• As of September 30, 2008, we have approximately $1.5 billion of cash and cash equivalents and nearly $2.6 billion of available capacity under our credit facilities. (See further discussion in Management's Discussion and Analysis of Financial Condition - Available Liquidity.)

• We have no significant debt maturities until 2011.

• Considering master netting agreements and collateral support, we do not have significant risk from our net credit exposure to derivative counterparties. (See further discussion in Energy Trading Activities - Counterparty Credit Considerations.)

To the extent that these recent events drive sustained lower energy commodity prices, it will negatively impact our future results of operations and cash flow from operations and could result in a further reduction in capital expenditures. These impacts could also include the future nonperformance of counterparties or impairments of goodwill and long-lived assets. In addition, the overall decline in equity markets in 2008 has negatively impacted our employee benefit plan assets and will likely increase expense in future periods. (See Note 7 of Notes to Consolidated Financial Statements.)
Company Outlook
Our plan for 2008 has been focused on disciplined growth. Our plans for the remainder of 2008 and into 2009 have been adjusted in light of lower energy commodity prices and the disruption in the financial markets. At present, we intend to continue our disciplined growth, but the level of our future investment will be adjusted as required to maintain adequate liquidity. Our objectives include continuing to improve EVA® and invest in our businesses in a way that meets customer needs and enhances our competitive position:
• Continue to increase natural gas production and reserves;

• Increase the scale of our gathering and processing business in key growth basins;

• Continue to invest in expansion projects on our interstate natural gas pipelines.

Potential risks and/or obstacles that could prevent us from achieving these objectives include:
• Availability of capital;

• Counterparty credit and performance risk;

• Volatility of commodity prices;

• Lower than expected levels of cash flow from operations;

• Decreased drilling success at Exploration & Production;

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

Management's Discussion and Analysis (Continued)
• General economic, financial markets, or industry downturn;

• Changes in the current political and regulatory environment;

• Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 12 of Notes to Consolidated Financial Statements).

We continue to address these risks through utilization of commodity hedging strategies, focused efforts to resolve regulatory issues and litigation claims, disciplined investment strategies, and maintaining at least $1 billion in liquidity from cash and cash equivalents and unused revolving credit facilities. In addition, we utilize master netting agreements and collateral requirements with our counterparties.
Our income from continuing operations for the nine months ended September 30, 2008, increased $563 million compared to the nine months ended September 30, 2007. This increase is reflective of:
• Higher net realized average prices and continued strong natural gas production growth at Exploration & Production;

• A pre-tax gain of $148 million at Exploration & Production on the sale of a contractual right to a production payment on certain future international hydrocarbon production;

• Favorable commodity price margins at Midstream.

See additional discussion in Results of Operations.
Our net cash provided by operating activities for the nine months ended September 30, 2008, increased $929 million compared to the nine months ended September 30, 2007, primarily due to our improved operating results. See additional discussion in Management's Discussion and Analysis of Financial Condition.
Recent Events
In September 2008, Hurricanes Gustav and Ike impacted our operations, primarily at Midstream. We estimate that our segment profit for third-quarter 2008 was decreased by approximately $50 million to $65 million due to downtime and charges for repairs and property insurance deductibles associated with Hurricanes Gustav and Ike. We also estimate that fourth-quarter 2008 pre-tax results will be reduced by approximately $10 million to $20 million due to downtime and reduced volumes. See additional discussion in Results of Operations
- Segments, Gas Pipeline and Midstream Gas & Liquids. In July 2008, we completed our stock repurchase program by reaching the $1 billion limit authorized by our Board of Directors. (See Note 11 of Notes to Consolidated Financial Statements.) In 2008, we increased our positions by acquiring undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin and undeveloped leasehold acreage and producing properties in the Fort Worth basin. See additional discussion in Results of Operations - Segments, Exploration & Production. In 2008, we recognized pre-tax income of $172 million in income from discontinued operationsrelated to our former Alaska operations. (See Note 3 of Notes to Consolidated Financial Statements.) In 2008, we recognized income of $148 million related to the sale of a contractual right to a production payment on certain future international hydrocarbon production. See additional discussion in Results of Operations - Segments, Exploration & Production. In January 2008, Williams Pipeline Partners L.P. completed its initial public offering. See additional discussion in Results of Operations - Segments, Gas Pipeline. Transco's new rates became effective June 1, 2008. See additional discussion in Results of Operations - Segments, Gas Pipeline. General
Unless indicated otherwise, the following discussion and analysis of Results of Operations and Financial Condition relates to our current continuing operations and should be read in conjunction with the Consolidated Financial Statements and notes thereto included in Item 1 of this document and our 2007 Annual Report on Form 10-K.

Management's Discussion and Analysis (Continued) Fair Value Measurements
On January 1, 2008, we adopted Statement of Financial Accounting Standards No. 157, "Fair Value Measurements" (SFAS 157), for our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy derivatives. See Note 10 of Notes to Consolidated Financial Statements for disclosures regarding SFAS 157, including discussion of the fair value hierarchy levels and valuation methodologies.
Certain of our energy derivative assets and liabilities and other assets are valued using unobservable inputs and included in Level 3. At September 30, 2008, 13 percent of the total assets measured at fair value and four percent of the total liabilities measured at fair value are included in Level 3.
Certain instruments 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. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.
The determination of fair value also incorporates the time value of money and credit risk factors including the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash deposits and letters of credit) and our nonperformance risk on our 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.
The instruments included in Level 3 at September 30, 2008, predominantly consist of options that primarily hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled. The options are valued using an industry standard Black-Scholes option pricing model. Certain inputs into the model are generally observable, such as commodity prices and interest rates, whereas a significant input, implied volatility by location, is unobservable. The impact of volatility on changes in the overall fair value of the options structured as collars is reduced because of the offsetting nature of the put and call positions. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices. The hedges are accounted for as cash flow hedges where net unrealized gains and losses from changes in fair value are recorded, to the extent effective, in other comprehensive income and subsequently impact earnings when the underlying hedged production is sold.
Exploration & Production has an unsecured credit agreement through December 2013 with certain banks which serves to reduce our usage of cash and other credit facilities for margin requirements related to options included in the facility.

Management's Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
   The following table and discussion is a summary of our consolidated results
of operations for the three and nine months ended September 30, 2008, compared
to the three and nine months ended September 30, 2007. The results of operations
by segment are discussed in further detail following this consolidated overview
discussion.

                                 Three months ended September 30,                            Nine months ended September 30,
                                                    $ Change        % Change                                  $ Change        % Change
                                                      from            from                                      from            from
                        2008           2007          2007*           2007*           2008         2007          2007*          2007*
                            (Millions)                                                  (Millions)
Revenues              $   3,267       $ 2,860            +407             +14 %    $ 10,220      $ 8,052         +2,168             +27 %
Costs and
expenses:
Costs and
operating expenses        2,386         2,222            -164              -7 %       7,506        6,245         -1,261             -20 %
Selling, general
and administrative
expenses                    133           107             -26             -24 %         375          317            -58             -18 %
Other income - net            -            (2 )            -2            -100 %        (152 )        (38 )         +114              NM
General corporate
expenses                     34            40              +6             +15 %         118          116             -2              -2 %

Total costs and
expenses                  2,553         2,367                                         7,847        6,640

Operating income            714           493                                         2,373        1,412
Interest accrued -
net                        (150 )        (162 )           +12              +7 %        (456 )       (494 )          +38              +8 %
Investing income             65            78             -13             -17 %         175          196            -21             -11 %
Minority interest
in income of
consolidated
subsidiaries                (55 )         (29 )           -26             -90 %        (157 )        (68 )          -89            -131 %
Other income - net            2             8              -6             -75 %           7           12             -5             -42 %

Income from
continuing
operations before
income taxes                576           388                                         1,942        1,058
Provision for
income taxes                207           160             -47             -29 %         738          417           -321             -77 %

Income from
continuing
operations                  369           228                                         1,204          641
Income (loss) from
discontinued
operations                   (3 )         (30 )           +27             +90 %          99          124            -25             -20 %

Net income            $     366       $   198                                      $  1,303      $   765

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

Three months ended September 30, 2008 vs. three months ended September 30, 2007
The increase in revenues is primarily due to higher production revenues at Exploration & Production resulting from both higher net realized average prices and increased production volumes sold. Midstream also experienced higher natural gas liquid (NGL) and olefin production revenues due primarily to higher prices, partially offset by lower volumes.
The increase in costs and operating expenses is primarily due to higher costs associated with our NGL and olefin production businesses at Midstream. Higher depreciation, depletion and amortization and higher operating taxes at Exploration & Production also contributed to our increased expenses.
The increase in selling, general and administrative expenses (SG&A) primarily includes the impact of higher staffing and compensation at Exploration & Production in support of increased operational activities.
Other income - net within operating income in third-quarter 2008 includes a gain of $10 million on the sale of certain south Texas assets at Gas Pipeline and $8 million of net gains on foreign currency exchanges at Midstream. These gains are partially offset by a $14 million impairment of certain natural gas producing properties at Exploration & Production.
Other income - net within operating income in third-quarter 2007 includes income of $12 million associated with a payment received for a terminated firm transportation agreement on Gas Pipeline's Grays Harbor lateral, partially offset by $6 million of net losses on foreign currency exchanges at Midstream.
The increase in operating income primarily reflects both higher net realized average prices and continued strong natural gas production growth at Exploration & Production.

Management's Discussion and Analysis (Continued) Interest accrued - net decreased primarily due to increased capitalized interest resulting from an increased level of capital expenditures. Additionally, the decrease was impacted by lower interest rates on debt issuances that occurred late in the fourth quarter 2007 and in the first half of 2008 for which the proceeds were primarily used to retire existing debt bearing higher interest rates.
The decrease in investing income is due primarily to a $17 million decrease in interest income largely a result of lower average interest rates in 2008 compared to 2007.
Minority interest in income of consolidated subsidiaries increased primarily due to the growth in the minority interest holdings of Williams Partners L.P. and Williams Pipeline Partners L.P.
Provision for income taxes increased primarily due to higher pre-tax income. See Note 5 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
See Note 3 of Notes to Consolidated Financial Statements for a discussion of the items in income (loss) from discontinued operations.
Nine months ended September 30, 2008 vs. nine months ended September 30, 2007 The increase in revenues is primarily due to higher production revenues at Exploration & Production resulting from both higher net realized average prices and increased production volumes sold. Midstream also experienced higher olefin production revenues primarily due to higher prices and volumes as well as increased NGL, olefin and crude marketing and NGL production revenues all due to higher prices, partially offset by lower volumes. In addition, revenues increased due to the favorable change in unrealized mark-to-market revenues at Gas Marketing Services primarily as a result of reduced losses in 2008 from legacy derivative contracts that are no longer outstanding.
The increase in costs and operating expenses is primarily due to increased NGL, olefin, and crude marketing purchases and increased costs associated with our olefin and NGL production businesses at Midstream. Higher depreciation, depletion and amortization, increased operating taxes and higher lease operating expenses at Exploration & Production also contributed to our increased expenses.
The increase in SG&A includes the impact of higher staffing and compensation at our Exploration & Production and Midstream segments in support of increased operational activities. The increase also includes $11 million in bad debt expense primarily at Exploration & Production.
Other income - net within operating income in 2008 includes a gain of $148 million on the sale of a contractual right to a production payment on certain future international hydrocarbon production at Exploration & Production, $20 million of net gains on foreign currency exchanges at Midstream, and a gain of $10 million on the sale of certain south Texas assets at Gas Pipeline. These items are partially offset by $21 million higher project development costs at Gas Pipeline and a $14 million impairment of certain natural gas producing properties at Exploration & Production.
Other income - net within operating income in 2007 includes income of $18 million associated with payments received for a terminated firm transportation agreement on Gas Pipeline's Grays Harbor lateral and income of $17 million from a change in estimate related to a regulatory liability at Northwest Pipeline.
The increase in operating income reflects increased net realized average prices, continued strong natural gas production growth and a gain of $148 million on the sale of a contractual right to a production payment at Exploration & Production, partially offset by higher operating costs. The increase also reflects reduced losses in 2008 from legacy derivative contracts that are no longer outstanding at Gas Marketing Services and continued favorable commodity price margins at Midstream, partially offset by higher operating costs.
Interest accrued - net decreased primarily due to increased capitalized interest resulting from an increased level of capital expenditures. Additionally, the decrease was impacted by lower interest rates on debt issuances that occurred late in the fourth quarter 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.

Management's Discussion and Analysis (Continued) The decrease in investing income is primarily due to $47 million of decreased interest income largely due to lower average interest rates in 2008 compared to 2007, partially offset by an increase in equity earnings of $31 million, primarily at Midstream.
Minority interest in income of consolidated subsidiaries increased primarily due to the growth in the minority interest holdings of Williams Partners L.P. and Williams Pipeline Partners L.P.
Provision for income taxes increased primarily due to higher pre-tax income. See Note 5 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
See Note 3 of Notes to Consolidated Financial Statements for a discussion of the items in income (loss) from discontinued operations.

Management's Discussion and Analysis (Continued) Results of Operations - Segments
Exploration & Production
Overview of Nine Months Ended September 30, 2008 During the first nine months of 2008, we continued our development drilling program in our growth basins. Accordingly, we:
• Benefited from increased domestic net realized average prices, which increased by approximately 42 percent compared to the first nine months of 2007. The domestic net realized average price for the first nine months of 2008 was $7.22 per thousand cubic feet of gas equivalent (Mcfe) compared to $5.09 per Mcfe in 2007. Net realized average prices include market prices, net of fuel and shrink and hedge positions, less gathering and transportation expenses.

• Increased average daily domestic production levels by approximately 21 percent compared to the first nine months of 2007. The average daily domestic production for the first nine months of 2008 was approximately 1,073 million cubic feet of gas equivalent (MMcfe) compared to 890 MMcfe in 2007. The increased production is primarily due to increased development within the Piceance, Powder River, and Fort Worth basins.

• Increased capital expenditures for domestic drilling, development, and acquisition activity in the first nine months of 2008 by $699 million compared to 2007. Capital expenditures for 2008 include acquisitions in the Piceance and Fort Worth basins discussed in Significant events below.

The benefits of higher net realized average prices and higher production volumes were partially offset by increased operating costs. The increase in operating costs was primarily due to increased production volumes and higher well service and lease service costs. In addition, higher production volumes coupled with higher capitalized drilling costs increased depletion, depreciation, and amortization expense.
Significant events
In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for $148 million. In the first quarter of 2008, we received $118 million in cash, with the remainder placed in escrow subject to certain post-closing conditions and adjustments. We recognized a pre-tax gain of $118 million in the first quarter of 2008 related to the initial cash received. In the second quarter of 2008, the remaining cash was received from escrow and recognized as income. As a result of the contract termination, we have no further interests associated with the crude oil concession, which is located in Peru. We had obtained these interests through our acquisition of Barrett Resources Corporation in 2001.
In May 2008, we acquired certain undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin for $285 million. In July 2008, a third party exercised its contractual option to purchase, on the same terms and conditions, an interest in a portion of the acquired assets for $71 million. We received this $71 million in October 2008.
In September 2008, we increased our position in the Fort Worth basin by acquiring certain undeveloped leasehold acreage and producing properties for $147 million subject to post-closing adjustments. This acquisition is consistent with our growth strategy of leveraging our horizontal drilling expertise by acquiring and developing low-risk properties. The change in purchase price from the $166 million announced in July 2008 relates to the ongoing process of finalizing title work on a small portion of the acquisition package. Outlook for the Remainder of 2008
Our expectations for the remainder of the year include:
• Maintaining our development drilling program in the Piceance, Powder River, San Juan, Fort Worth and Arkoma basins through our remaining planned capital expenditures projected between $450 million and $550 million.

Management's Discussion and Analysis (Continued)

• Continuing toward our average daily domestic production level goal of 10 to 20 percent growth compared to 2007.

Risks to achieving our expectations include unfavorable natural gas market price movements which are impacted by numerous factors, including weather conditions, domestic natural gas production and consumption, and rising concerns about the recent volatility in the global economy and the related impact on natural gas prices. Also, achievement of expectations can be affected by costs of services associated with drilling.
In addition, changes in laws and regulations may impact our development drilling program. The Colorado Oil & Gas Conservation Commission (COGCC) has proposed rules that could alter our drilling schedule and increase our costs of permitting and environmental compliance. We continue to actively monitor the situation and provide input to the COGCC staff responsible for rulemaking. The final rules could become effective as early as April 2009. Declining Natural Gas Prices
As a result of the recent market events and the recent decline in natural gas prices, we plan to deploy fewer drilling rigs in 2009 compared to 2008. This will reduce capital expenditures and the number of wells drilled in 2009 compared to 2008. However, we still expect approximately 8 to 10 percent production growth in 2009 compared to 2008. We continue to utilize certain derivative instruments to hedge our cash flows from the sales of natural gas production.
Hedging Strategy
To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative forward sales contracts that fix the sales price relating to a portion of our future production using NYMEX and basis fixed-price contracts and collar agreements.
For the remainder of 2008 and total year 2009, we have the following agreements and contracts for our daily domestic production, shown at weighted average volumes and basin-level weighted average prices:

                                                             Remainder of 2008                                   2009
                                                   Volume             Price ($/Mcf)             Volume              Price ($/Mcf)
                                                  (MMcf/d)      Floor-Ceiling for Collars      (MMcf/d)       Floor-Ceiling for Collars
Collar agreements - Rockies                         160               $6.08 - $9.04              150                $6.11 - $9.04
. . .