Retirement Obligations

Our accrued obligations relate to producing wells, underground storage caverns, offshore platforms, fractionation facilities, gas gathering well connections and pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug both producing wells and storage caverns and remove any related surface equipment, to restore land and remove surface equipment at fractionation facilities, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

The following table presents the significant changes to our asset retirement obligations, of which $716 million and $630 million are included in other liabilities and deferred income, with the remaining current portion in accrued liabilities at December 31, 2009 and 2008, respectively.


	December 31,
	2009			2008
	(Millions)
Beginning balance	$	644		$	399
Liabilities settled		(13	)		(11	)
Additions		32			59
Accretion expense		51			64
Revisions		14			133

	$	728		$	644

Pursuant to its 2008 rate case settlement, Transco deposits a portion of its collected rates into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations. Transco is also required to make annual deposits into the trust through 2012. The trust is reported as a component of other assets and deferred charges and has a carrying value of $22 million and $13 million as of December 31, 2009 and 2008, respectively.

Property Insurance Changes

As a result of damage caused by recent hurricanes, the availability of named windstorm insurance has been significantly reduced. Additionally, named windstorm insurance coverage that is available for offshore assets comes at significantly higher premium amounts, higher deductibles and lower coverage limits. Considering these changes, we have reduced the overall named windstorm property insurance coverage for our assets in the Gulf of Mexico area beginning in the second quarter of 2009. In addition, certain assets are no longer covered for named windstorm losses, primarily certain offshore lateral pipelines.

Note 10. Accounts Payable and Accrued Liabilities

Under our cash-management system, certain cash accounts reflected negative balances to the extent checks written have not been presented for payment. These negative balances represent obligations and have been reclassified to accounts payable. Accounts payable includes $44 million of these negative balances at December 31, 2009 and $95 million at December 31, 2008.

Notes (continued)

Accrued Liabilities


	December 31,
	2009		2008
	(Millions)
Interest on debt	$	199	$	179
Taxes other than income taxes		176		221
Employee costs		158		167
Income taxes		112		144
Other, including other loss contingencies		303		428

	$	948	$	1,139

Note 11. Debt, Leases and Banking Arrangements

In February 2010, we completed a strategic restructuring that impacted our long-term debt and credit facilities. See Note 19 for further discussion.

Long-Term Debt


	Weighted-
	Average
	Interest			December 31,
	Rate (1)			2009 (2)			2008 (2)
				(Millions)
Secured
Capital lease obligations		9.5	%	$	3		$	5
Unsecured
5.5% to 10.25%, payable through 2033		7.7	%		8,023			7,446
Adjustable rate, payable through 2012		1.2	%		250			250

Total long-term debt, including current portion					8,276			7,701
Long-term debt due within one year					(17	)		(18	)

Long-term debt				$	8,259		$	7,683


(1)		At December 31, 2009.

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

Revolving Credit and Letter of Credit Facilities (Credit Facilities)

At December 31, 2009, we have an unsecured, $1.5 billion credit facility with a maturity date of May 1, 2012. Northwest Pipeline and Transco each have access to $400 million under the credit facility to the extent not otherwise utilized by us. We expect that our ability to borrow under the credit facility is reduced by $70 million due to the bankruptcy of a participating bank. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin. We are required to pay a commitment fee (currently 0.125 percent) based on the unused portion of the credit facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the credit agreement include the following:

•

Our ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2009, we are in compliance with this covenant.

•

Ratio of debt to capitalization must be no greater than 55 percent for Northwest Pipeline and Transco. At December 31, 2009, they are in compliance with this covenant.

We have unsecured credit facilities totaling $700 million, which mature in October 2010. These credit facilities provide for both borrowings and issuing letters of credit but are expected to be used primarily for issuing letters of credit. We are required to pay the funding bank fixed fees at a weighted-average interest rate of 2.29 percent on the total committed amount and interest on any borrowings at a fluctuating rate comprised of either a base rate or LIBOR.

Notes (continued)

The funding bank, an affiliate of Citibank N.A., syndicated its associated credit risk through a private offering that allows for the resale of certain restricted securities to qualified institutional buyers. To facilitate the syndication of these credit facilities, the bank established a trust funded by the institutional investors. The assets of the trust serve as collateral to reimburse the bank for our borrowings in the event that the credit facilities are delivered to the investors as described below. Thus, we have no asset securitization or collateral requirements under the credit facilities. Upon the occurrence of certain credit events, letters of credit under the agreement become cash collateralized creating a borrowing under the credit facilities. Concurrently, the funding bank can deliver the credit facilities to the institutional investors, whereby the investors replace the funding bank as lender under the credit facilities. Upon such occurrence, we will pay:


	$700 Million Facilities
	$500 million	$200 million
Interest Rate	4.35 percent	LIBOR
Facility Fixed Fee	2.29 percent

In second-quarter 2009, two of our unsecured revolving credit facilities totaling $500 million expired and were not renewed. These facilities were originated primarily in support of our former power business.

At December 31, 2009, WPZ has an unsecured $450 million credit agreement with a maturity date of December 2012. This $450 million credit facility is comprised initially of a $200 million revolving credit facility available for borrowings and letters of credit and a $250 million term loan. WPZ expects that its ability to borrow under this credit facility is reduced by $12 million due to the bankruptcy of a participating bank. Interest on borrowings under this agreement will be payable at rates per annum equal to either (1) a fluctuating base rate equal to the lender’s prime rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. At December 31, 2009, WPZ had a $250 million term loan outstanding and no amounts outstanding under the $200 million credit facility. Significant financial covenants under this credit agreement include the following:

•

WPZ is required to maintain a ratio of indebtedness to EBITDA (each as defined in the credit agreement) of no greater than 5.0 to 1.0. At December 31, 2009, they are in compliance with this covenant.

•

WPZ is required to maintain a ratio of EBITDA to interest expense (as defined in the credit agreement) of not less than 2.75 to 1.0 as of the last day of any fiscal quarter. At December 31, 2009, they are in compliance with this covenant.

At December 31, 2009, no loans are outstanding under our credit facilities. Letters of credit issued under our credit facilities are:


	Credit Facilities	Letters of Credit at
	Expiration	December 31, 2009
		(Millions)
$700 million unsecured credit facilities	October 2010	$	220
$1.5 billion unsecured credit facility	May 2012		—
$200 million WPZ unsecured credit facility	December 2012		—

		$	220

Exploration & Production’s Credit Agreement

Exploration & Production has an unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. The agreement extends through December 2013. Under the credit agreement, Exploration & Production is not required to post collateral as long as the value of its domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money positions on hedges entered into under the credit agreement. Exploration & Production is subject to additional covenants under the credit agreement including restrictions on hedge limits, the creation of liens, the incurrence of debt, the sale of assets and properties, and making certain payments, such as dividends, under certain circumstances.

Notes (continued)

Issuances

On March 5, 2009, we issued $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to certain institutional investors in a private debt placement. In August 2009, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

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


	(Millions)
2010	$	15
2011		936
2012		1,203
2013		—
2014		—

Cash payments for interest (net of amounts capitalized), including amounts related to discontinued operations, were as follows: 2009 — $592 million; 2008 — $592 million; and 2007 — $634 million.

Leases-Lessee

Future minimum annual rentals under noncancelable operating leases as of December 31, 2009, are payable as follows:


	(Millions)
2010	$	48
2011		33
2012		31
2013		27
2014		18
Thereafter		137

Total	$	294

Total rent expense was $70 million in 2009, $87 million in 2008 and $68 million in 2007. Rent expense reported in 2007 as discontinued operations, primarily related to a tolling agreement, was $148 million and was offset by approximately $276 million resulting from sales and other transactions made possible by the tolling agreement. This tolling agreement was included in the sale of our power business in 2007. (See Note 2.)

Note 12. Stockholders’ Equity

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

At December 31, 2009, approximately $25 million of our original $300 million, 5.5 percent junior subordinated convertible debentures, convertible into approximately 2 million shares of common stock, remain outstanding. In 2009 and 2008, we converted $28 million and $27 million, respectively, of the debentures in exchange for 3 million and 2 million shares, respectively, of common stock.

At December 31, 2007, we held all of WPZ’s seven million subordinated units outstanding. In February 2008, these subordinated units were converted into common units of WPZ 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 WPZ had preferential rights and the proceeds from these issuances in excess of the book basis of assets acquired by WPZ were

Notes (continued)

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 WPZ. In accordance with our policy regarding the issuance of equity of a consolidated subsidiary, such issuances of nonpreferential equity are accounted for as capital transactions and no gain or loss is recognized. Therefore, as a result of the 2008 conversion, we recognized a decrease to noncontrolling interests in consolidated subsidiaries and a corresponding increase to capital in excess of par value of approximately $1.2 billion.

We maintain a Stockholder Rights Plan, as amended and restated on September 21, 2004, and further amended May 18, 2007, and October 12, 2007, under which each outstanding share of our common stock has a right (as defined in the plan) attached. Under certain conditions, each right may be exercised to purchase, at an exercise price of $50 (subject to adjustment), one two-hundredth of a share of Series A Junior Participating Preferred Stock. The rights may be exercised only if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or more of our common stock or commences an offer for 15 percent or more of our common stock. The plan contains a mechanism to divest of shares of common stock if such stock in excess of 14.9 percent was acquired inadvertently or without knowledge of the terms of the rights. The rights, which until exercised do not have voting rights, expire in 2014 and may be redeemed at a price of $.01 per right prior to their expiration, or within a specified period of time after the occurrence of certain events. In the event a person becomes the owner of more than 15 percent of our common stock, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, our common stock having a value equal to two times the exercise price of the right. In the event we are engaged in a merger, business combination, or 50 percent or more of our assets, cash flow or earnings power is sold or transferred, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the right.

Note 13. Stock-Based Compensation

Plan Information

On May 17, 2007, our stockholders approved a plan that provides common-stock-based awards to both employees and nonmanagement directors. The plan generally contains terms and provisions consistent with the previous plans. The plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options and reserves 19 million shares for issuance. At December 31, 2009, 30 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 11 million shares were available for future grants. At December 31, 2008, 33 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 16 million shares were available for future grants.

Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorizes up to 2 million shares of our common stock to be available for sale under the plan. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of: (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the Plan was approved by the stockholders. The first offering under the ESPP commenced on October 1, 2007 and ended on December 31, 2007. Subsequent offering periods are from January through June and from July through December. Generally, all employees are eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an employee to purchase during each offering period is limited to 750 shares. The purchase price of the stock is 85 percent of the lower closing price of either the first or the last day of the offering period. The ESPP requires a one-year holding period before the stock can be sold. Employees purchased 370 thousand shares at an average price of $13.01 per share during 2009. Approximately 1.3 million and 1.7 million shares were available for purchase under the ESPP at December 31, 2009 and 2008, respectively.

Stock Options

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase

Notes (continued)

price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and can be subject to accelerated vesting if certain future stock prices or specific financial performance targets are achieved. Stock options generally expire ten years after the grant.

The following summary reflects stock option activity and related information for the year ending December 31, 2009.


				Weighted-
				Average		Aggregate
				Exercise		Intrinsic
Stock Options	Options			Price		Value
	(Millions)					(Millions)
Outstanding at December 31, 2008		11.5		$	18.10
Granted		2.1		$	10.86
Exercised		(0.2	)	$	8.46	$	2

Expired		(0.3	)	$	33.27
Forfeited		(0.1	)	$	22.73

Outstanding at December 31, 2009		13.0		$	16.73	$	90

Exercisable at December 31, 2009		10.0		$	16.32	$	69

The total intrinsic value of options exercised during the years ended December 31, 2009, 2008, and 2007 was $2 million, $49 million, and $74 million, respectively.

The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2009.


	Stock Options Outstanding						Stock Options Exercisable
					Weighted-						Weighted-
			Weighted-		Average				Weighted-		Average
			Average		Remaining				Average		Remaining
			Exercise		Contractual				Exercise		Contractual
Range of Exercise Prices	Options		Price		Life		Options		Price		Life
	(Millions)				(Years)		(Millions)				(Years)
$2.27 to $12.27		6.5	$	8.24		5.1		4.5	$	7.05		3.2
$12.28 to $22.27		3.8	$	19.50		4.9		3.7	$	19.50		4.9
$22.28 to $32.28		1.1	$	28.04		6.5		0.8	$	27.93		6.3
$32.29 to $42.29		1.6	$	37.17		5.1		1.0	$	37.61		3.1

Total		13.0	$	16.73		5.2		10.0	$	16.32		4.1

The estimated fair value at date of grant of options for our common stock granted in 2009, 2008, and 2007, using the Black-Scholes option pricing model, is as follows:


	2009			2008			2007
Weighted-average grant date fair value of options for our common stock granted during the year	$	5.60		$	12.83		$	9.09

Weighted-average assumptions:
Dividend yield		1.6	%		1.2	%		1.5	%
Volatility		60.8	%		33.4	%		28.7	%
Risk-free interest rate		2.3	%		3.5	%		4.6	%
Expected life (years)		6.5			6.5			6.3

The expected dividend yield is based on the average annual dividend yield as of the grant date. Expected volatility is based on the historical volatility of our stock and the implied volatility of our stock based on traded options. In calculating historical volatility, returns during calendar year 2002 were excluded as the extreme volatility during that time is not reasonably expected to be repeated in the future. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

Cash received from stock option exercises was $2 million, $32 million, and $56 million during 2009, 2008, and 2007, respectively; and the tax benefit realized was $1 million, $17 million, and $27 million, respectively.

Notes (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, 2009.


				Weighted-
				Average
Restricted Stock Units	Shares			Fair Value*
	(Millions)
Nonvested at December 31, 2008		4.4		$	22.91
Granted		3.4		$	10.23
Forfeited		(0.1	)	$	20.65
Vested		(1.6	)	$	17.93

Nonvested at December 31, 2009		6.1		$	16.24


*		Performance-based shares are primarily valued using the end-of-period market price until certification that the performance objectives have been completed, a value of zero once it has been determined that it is unlikely that performance objectives will be met, or a valuation pricing model. All other shares are valued at the grant-date market price.

Other restricted stock unit information


	2009		2008		2007
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	10.23	$	30.13	$	30.79

Total fair value of restricted stock units vested during the year ($’s in millions)	$	28	$	48	$	33

Performance-based shares granted under the Plan represent 29 percent of nonvested restricted stock units outstanding at December 31, 2009. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Note 14. Fair Value Measurements

Fair value is the amount received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

•

Level 1 — Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange traded.

Notes (continued)

•

Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 primarily consists of over-the-counter (OTC) instruments such as forwards, swaps, and options. These options, which hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Prior to the third quarter of 2009, these options were included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. However, due to the increased transparency, we now consider this input to be observable and have included these options in Level 2.

•

Level 3 — Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis.

Fair Value Measurements Using:


	December 31, 2009								December 31, 2008
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
			(Millions)								(Millions)
Assets:
Energy derivatives	$	178	$	911	$	5	$	1,094	$	680	$	1,223	$	547	$	2,450
Other assets		22		—		—		22		13		—		7		20

Total assets	$	200	$	911	$	5	$	1,116	$	693	$	1,223	$	554	$	2,470


Liabilities:
Energy derivatives	$	177	$	826	$	3	$	1,006	$	615	$	1,313	$	40	$	1,968

Total liabilities	$	177	$	826	$	3	$	1,006	$	615	$	1,313	$	40	$	1,968

Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps and options.

Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.

Notes (continued)

Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.

Contracts for which fair value can be estimated from executed transactions or broker quotes corroborated by other market data are generally classified within Level 2. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Our derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent expiring in the next 36 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.

Certain instruments trade in less active markets with lower availability of pricing information requiring valuation models using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2009, consist of natural gas liquids swaps for our Williams Partners segment as well as natural gas index transactions that are used to manage the physical requirements of our Exploration & Production segment.

The following tables present a reconciliation of changes in the fair value of net derivatives and other assets classified as Level 3 in the fair value hierarchy.

Level 3 Fair Value Measurements Using Significant Unobservable Inputs


	Year Ended December 31,
	2009						2008
	Net			Other			Net			Other
	Derivatives			Assets			Derivatives			Assets
	(Millions)
Beginning balance	$	507		$	7		$	(14	)	$	10
Realized and unrealized gains (losses):
Included in income from continuing operations		476			—			88			(3	)
Included in other comprehensive income (loss)		(331	)		—			486			—
Purchases, issuances, and settlements		(477	)		(7	)		(51	)		—
Transfers into Level 3		—			—			3			—
Transfers out of Level 3		(173	)		—			(5	)		—

Ending balance	$	2		$	—		$	507		$	7

Unrealized gains included in income from continuing operations relating to instruments still held at December 31	$	2		$	—		$	—		$	—

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

Notes (continued)

The following table presents, by level within the fair value of hierarchy, certain assets that have been measured at fair value on a nonrecurring basis, including certain items reported as discontinued operations.

Fair Value Measurements Using:


								Total
								Losses for the
	December 31, 2009							year ended
	Level 1		Level 2		Level 3			December 31, 2009
					(Millions)
Impairments:
Venezuelan property (see Note 2)	$	—	$	—	$	(a	)	$	(211	)
Investment in Accroven — Other (see Note 3)		—		—		(b	)		(75	)
Cost-based investment — Exploration & Production (see Note 3)		—		—		(b	)		(11	)
Unproved properties — Exploration & Production (see Note 4)		—		—		(c	)		(15	)

	$	—	$	—				$	(312	)


(a)		Fair value measured at March 31, 2009, was $106 million. These assets were expropriated by the Venezuelan government during the second quarter of 2009 and the entities that previously owned these assets are no longer consolidated. We recorded our retained noncontrolling investment in these entities at zero and recognized a gain of $9 million on the deconsolidation. (See Note 2.)

(b)		Fair value measured at March 31, 2009, was zero.

(c)		Fair value measured at December 31, 2009, is $22 million.

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

Financial Instruments

Fair-value methods

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

Cash and cash equivalents and restricted cash: The carrying amounts reported in the Consolidated Balance Sheet approximate fair value due to the short-term maturity of these instruments. Current and noncurrent restricted cash is included in other current assets and deferred charges and other assets and deferred charges, respectively, in the Consolidated Balance Sheet.

ARO Trust Investments: Our Transco subsidiary deposits a portion of its collected rates, pursuant to its 2008 rate case settlement, into an external trust specifically designated to fund future asset retirement obligations (ARO Trust). The ARO Trust invests in a portfolio of mutual funds that are reported at fair value in other assets and deferred charges in the Consolidated Balance Sheet and are classified as available-for-sale. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

Long-term debt: The fair value of our publicly traded long-term debt is determined using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings. At December 31, 2009 and 2008, approximately 97 percent of our long-term debt was publicly traded.

Guarantees: The guarantees represented in the following table consist primarily of guarantees we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on certain lease performance obligations. To estimate the fair value of the guarantees, the estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate for each guarantee based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rates are published by Moody’s Investors Service. Guarantees, if recognized, are included in accrued liabilities in the Consolidated Balance Sheet.

Other: Includes notes and other noncurrent receivables, margin deposits, customer margin deposits payable, cost-based investments and auction rate securities.

Notes (continued)

Energy derivatives: Energy derivatives include futures, forwards, swaps, and options. These are carried at fair value in the Consolidated Balance Sheet. See Note 14 for discussion of valuation of our energy derivatives.

Carrying amounts and fair values of our financial instruments


	December 31,
	2009						2008
	Carrying						Carrying
Asset (Liability)	Amount			Fair Value			Amount			Fair Value
	(Millions)
Cash and cash equivalents	$	1,867		$	1,867		$	1,438		$	1,438
Restricted cash (current and noncurrent)		28			28			37			37
ARO Trust Investments		22			22			13			13
Long-term debt, including current portion (a)		(8,273	)		(9,142	)		(7,696	)		(6,140	)
Guarantees		(36	)		(33	)		(38	)		(32	)
Other		(23	)		(25	)(b)		4			(13	)(b)
Net energy derivatives:
Energy commodity cash flow hedges		178			178			458			458
Other energy derivatives		(90	)		(90	)		24			24


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

(b)		Excludes certain cost-based investments in companies that are not publicly traded and therefore it is not practicable to estimate fair value. The carrying value of these investments was $2 million and $17 million at December 31, 2009 and December 31, 2008, respectively.

Energy Commodity Derivatives

Risk management activities

We are exposed to market risk from changes in energy commodity prices within our operations. We manage this risk on an enterprise basis and may utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases and sales of natural gas and NGLs attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.

We produce, buy, and sell natural gas at different locations throughout the United States. We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in revenues or margins 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. These 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 financial option contracts are either purchased options or a combination of options that comprise a net purchased option or a zero-cost collar. Our designation of the hedging relationship and method of assessing effectiveness for these option contracts are generally such that the hedging relationship is considered perfectly effective and no ineffectiveness is recognized in earnings. Hedges for storage contracts have not been designated as hedging instruments, despite economically hedging the expected cash flows generated by those agreements.

Notes (continued)

We produce and sell NGLs and olefins at different locations throughout North America. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs and olefins. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas and NGL market prices, we may enter into NGL or natural gas swap agreements, financial forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas and NGLs. These 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.

Other activities

We also enter into commodity derivatives for other than risk management purposes, including managing certain remaining legacy natural gas contracts and positions from our former power business and providing services to third parties. These legacy natural gas contracts include substantially offsetting positions and have an insignificant net impact on earnings.

Volumes

Our energy commodity derivatives are comprised of both contracts to purchase the commodity (long positions) and contracts to sell the commodity (short positions). Derivative transactions are categorized into four types:

•

Fixed price: Includes physical and financial derivative transactions that settle at a fixed location price;

•

Basis: Includes financial derivative transactions priced off the difference in value between a commodity at two specific delivery points;

•

Index: Includes physical derivative transactions at an unknown future price;

•

Options: Includes all fixed price options or combination of options (collars) that set a floor and/or ceiling for the transaction price of a commodity.

The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of December 31, 2009. Natural gas is presented in millions of British Thermal Units (MMBtu), and NGLs is presented in gallons. The volumes for options represent at location zero-cost collars and represent one side of the short position. The net index position for Exploration & Production includes certain long positions on behalf of other segments.


Derivative Notional Volumes		Measurement	Fixed Price			Basis			Index			Options
Designated as Hedging Instruments
Exploration & Production	Risk Management	MMBtu		(60,125,000	)		(58,400,000	)					(286,525,000	)
Williams Partners	Risk Management	MMBtu		1,247,500			412,500
Williams Partners	Risk Management	Gallons		(30,240,000	)

Not Designated as Hedging Instruments
Exploration & Production	Risk Management	MMBtu		(9,967,499	)		(7,805,000	)		8,214,454
William Partners	Risk Management	MMBtu					835,000
Williams Partners	Risk Management	Gallons								(2,998,800	)
Exploration & Production	Other	MMBtu		(851,850	)		(3,737,500	)

Fair values and gains (losses)

The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheet as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

Notes (continued)


	December 31, 2009
	Assets		Liabilities
	(Millions)
Designated as hedging instruments	$	352	$	174
Not designated as hedging instruments:
Legacy natural gas contracts from former power business		505		526
All other		237		306

Total derivatives not designated as hedging instruments		742		832

Total derivatives	$	1,094	$	1,006

The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (AOCI) or revenues.


	Year Ended
	December 31, 2009		Classification
	(Millions)
Net gain recognized in other comprehensive income (effective portion)	$	262	AOCI
Net gain reclassified from accumulated other comprehensive loss into income (effective portion)	$	618	Revenues
Gain recognized in income (ineffective portion)	$	4	Revenues

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.

The following table presents pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments.


	Year Ended
	December 31, 2009
	(Millions)
Revenues	$	37
Costs and operating expenses		33

Net gain	$	4

The cash flow impact of our derivative activities is presented in the Consolidated Statement of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. Additionally, Exploration & Production has an unsecured credit agreement with certain banks related to hedging activities. We are not required to provide collateral support for net derivative liability positions under the credit agreement as long as the value of Exploration & Production’s domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money position on hedges entered into under the credit agreement.

As of December 31, 2009, we have collateral totaling $96 million posted to derivative counterparties, all of which is in the form of letters of credit, to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $167 million, which includes a reduction of $3 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, is $74 million.

Notes (continued)

Cash flow hedges

Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in other comprehensive income and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of December 31, 2009, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to three years. Based on recorded values at December 31, 2009, $64 million of net gains (net of income tax provision of $39 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2009. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next year will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

Guarantees

In addition to the guarantees and payment obligations discussed in Note 16, we have issued guarantees and other similar arrangements as discussed below.

We are required by our revolving credit agreement to indemnify lenders for any taxes required to be withheld from payments due to the lenders and for any tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

We have provided guarantees in the event of nonpayment by our previously owned communications subsidiary, WilTel, on certain lease performance obligations that extend through 2042. The maximum potential exposure is approximately $40 million at December 31, 2009, and $42 million at December 31, 2008. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees included in accrued liabilities on the Consolidated Balance Sheet is $36 million at December 31, 2009 and $38 million at December 31, 2008.

At December 31, 2009, we do not expect these guarantees to have a material impact on our future liquidity or financial position. However, if we are required to perform on these guarantees in the future, it may have a material adverse effect on our results of operations.

Concentration of Credit Risk

Cash equivalents

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

Notes (continued)

Accounts and notes receivable

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


	December 31,
	2009		2008
	(Millions)
Receivables by product or service:
Sale of natural gas and related products and services (1)	$	599	$	653
Transportation of natural gas and related products		173		158
Joint interest		56		86
Other		2		49

Total	$	830	$	946


(1)		Includes $57 million net receivable from PDVSA at December 31, 2008. This amount has been fully reserved and subsequently deconsolidated in 2009. (See Note 2.)

Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains, Gulf Coast, and Canada. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2009 and 2008, we did not incur any significant losses due to counterparty bankruptcy filings.

The gross credit exposure from our derivative contracts as of December 31, 2009, is summarized as follows.


	Investment
Counterparty Type	Grade(a)		Total
	(Millions)
Gas and electric utilities	$	35	$	424
Energy marketers and traders		1		9
Financial institutions		661		661

	$	697		1,094

Credit reserves				—

Gross credit exposure from derivatives			$	1,094

Notes (continued)

We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of December 31, 2009, excluding collateral support discussed below, is summarized as follows.


	Investment
Counterparty Type	Grade(a)		Total
	(Millions)
Gas and electric utilities	$	17	$	17
Energy marketers and traders		1		8
Financial institutions		230		230

	$	248		255

Credit reserves				—

Net credit exposure from derivatives			$	255


(a)		We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Our eight largest net counterparty positions represent approximately 95 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are five counterparty positions, representing 64 percent of our net credit exposure from derivatives, associated with Exploration & Production’s hedging facility. (See Note 11.) Under certain conditions, the terms of this credit agreement may require the participating financial institutions to deliver collateral support to a designated collateral agent (which is another participating financial institution in the agreement). The level of collateral support required is dependent on whether the net position of the counterparty financial institution exceeds specified thresholds. The thresholds may be subject to prescribed reductions based on changes in the credit rating of the counterparty financial institution.

At December 31, 2009, the designated collateral agent holds $27 million of collateral support on our behalf under Exploration & Production’s hedging facility. In addition, we hold collateral support, including letters of credit, of $25 million related to our other derivative positions.

Revenues

In 2009, 2008, and 2007, there were no customers for which our sales exceeded 10 percent of our consolidated revenues.

Note 16. Contingent Liabilities and Commitments

Issues Resulting from California Energy Crisis

Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the U.S. Federal Energy Regulatory Commission (FERC). These challenges included refund proceedings, summer 2002 90-day contracts, investigations of alleged market manipulation including withholding, gas indices and other gaming of the market, new long-term power sales to the State of California that were subsequently challenged and civil litigation relating to certain of these issues. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.

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

Notes (continued)

settlements of the contractual disputes. The parties to the remanded proceeding have engaged the FERC’s Dispute Resolution Service to assist with settlement discussions.

Certain other issues also remain open at the FERC and for other nonsettling parties.

Refund proceedings

Although we entered into the State Settlement and Utilities Settlement, which resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, such as the counterparty to the contracts described above and various California end users that did not participate in the Utilities Settlement. As a part of the Utilities Settlement, we funded escrow accounts that will be used towards satisfying any ultimate refund determinations in favor of the nonsettling parties including interest on refund amounts that we might owe to settling and nonsettling parties. We are also owed interest from counterparties in the California market during the refund period for which we have recorded a receivable totaling $24 million at December 31, 2009. Collection of the interest and the payment of interest on refund amounts from the escrow accounts are subject to the conclusion of this proceeding. Therefore, we continue to participate in the FERC refund case and related proceedings.

Challenges to virtually every aspect of the refund proceedings, including the refund period, continue to be made. Despite two FERC decisions that will affect the refund calculation, significant aspects of the refund calculation process remain unsettled, and the final refund calculation has not been made. Because of our settlements, we do not expect that the final resolution of refund obligations will have a material impact on us.

Reporting of Natural Gas-Related Information to Trade Publications

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri, Tennessee and Wisconsin brought on behalf of direct and indirect purchasers of gas in those states.

•

The federal court in Nevada currently presides over cases that were transferred to it from state courts in Colorado, Kansas, Missouri, and Wisconsin. In 2008, the federal court in Nevada granted summary judgment in the Colorado case in favor of us and most of the other defendants, and on January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal. We expect that the Colorado plaintiffs will appeal, but the appeal cannot occur until the case against the remaining defendant is concluded.

•

On October 29, 2008, the Tennessee appellate court reversed the state court’s dismissal of the plaintiffs’ claims on federal preemption grounds and sent the case back to the lower court for further proceedings. We and other defendants appealed the reversal to the Tennessee Supreme Court, and we expect the court’s ruling in 2010.

•

On December 8, 2009, the Missouri appellate court upheld the trial court’s dismissal of a case for lack of standing. The plaintiff has appealed to the Missouri Supreme Court.

Environmental Matters

Continuing operations

Since 1989, our Transco subsidiary has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The

Notes (continued)

costs of any such remediation will depend upon the scope of the remediation. At December 31, 2009, we had accrued liabilities of $5 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than $500,000, which is included in the environmental accrual discussed above. We expect that these costs will be recoverable through Transco’s rates.

Beginning in the mid-1980s, our Northwest Pipeline 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 assessments and remediation activities at certain sites to comply with Washington’s current environmental standards. At December 31, 2009, we have accrued liabilities of $8 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

In March 2008, the EPA issued new air quality standards for ground level ozone. In September 2009, the EPA announced that it would reconsider those standards. In January 2010, the EPA proposed more stringent standards, which are expected to be final in August 2010. The EPA expects that new eight-hour ozone nonattainment areas will be designated in July 2011. The new standards and nonattainment areas will likely impact the operations of our interstate gas pipelines and cause us to incur additional capital expenditures to comply. At this time we are unable to estimate the cost of these additions that may be required to meet these regulations. We expect that costs associated with these compliance efforts will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2009, we have accrued liabilities totaling $8 million for these costs.

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

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

In September 2007, the EPA requested, and our Transco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued NOVs alleging violations of Clean Air Act requirements at these compressor stations. We met with the EPA in May 2008 and submitted our response denying the allegations in June 2008. In July 2009, the EPA requested additional information pertaining to these compressor stations and in August 2009, we submitted the requested information.

In January 2010, the Colorado Department of Public Health and Environment (CDPHE) proposed a penalty of $113,750 against Williams Production RMT Company for alleged permit violations at four compressor stations in Colorado. We are discussing the proposed penalties with CDPHE.

Notes (continued)

Former operations, including operations classified as discontinued

We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities include those described below.

Agrico

In connection with the 1987 sale of the assets of Agrico Chemical Company, we agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations to the extent such costs exceed a specified amount. At December 31, 2009, we have accrued liabilities of $8 million for such excess costs.

Other

At December 31, 2009, we have accrued environmental liabilities of $13 million related primarily to our:

•

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

•

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

•

Discontinued petroleum refining facilities;

•

Former exploration and production and mining operations.

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

Summary of environmental matters

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

Other Legal Matters

Will Price (formerly Quinque)

In 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two subsidiaries. All remaining defendants opposed class certification and on September 18, 2009, the court denied plaintiffs’ most recent motion to certify the class. On October 2, 2009, the plaintiffs filed a motion for reconsideration of the denial. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.

Gulf Liquids litigation

Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.

Notes (continued)

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. The negative assessment for the 2000-2002 time period resulted in additional severance and ad valorem taxes of $4 million. We disputed the DOA’s interpretation of the statutory obligation and appealed this assessment to the Wyoming State Board of Equalization (SBOE). The SBOE upheld the assessment and remanded it to the DOA to address the disallowance of a credit. We appealed to the Wyoming Supreme Court but the court ruled against us in December 2008. On April 14, 2009, the Wyoming Supreme Court denied our petition for rehearing and issued its mandate affirming its prior published decision in this case. We had accrued liabilities of $39 million as of December 31, 2008, related to this matter representing our estimated exposure, including interest, through the end of 2008. During 2009, we reduced our accrual for our estimated exposure by $6 million, including interest, and made net payments of $29 million. While certain issues involved remain to be resolved, we do not expect any material future changes from this matter and estimate our remaining net exposure, including interest, to be approximately $4 million at December 31, 2009, all of which has been recorded.

Royalty litigation

In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in Colorado state court alleging that we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of gas and extracted products, improperly charged certain expenses, and failed to refund amounts withheld in excess of ad valorem tax obligations. The plaintiffs claim that the class might be in excess of 500 individuals and seek an accounting and damages. We have reached a final partial settlement agreement for an amount that was previously accrued. We anticipate trial in 2010 on remaining issues related to royalty payment calculation and obligations under specific lease provisions. While we are not able to estimate the amount of any additional exposure at this time, it is reasonably possible that plaintiff’s claims could reach a material amount.

Other producers have been in litigation or discussions with a federal regulatory agency and a state agency in New Mexico regarding certain deductions used in the calculation of royalties. Although we are not a party to these matters, we have monitored them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. One of these matters involving federal litigation was decided on October 5, 2009. The resolution of this specific matter is not material to us. However, other related issues in these matters that could be material to us remain outstanding.

Notes (continued)

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, 2009, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Summary

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

Commitments

Commitments for construction and acquisition of property, plant, and equipment are approximately $221 million at December 31, 2009.

As part of managing our commodity price risk, we utilize contracted pipeline capacity primarily to move our natural gas production to other locations with more favorable pricing differentials. Our commitments under these contracts are as follows:


	(Millions)
2010	$	166
2011		170
2012		159
2013		141
2014		122
Thereafter		526

Total	$	1,284

We also have certain commitments to an equity investee for natural gas gathering and treating services which total $188 million over approximately eight years.

Notes (continued)

Note 17. Accumulated Other Comprehensive Loss

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


	Income (Loss)
													Other
													Postretirement
							Pension Benefits						Benefits
				Foreign			Prior			Net			Prior			Net
	Cash Flow			Currency			Service			Actuarial			Service			Actuarial
	Hedges			Translation			Cost			Gain (Loss)			Cost			Gain (Loss)			Total
	(Millions)
Balance at December 31, 2006	$	20		$	76		$	(4	)	$	(150	)	$	(4	)	$	2		$	(60	)


2007 Change:
Pre-income tax amount		201			53			—			68			—			15			337
Income tax provision		(77	)		—			—			(26	)		—			(6	)		(109	)
Net reclassification into earnings of derivative instrument gains (net of a $187 million income tax provision)		(303	)*		—			—			—			—			—			(303	)
Amortization included in net periodic benefit expense		—			—			—			19			2			—			21
Income tax provision on amortization		—			—			—			(8	)		(1	)		—			(9	)

		(179	)		53			—			53			1			9			(63	)

Allocation of other comprehensive loss to noncontrolling interests		2			—			—			—			—			—			2


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


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

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

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


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


2009 Change:
Pre-income tax amount		262			83			—			44			7			(1	)		395
Income tax (provision) benefit		(99	)		—			—			(17	)		—			1			(115	)
Net reclassification into earnings of derivative instrument gains (net of a $234 million income tax provision)		(384	)		—			—			—			—			—			(384	)
Amortization included in net periodic benefit expense		—			—			1			42			(4	)		—			39
Income tax (provision) benefit on amortization		—			—			(1	)		(16	)		1			—			(16	)

		(221	)		83			—			53			4			—			(81	)

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


Balance at December 31, 2009	$	75		$	136		$	(3	)	$	(388	)	$	10		$	2		$	(168	)


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

Notes (continued)

Note 18. Segment Disclosures

In February 2010, we completed our strategic restructuring that resulted in a revision to our segment reporting structure. Our reportable segments are now Williams Partners, Exploration & Production, and Other. (See Note 1.)

Our segment presentation of Williams Partners is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with this master limited partnership structure. Following our restructuring, WPZ maintains a capital and cash management structure that is separate from ours. WPZ is expected to be self-funding and maintains its own lines of bank credit and cash management accounts. These factors, coupled with a different cost of capital from our other businesses, serve to differentiate the management of this entity as a whole.

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:

•

Williams Partners — commodity purchases (primarily for NGL and crude marketing, shrink and fuel), depreciation and operation and maintenance expenses;

•

Exploration & Production — commodity purchases (primarily in support of commodity marketing and risk management activities), depletion, depreciation and amortization, lease and facility operating expenses and operating taxes;

•

Other — commodity purchases (primarily for shrink, feedstock and NGL and olefin marketing activities), depreciation and operation and maintenance expenses.

Energy commodity hedging by our business units may be done through intercompany derivatives with our Exploration & Production segment which, in turn, enters into offsetting derivative contracts with unrelated third parties. 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.

The following geographic area data includes revenues from external customers based on product shipment origin and long-lived assets based upon physical location.


	United States		Other		Total
	(Millions)
Revenues from external customers:
2009	$	8,065	$	190	$	8,255
2008		11,629		261		11,890
2007		9,966		273		10,239

Long-lived assets:
2009	$	19,247	$	410	$	19,657
2008		18,419		335		18,754
2007		16,279		361		16,640

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

Notes (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.


	Williams		Exploration &
	Partners		Production		Other			Eliminations			Total
	(Millions)
2009
Segment revenues:
External	$	4,338	$	3,164	$	753		$	—		$	8,255
Internal		174		541		27			(742	)		—

Total revenues	$	4,512	$	3,705	$	780		$	(742	)	$	8,255

Segment profit (loss)	$	1,308	$	400	$	(2	)	$	—		$	1,706
Less:
Equity earnings		81		18		37			—			136
Loss from investments		—		—		(75	)		—			(75	)

Segment operating income	$	1,227	$	382	$	36		$	—			1,645

General corporate expenses												(164	)

Total operating income											$	1,481

Other financial information:
Additions to long-lived assets	$	1,003	$	1,324	$	70		$	—		$	2,397
Depreciation, depletion & amortization	$	531	$	890	$	40		$	—		$	1,461
2008
Segment revenues:
External	$	5,519	$	5,156	$	1,215		$	—		$	11,890
Internal		243		1,065		42			(1,350	)		—

Total revenues	$	5,762	$	6,221	$	1,257		$	(1,350	)	$	11,890

Segment profit	$	1,416	$	1,262	$	142		$	—		$	2,820
Less:
Equity earnings		76		20		41			—			137
Income from investments		—		—		1			—			1

Segment operating income	$	1,340	$	1,242	$	100		$	—			2,682

General corporate expenses												(149	)

Total operating income											$	2,533

Other financial information:
Additions to long-lived assets	$	1,067	$	2,563	$	64		$	—		$	3,694
Depreciation, depletion & amortization	$	503	$	738	$	39		$	—		$	1,280
2007
Segment revenues:
External	$	5,400	$	3,757	$	1,082		$	—		$	10,239
Internal		216		760		31			(1,007	)		—

Total revenues	$	5,616	$	4,517	$	1,113		$	(1,007	)	$	10,239

Segment profit	$	1,560	$	419	$	106		$	—		$	2,085
Less equity earnings		79		25		33			—			137

Segment operating income	$	1,481	$	394	$	73		$	—			1,948

General corporate expenses												(161	)

Total operating income											$	1,787

Other financial information:
Additions to long-lived assets	$	1,077	$	1,717	$	105		$	—		$	2,899
Depreciation, depletion & amortization	$	478	$	542	$	31		$	—		$	1,051

Total segment revenues for Exploration & Production include $1,456 million, $3,244 million and $2,865 million of gas management revenues for the years ended December 31, 2009, 2008 and 2007, respectively. Gas management revenues include sales of natural gas in conjunction with marketing services provided to third parties and intercompany sales of fuel and shrink gas to the midstream businesses in Williams Partners. These revenues are substantially offset by similar amounts of gas management costs.

Notes (continued)

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


	Total Assets									Equity Method Investments
	December 31,			December 31,			December 31,			December 31,		December 31,		December 31,
	2009			2008			2007			2009		2008		2007
	(Millions)
Williams Partners	$	11,981		$	11,676		$	11,050		$	593	$	524	$	517
Exploration & Production (1)		10,575			11,646			10,126			95		87		72
Other		4,192			3,696			4,147			196		336		287
Eliminations		(1,469	)		(1,541	)		(985	)		—		—		—

		25,279			25,477			24,338			884		947		876
Discontinued operations (see Note 2)		1			529			723			—		—		—

Total	$	25,280		$	26,006		$	25,061		$	884	$	947	$	876


(1)		The 2009 decrease in Exploration & Production’s total assets is primarily due to the fluctuations in derivative assets as a result of the impact of changes in commodity prices on existing forward derivative contracts. The 2008 increase in Exploration & Production’s total assets is primarily due to an increase in property, plant, and equipment — net as a result of increased drilling activity, partially offset by fluctuations in derivative assets as a result of the impact of changes in commodity prices on existing forward derivative contracts. Exploration & Production’s derivative assets are substantially offset by their derivative liabilities.

Note 19. Subsequent Events

Strategic Restructuring

On February 17, 2010, we completed a strategic restructuring that involved contributing a substantial majority of our domestic midstream and gas pipeline businesses, including our limited and general partner interests in WMZ, to WPZ in exchange for cash and WPZ common units. The aggregate consideration received from WPZ consisted of the following:

•

The issuance to us of 203 million WPZ Class C units, which are identical to common units, except for a prorated initial distribution;

•

An increase in our general partner’s capital account to maintain our 2 percent general partner interest and the issuance of WPZ general partner units equal to 2/98th of the number of WPZ common units issued;

•

Proceeds from the sale of $3.5 billion aggregate principal amount of senior unsecured notes of WPZ to qualified institutional buyers, net of all expenses incurred by WPZ in connection with these transactions.

Utilizing the cash consideration received from WPZ, we retired $3 billion of debt and paid $574 million in related premiums as well as other transaction costs.

Long-term Debt and Credit Facilities

The WPZ $3.5 billion senior unsecured notes issued, at face, include:


	(Millions)
3.80% Senior Notes due 2015	$	750
5.25% Senior Notes due 2020		1,500
6.30% Senior Notes due 2040		1,250

Total	$	3,500

In connection with the issuance of the $3.5 billion unsecured notes previously discussed, WPZ entered into registration rights agreements with the initial purchasers of the notes. WPZ is obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing and use its commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing and to consummate the

Notes (continued)

exchange offers within 30 business days after such effective date. WPZ may also be required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If WPZ fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of 0.5 percent annually. Following the cure of any registration defaults the accrual of additional interest will cease.

The $3 billion of aggregate principal corporate debt retired includes:


	(Millions)
7.125% Notes due 2011	$	429
8.125% Notes due 2012		602
7.625% Notes due 2019		668
8.75% Senior Notes due 2020		586
7.875% Notes due 2021		179
7.70% Debentures due 2027		98
7.50% Debentures due 2031		163
7.75% Notes due 2031		111
8.75% Notes due 2032		164

Total	$	3,000

As part of the restructuring, WPZ, Transco and Northwest Pipeline, as co-borrowers, entered into a new $1.75 billion three-year senior unsecured revolving credit facility. The full amount of the new credit facility is available to WPZ to the extent not otherwise utilized by Transco and Northwest Pipeline, and may be increased by up to an additional $250 million. Transco and Northwest Pipeline each have access to borrow up to $400 million under the new facility to the extent not otherwise utilized by WPZ. WPZ utilized $250 million of the new credit facility to repay a term loan that was outstanding under its previously existing $450 million facility. As WPZ will be funding projects for its midstream and gas pipeline businesses, we reduced our $1.5 billion unsecured credit facility that expires May 2012 to $900 million and removed Transco and Northwest Pipeline as borrowers. Our unsecured credit facility that expires December 2013 and is used to facilitate our natural gas production hedging remains unchanged.

The new credit facility contains various covenants that limit, among other things, a borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and allow any material change in the nature of its business.

Under the new credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For Transco and Northwest Pipeline and their consolidated subsidiaries, the ratio of debt to capitalization (each as defined) is not permitted to be greater than 55 percent. Each of the above ratios will be tested quarterly, beginning June 30, 2010, and the debt to EBITDA ratio will be measured on a rolling four-quarter basis.

Contributed Businesses

The contributed gas pipeline businesses include 100 percent of Transco, 65 percent of Northwest Pipeline, and 24.5 percent of Gulfstream. We also contributed our general and limited partner interests in WMZ, which owns the remaining 35 percent of Northwest Pipeline. The contributed midstream businesses include significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, a recently acquired business in Pennsylvania’s Marcellus Shale region, and various equity investments in domestic processing and fractionation assets. A 25.5 percent ownership interest in Gulfstream and our Canadian midstream, Venezuelan, and domestic olefins operations were excluded from the transaction. Additionally, our Exploration & Production business was not included in this transaction.

Notes (continued)

Segment Changes

As a result of the restructuring, we have changed our segment reporting structure to align with the new parent-level focus employed by our chief operating decision-maker, considering the resource allocation and governance associated with managing WPZ as a distinctly separate entity. Our reportable segments are now Williams Partners, Exploration & Production, and Other.

Exploration & Production includes our former Gas Marketing Services segment, and Other includes the Canadian midstream and domestic olefins operations and a 25.5 percent interest in Gulfstream, as well as corporate operations.

Stockholders’ Equity & Noncontrolling Interests

We will account for the change in our ownership interest in WPZ as an equity transaction and adjust the carrying amount of noncontrolling interest to reflect this change in ownership. As a result, our capital in excess of par value will decrease with a corresponding increase to noncontrolling interests in consolidated subsidiaries.

Exploration & Production Acquisition

On May 25, 2010, Exploration & Production announced the acquisition of additional acreage in the Marcellus Shale in the Appalachian basin for $501 million. Exploration & Production is also purchasing a five percent overriding royalty interest associated with the acquisition for $84 million.

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA
(Unaudited)

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


	First			Second		Third		Fourth
	Quarter			Quarter		Quarter		Quarter
2009
Revenues	$	1,922		$	1,909	$	2,098	$	2,326
Costs and operating expenses		1,444			1,392		1,537		1,708
Income from continuing operations		19			151		192		222
Net income (loss)		(224	)		169		194		222
Amounts attributable to The Williams Companies, Inc.:
Income from continuing operations		2			123		141		172
Net income (loss)		(172	)		142		143		172
Basic earnings per common share:
Income from continuing operations		—			.21		.24		.30
Diluted earnings per common share:
Income from continuing operations		—			.21		.24		.29

2008
Revenues	$	3,095		$	3,574	$	3,137	$	2,084
Costs and operating expenses		2,264			2,614		2,280		1,618
Income from continuing operations		448			471		411		137
Net income		539			500		421		132
Amounts attributable to The Williams Companies, Inc.:
Income from continuing operations		411			412		360		123
Net income		500			437		366		115
Basic earnings per common share:
Income from continuing operations		.70			.71		.62		.21
Diluted earnings per common share:
Income from continuing operations		.69			.69		.61		.21

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding and rounding.

Amounts reported above for 2008 have been adjusted to reflect the presentation of certain revenues and costs on a net basis. These adjustments reduced previously reported revenues and costs and operating expenses by the same amount, with no impact on segment profit. The reductions were as follows (in millions):


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
2008	$	69	$	83	$	64	$	79

Net income for fourth-quarter 2009 includes the following pre-tax items:

•

$40 million gain related to the sale of our Cameron Meadows processing plant at Williams Partners (see Note 4 of Notes to Consolidated Financial Statements);

•

$17 million unfavorable depletion adjustment at Exploration & Production primarily as the result of new oil and gas accounting guidance that requires we value our reserves using an average price;

•

$15 million impairment of certain natural gas properties at Exploration & Production (see Note 4).

Net income for second-quarter 2009 includes the following pre-tax items:

•

$15 million gain related to our former coal operations (see summarized results of discontinued operations at Note 2);

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA — (Continued)
(Unaudited)

•

$11 million of income related to the recovery of certain royalty overpayments from prior periods (see Note 4).

Net income for first-quarter 2009 includes the following pre-tax items:

•

$211 million impairment of Venezuela property, plant, and equipment (see summarized results of discontinued operations at Note 2);

•

$75 million impairment of a Venezuelan investment in Accroven at Other (see Note 3);

•

$48 million of bad debt expense related to our discontinued Venezuela operations (see summarized results of discontinued operations at Note 2);

•

$30 million net charge related to the write-off of certain deferred charges related to our discontinued Venezuela operations (see summarized results of discontinued operations at Note 2);

•

$34 million of penalties from early release of drilling rigs at Exploration & Production (see Note 4);

•

$11 million impairment of a Venezuelan cost-based investment at Exploration & Production (see Note 3).

Net income for first-quarter 2009 also includes a $76 million benefit from the reversal of deferred tax balances related to our discontinued Venezuela operations (see summarized results of discontinued operations at Note 2).

Net income for fourth-quarter 2008 includes both the unfavorable impact of the significant decline in energy commodity prices and the following pre-tax items:

•

$129 million impairment of certain natural gas producing properties at Exploration & Production (see Note 4);

•

$43 million of income including associated interest related to the partial settlement of the Gulf Liquids litigation at Other (see Note 16);

•

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

•

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

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

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

•

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

•

$10 million gain from the sale of certain south Texas assets at Williams Partners (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);

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA — (Continued)
(Unaudited)

•

$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).

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES
(Unaudited)

We have significant oil and gas producing activities primarily in the Rocky Mountain and Mid-continent areas of the United States. Additionally, we have international oil- and gas-producing activities, primarily in Argentina. Proved reserves and revenues related to international activities are approximately 4 percent and 3 percent, respectively, of our total international and domestic proved reserves and revenues from producing activities. Accordingly, the following information relates only to the oil and gas activities in the United States. This information also excludes gas management activities associated with our former Gas Marketing Services segment.

Capitalized Costs


	As of December 31,
	2009			2008
	(Millions)
Proved properties	$	9,165		$	8,099
Unproved properties		953			806

		10,118			8,905
Accumulated depreciation, depletion and amortization and valuation provisions		(3,212	)		(2,353	)

Net capitalized costs	$	6,906		$	6,552

•

Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $762 million and $726 million, net, for 2009 and 2008, respectively. The capitalized cost amounts do not include approximately $1 billion of goodwill related to the purchase of Barrett Resources Corporation (Barrett) in 2001.

•

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

•

Unproved properties consist primarily of costs for acquired unproven reserves.

Costs Incurred


	For the Year Ended
	December 31,
	2009		2008		2007
			(Millions)
Acquisition	$	305	$	543	$	82
Exploration		51		38		38
Development		878		1,699		1,374

	$	1,234	$	2,280	$	1,494

•

Costs incurred include capitalized and expensed items.

•

Acquisition costs are as follows: The 2009 costs are primarily for additional leasehold and reserve acquisitions in the Piceance basin, and includes $85 million of proved property values. The 2008 and 2007 costs are primarily for additional leasehold and reserve acquisitions in the Piceance and Fort Worth basins. Included in the 2008 acquisition amounts is $140 million of proved property values and $71 million related to an interest in a portion of acquired assets that a third party subsequently exercised its contractual option to purchase from us, on the same terms and conditions.

•

Exploration costs include the costs of geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions, and the cost of retaining undeveloped leaseholds.

•

Development costs include costs incurred to gain access to and prepare development well locations for drilling and to drill and equip wells in our development basins.

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

Results of Operations


	For the Year Ended December 31,
	2009			2008			2007
	(Millions)
Revenues:
Oil and gas revenues	$	2,093		$	2,819		$	1,869
Other revenues		42			56			31

Total revenues		2,135			2,875			1,900

Costs:
Production costs		606			730			504
General & administrative		162			169			144
Exploration expenses		58			27			21
Depreciation, depletion & amortization		873			724			523
Impairment of certain natural gas properties in the Arkoma basin		—			143			—
Other (income) expense		50			1			(4	)

Total costs		1,749			1,794			1,188

Results of operations		386			1,081			712
Provision for income taxes		(146	)		(406	)		(273	)

Exploration and production net income	$	240		$	675		$	439

•

Results of operations for producing activities consist of all related domestic oil- and gas-producing activities. Amounts for 2008 exclude a $148 million gain on sale of a contractual right to a production payment on certain future international hydrocarbon production.

•

Oil and gas revenues consist primarily of natural gas production sold and includes the impact of hedges.

•

Other revenues consist of activities that are not a direct part of the producing activities. Other expenses in 2009 also include $32 million of expense related to penalties from the early release of drilling rigs and $15 million write-down of costs associated with acquired unproved reserves.

•

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

•

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

•

Depreciation, depletion and amortization includes depreciation of support equipment. Additionally, 2009 includes $17 million additional depreciation, depletion and amortization as a result of our recalculation of fourth quarter depreciation, depletion and amortization utilizing our year-end reserves which were lower than 2008. The lower reserves are primarily a result of the application of new rules issued by the SEC.

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

Proved Reserves


	2009			2008			2007
				(Bcfe)
Proved reserves at beginning of period		4,339			4,143			3,701
Revisions		(859	)		(220	)		(106	)
Purchases		159			31			19
Extensions and discoveries		1,051			791			863
Wellhead production		(435	)		(406	)		(334	)

Proved reserves at end of period		4,255			4,339			4,143

Proved developed reserves at end of period		2,387			2,456			2,252

•

The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

•

A significant portion of the revisions for 2009 are a result of the impact of the new SEC rules. Proved reserves are lower because of the lower 12-month average, first-of-the-month price as compared to the 2008 year-end price, and the revision of proved undeveloped reserve estimates based on new guidance. Approximately one-half of the revisions for 2008 relate to the impact of lower average year-end natural gas prices used in 2008 compared to the 2007.

•

Extensions and discoveries in 2009 are higher this year as compared to prior years due in part to the expanded definition of oil and gas reserves supported by reliable technology and reasonable certainty used for reserves estimation.

•

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

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is based on the estimated quantities of proved reserves. During 2009, we adopted prescribed accounting revisions associated with oil and gas authoritative guidance. Those revisions include using the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. These revisions are reflected in our 2009 amounts. For the year-ended December 31, 2009, the average natural gas equivalent price used in the estimates was $2.76 per MMcfe. For the years ended December 31, 2008 and 2007, the average year-end natural gas equivalent prices used in the estimates were $4.41 and $5.78 per MMcfe, respectively. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The

100

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

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 $2,833 million of future development costs, approximately 60 percent is estimated to be spent in 2010, 2011, and 2012.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows


	At December 31,
	2009			2008
	(Millions)
Future cash inflows	$	11,729		$	19,127
Less:
Future production costs		3,990			5,516
Future development costs		2,833			3,772
Future income tax provisions		1,404			3,284

Future net cash flows		3,502			6,555
Less 10 percent annual discount for estimated timing of cash flows		(1,789	)		(3,382	)

Standardized measure of discounted future net cash flows	$	1,713		$	3,173

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


	2009			2008			2007
	(Millions)
Standardized measure of discounted future net cash flows beginning of period	$	3,173		$	4,803		$	2,856
Changes during the year:
Sales of oil and gas produced, net of operating costs		(1,006	)		(2,091	)		(1,426	)
Net change in prices and production costs		(3,310	)		(2,548	)		2,019
Extensions, discoveries and improved recovery, less estimated future costs		1,131			1,423			2,163
Development costs incurred during year		389			817			738
Changes in estimated future development costs		701			(724	)		(931	)
Purchase of reserves in place, less estimated future costs		171			55			48
Revisions of previous quantity estimates		(923	)		(395	)		(266	)
Accretion of discount		450			714			434
Net change in income taxes		932			1,108			(1,108	)
Other		5			11			276

Net changes		(1,460	)		(1,630	)		1,947

Standardized measure of discounted future net cash flows end of period	$	1,713		$	3,173		$	4,803

In relation to the new SEC rules, we estimate that the standardized measure of discounted future net cash flows declined approximately $840 million on a before tax basis and excluding the overall price rule impact. The significant components of this decline include an estimated $640 million decrease included in revisions of previous quantity estimates and a related $430 million decrease included in the net change in prices and production costs, partially offset by a $210 million increase included in extensions, discoveries and improved recovery, less estimated future costs. Additionally, we estimate that a significant portion of the remaining net change in price and production costs is due to the application of the new pricing rules which resulted in the use of lower prices at December 31, 2009, than would have resulted under the previous rules.

101