Exhibit 99.2

PART I — FINANCIAL INFORMATION

Williams Partners L.P.
Supplemental Consolidated Statement of Income *
(Unaudited)

		Three months ended								Nine months ended
		September 30,								September 30,
		2010				2009				2010				2009
						(Millions, except per-unit amounts)
Revenues:
Gas Pipeline		$	409			$	380			$	1,196			$	1,202
Midstream Gas & Liquids			919				822				3,022				2,092
Intercompany eliminations			(1	)			(1	)			(1	)			(6	)
Total revenues			1,327				1,201				4,217				3,288
Segment costs and expenses:
Costs and operating expenses			923				810				2,958				2,225
Selling, general and administrative expenses			70				75				202				221
Other income — net			(13	)			(1	)			(22	)			—
Segment costs and expenses			980				884				3,138				2,446
General corporate expenses			30				27				93				79
Operating income:
Gas Pipeline			151				138				449				449
Midstream Gas & Liquids			196				179				630				393
General corporate expenses			(30	)			(27	)			(93	)			(79	)
Total operating income			317				290				986				763
Equity earnings			24				30				77				51
Interest accrued — third-party			(103	)			(51	)			(285	)			(155	)
Interest accrued — affiliate			—				(9	)			(1	)			(39	)
Interest capitalized			7				10				26				43
Interest income			—				5				3				16
Other income — net			9				4				10				9
Income before income taxes			254				279				816				688
Provision for income taxes			1				1				1				4
Net income			253				278				815				684
Less: Net income attributable to noncontrolling interests			5				7				16				20
Net income attributable to controlling interests		$	248			$	271			$	799			$	664
Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests		$	248			$	271			$	799			$	664
Allocation of net income to general partner and Class C units			85				216				444				564
Allocation of net income to common units		$	163			$	55			$	355			$	100
Basic and diluted net income per common unit		$	0.63			$	1.04			$	1.87			$	1.88
Weighted average number of common units outstanding			260,507,501	(a)			52,777,452				190,448,384	(a)			52,777,452

See accompanying notes.

Williams Partners L.P.
Supplemental Consolidated Balance Sheet *
(Unaudited)

		September 30,				December 31,
		2010				2009
		(Millions)
ASSETS
Current assets:
Cash and cash equivalents		$	92			$	153
Accounts receivable:
Trade			341				381
Affiliate			5				6
Inventories			160				129
Regulatory assets			63				77
Prepaid expense			41				26
Other current assets			35				49
Total current assets			737				821
Investments			1,020				593
Gross property, plant and equipment			16,365				15,976
Less accumulated depreciation			(5,592	)			(5,260	)
Property, plant and equipment — net			10,773				10,716
Regulatory assets, deferred charges and other			410				345
Total assets		$	12,940			$	12,475
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade		$	297			$	356
Affiliate			146				80
Accrued interest			110				49
Other accrued liabilities			163				136
Long-term debt due within one year			458				15
Total current liabilities			1,174				636
Long-term debt			5,765				2,981
Asset retirement obligations			461				492
Regulatory liabilities, deferred income and other			281				263
Contingent liabilities and commitments (Note 8)
Equity:
Common units (278,607,937 units outstanding at September 30, 2010 and 52,777,452 units outstanding at December 31, 2009)			6,111				1,631
General partner			(842	)			6,123
Accumulated other comprehensive income (loss)			(10	)			2
Noncontrolling interests in consolidated subsidiaries			—				347
Total equity			5,259				8,103
Total liabilities and equity		$	12,940			$	12,475

See accompanying notes.

Williams Partners L.P.
Supplemental Consolidated Statement of Changes in Equity *
(Unaudited)

		Williams Partners L.P.
														Accumulated Other
		Limited Partners								General				Comprehensive				Noncontrolling				Total
		Common				Class C				Partner				Income (Loss)				Interests				Equity
														(Millions)
Balance — January 1, 2010		$	1,631			$	—			$	6,123			$	2			$	347			$	8,103
Comprehensive income:
Net income			339				156				304				—				16				815
Other comprehensive loss:
Net unrealized change in cash flow hedges			—				—				—				(12	)			—				(12	)
Total other comprehensive loss																							(12	)
Total comprehensive income																							803
Cash distributions			(240	)			(87	)			(83	)			—				—				(410	)
Dividends paid to noncontrolling interests			—				—				—				—				(18	)			(18	)
Issuance of units (203,000,000 Class C units)			—				6,946				(6,946	)			—				—				—
Distributions to The Williams Companies, Inc. — net			—				(3,357	)			(260	)			—				—				(3,617	)
Conversion of Class C units to Common (203,000,000 units)			3,658				(3,658	)			—				—				—				—
Issuance of units due to Williams Pipeline Partners L.P. merger (13,580,485 common units)			343				—				—				—				(343	)			—
Issuance of units to public (9,250,000 common units)			380				—				—				—				—				380
Contributions from General Partner			—				—				20				—				—				20
Other			—				—				—				—				(2	)			(2	)
Balance — September 30, 2010		$	6,111			$	—			$	(842	)		$	(10	)		$	—			$	5,259

See accompanying notes.

Williams Partners L.P.
Supplemental Consolidated Statement of Cash Flows *
(Unaudited)

		Nine months ended September 30,
		2010				2009
		(Millions)
OPERATING ACTIVITIES:
Net income		$	815			$	684
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization			420				410
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			40				(74	)
Inventories			(31	)			15
Other assets and deferred charges			15				20
Accounts payable			(4	)			(39	)
Accrued liabilities			85				(48	)
Affiliates — net			67				(27	)
Other, including changes in noncurrent assets and liabilities			5				123
Net cash provided by operating activities			1,412				1,064
FINANCING ACTIVITIES:
Proceeds from long-term debt			4,179				—
Payments of long-term debt			(953	)			—
Payment of debt issuance costs			(62	)			—
Proceeds from sales of common units			380				—
General Partner contributions			20				—
Dividends paid to noncontrolling interests			(18	)			(18	)
Distributions to limited partners and general partner			(410	)			(110	)
Distributions to The Williams Companies, Inc. — net			(191	)			(190	)
Other — net			(6	)			12
Net cash provided (used) by financing activities			2,939				(306	)
INVESTING ACTIVITIES:
Purchase of Contributed Entities			(3,426	)			—
Property, plant and equipment:
Capital expenditures			(587	)			(641	)
Net proceeds from dispositions			65				1
Changes in notes receivable from parent			—				(84	)
Purchase of investments			(450	)			(123	)
Distribution received from Gulfstream Natural Gas System, L.L.C.			—				73
Other — net			(14	)			(7	)
Net cash used by investing activities			(4,412	)			(781	)
Decrease in cash and cash equivalents			(61	)			(23	)
Cash and cash equivalents at beginning of period			153				133
Cash and cash equivalents at end of period		$	92			$	110

See accompanying notes.

Williams Partners L.P.
Notes to Supplemental Consolidated Financial Statements
(Unaudited)

Note 1. Organization, Basis of Presentation, and Description of Business

Organization

     Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or similar language refer to Williams Partners L.P. and its subsidiaries.

     We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. Williams currently owns an approximate 75 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us).

     The accompanying interim supplemental consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the supplemental consolidated financial statements and notes thereto for the year ended December 31, 2009 in Exhibit 99.1 of our Form 8-K, dated December 10, 2010. The accompanying interim supplemental consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2010, results of operations for the three and nine months ended September 30, 2010 and 2009, changes in equity for the nine months ended September 30, 2010, and cash flows for the nine months ended September 30, 2010 and 2009. We eliminated all intercompany transactions and reclassified certain amounts to conform to the current classifications.

     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 supplemental consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

     On May 24, 2010, we and Williams Pipeline Partners L.P. (WMZ) entered into a merger agreement that was consummated on August 31, 2010. All of WMZ’s common units not held by its general partner were exchanged at a ratio of 0.7584 of our limited partner units for each WMZ limited partner unit, resulting in the issuance of 13,580,485 of our common units. All WMZ common and subordinated units have been extinguished and WMZ is wholly owned by us. WMZ has been delisted and is no longer publicly traded. As a result of the merger, we now own 100 percent of Northwest Pipeline GP (Northwest Pipeline).

Basis of Presentation

     On November 19, 2010, we closed the acquisition of a business represented by certain gathering and processing assets in Colorado’s Piceance Basin from Williams (the Piceance Acquisition). The Piceance Acquisition was made in exchange for consideration of $702 million in cash, approximately 1.8 million of our common units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner ownership interest. These gathering and processing assets will be reported in our Midstream Gas & Liquids (Midstream) reporting segment.

     This acquisition will be reflected in our December 31, 2010 consolidated financial statements. As the gathering and processing assets acquired in the Piceance Acquisition were acquired from affiliates of Williams at the time of the acquisition, this transaction will be accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities acquired are combined with ours at their historical amounts. Supplemental consolidated financial statements and notes which recast our historical consolidated financial statements and notes to reflect the combined historical results for all periods presented are being provided prior to our filing of Piceance Acquisition post-combination results.

Notes (Continued)

     The effect of recasting our financial statements to account for the Piceance Acquisition common control transaction increased net income $27 million and $51 million for the three and nine months ended September 30, 2010, respectively, decreased net income $1 million for the three months ended September 30, 2009 and increased net income $7 million for the nine months ended September 30, 2009. This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner. The revenues from the Piceance assets acquired reflect a cost-of-service based gathering and processing rate, which is not representative of the revenue these assets will generate in future periods. The revenues generated by these assets in future periods will be based on a new natural gas gathering agreement with a wholly owned subsidiary of Williams, entered into in conjunction with the closing of the Piceance Acquisition. We believe that the rates charged under the new agreement are reasonable as compared to those that are charged to similarly situated nonaffiliated customers.

     On February 17, 2010, we closed a transaction (the Dropdown) with our general partner, our operating company and certain subsidiaries of and including Williams, pursuant to which Williams contributed to us the ownership interests in the entities that made up its Gas Pipeline and Midstream Gas & Liquids (Midstream) businesses to the extent not already owned by us, including Williams’ limited and general partner interests in WMZ, but excluding its Canadian, Venezuelan and olefins operations, and 25.5 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream), collectively defined as the Contributed Entities.

     This contribution was made in exchange for aggregate consideration of:

	•		$3.5 billion in cash, less certain expenses incurred by us and other post-closing adjustments, which we financed by issuing $3.5 billion of senior unsecured notes (see Note 4).
	•		203 million of our Class C limited partnership units, which automatically converted into our common limited partnership units on May 10, 2010.
	•		An increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest.

     Because the acquired entities were affiliates of Williams at the time of the acquisition, this transaction is also accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired entities are combined with ours at their historical amounts. The effect of recasting our financial statements to account for the Dropdown common control transaction increased net income $223 million and $576 million for the three and nine months ended September 30, 2009, respectively. This acquisition did not impact historical earnings per limited partner unit as pre-acquisition earnings of the Contributed Entities were allocated to our general partner.

Description of Business

     Our operations are located in the United States and are organized into the following reporting segments: Gas Pipeline and Midstream.

     Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline, which own and operates a combined total of approximately 13,900 miles of pipelines with a total annual throughput of approximately 2,700 TBtu of natural gas and peak-day delivery capacity of approximately 12 MMdt of natural gas. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5 percent interest in Gulfstream, which owns an approximate 745-mile pipeline with the capacity to transport approximately 1.26 million Dth per day of natural gas.

     Midstream includes our natural gas gathering, treating and processing businesses and has a primary service area concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico and Pennsylvania. Midstream’s primary businesses—natural gas gathering, treating and processing; natural gas liquids (NGL) fractionation, storage and transportation; and oil transportation—fall within the middle of the process of taking raw natural gas and crude oil from the producing fields to the consumers.

Notes (Continued)

Note 2. Allocation of Net Income and Distributions

     The allocation of net income among our general partner, limited partners, and noncontrolling interests for the three and nine months ended September 30, 2010 and 2009, is as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
		2010				2009				2010				2009
						(Millions)
Allocation of net income to general partner:
Net income		$	253			$	278			$	815			$	684
Net income applicable to pre-partnership operations allocated to general partner			(27	)			(215	)			(214	)			(563	)
Net income applicable to noncontrolling interests			(5	)			(7	)			(16	)			(20	)
Net reimbursable costs charged directly to general partner			—				—				(4	)			1
Income subject to 2% allocation of general partner interest			221				56				581				102
General partner’s share of net income			2.0	%			2.0	%			2.0	%			2.0	%
General partner’s allocated share of net income before items directly allocable to general partner interest			4				1				11				2
Incentive distributions paid to general partner*			45				—				75				7
Charges allocated directly to general partner			—				—				4				(1	)
Pre-partnership net income allocated to general partner interest			27				215				214				563
Net income allocated to general partner		$	76			$	216			$	304			$	571
Net income		$	253			$	278			$	815			$	684
Net income allocated to general partner			76				216				304				571
Net income allocated to Class C limited partners			—				—				156				—
Net income allocated to noncontrolling interests			5				7				16				20
Net income allocated to common limited partners		$	172			$	55			$	339			$	93

     The Charges allocated directly to general partner amounts represent the net of both income and expense items. Under the terms of an omnibus agreement, we are reimbursed by our general partner for certain expense items and are required to distribute certain income items to our general partner.

     For purposes of calculating the year-to-date 2010 basic and diluted net income per common unit, the weighted average number of common units outstanding are calculated considering Class C units as common units effective April 1, 2010, and net income allocated to the Class C units prior to that date is based on the distributed earnings paid to the Class C units for first-quarter 2010. For the allocation of 2010 net income for the Supplemental Consolidated Statement of Changes in Equity, net income was allocated based on the number of days the Class C units were outstanding as Class C units during 2010.

     Total comprehensive income for the three months ended September 30, 2010 and 2009 is $230 million and $278 million, respectively, and for the nine months ended September 30, 2010 and 2009 is $803 million and $683 million, respectively. The difference between total comprehensive income and net income for all periods is due to net unrealized changes in cash flow hedges.

Notes (Continued)

     We have paid the following partnership cash distributions during 2009 and 2010 (in millions, except for per unit amounts):

																		Incentive
		Per Unit				Common				Class C								Distribution				Total Cash
Payment Date		Distribution				Units				Units				2%				Rights				Distribution
2/13/2009		$	0.6350			$	33			$	—			$	1			$	8			$	42
5/15/2009		$	0.6350			$	33			$	—			$	1			$	—			$	34
8/14/2009		$	0.6350			$	33			$	—			$	1			$	—			$	34
11/13/2009		$	0.6350			$	33			$	—			$	1			$	—			$	34
2/12/2010		$	0.6350			$	33			$	—			$	1			$	—			$	34
5/14/2010 (a)		$	0.6575			$	35			$	87			$	3			$	30			$	155
8/13/2010		$	0.6725			$	172			$	—			$	4			$	45			$	221
11/12/2010		$	0.6875			$	192			$	—			$	5			$	53			$	250

Note 3. Inventories

		September 30,				December 31,
		2010				2009
		(Millions)
Natural gas liquids		$	53			$	44
Natural gas in underground storage			36				20
Materials, supplies, and other			71				65
		$	160			$	129

Note 4. Debt and Banking Arrangements

Long-Term Debt

     As of September 30, 2010, our debt is unsecured with a weighted-average interest rate of 6.1 percent, payable through 2040. Interest rates range from 3.8 percent to 9.0 percent. 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 Facility

     In connection with the Dropdown, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (Credit Facility) with Transco and Northwest Pipeline as co-borrowers. This Credit Facility replaced our unsecured $450 million credit facility, comprised of a $200 million revolving credit facility and a $250 million term loan, which was terminated as part of the Dropdown. At the closing, we utilized $250 million of the Credit Facility to repay the outstanding term loan. During the third quarter of 2010, we had a maximum of $430 million outstanding under this credit facility, which was primarily used to purchase an additional ownership interest in Overland Pass Pipeline Company LLC (OPPL). In September 2010, the outstanding balance was reduced to zero, primarily with proceeds from our equity offering. (See Note 5.) As of September 30, 2010, no loans are outstanding under the Credit Facility. In November, 2010 we borrowed $200 million, which was partially used for the closing of the Piceance Acquisition.

Notes (Continued)

     The Credit Facility expires February 17, 2013, and may, under certain conditions, be increased by up to an additional $250 million. The full amount of the Credit Facility is available to us to the extent not otherwise utilized by Transco and Northwest Pipeline. Transco and Northwest Pipeline each have access to borrow up to $400 million under the Credit Facility to the extent not otherwise utilized by other co-borrowers. Each time funds are borrowed, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s adjusted base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. We are required to pay a commitment fee (currently 0.5 percent) based on the unused portion of the Credit Facility. The applicable margin and the commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. The 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. Significant financial covenants under the Credit Facility include:

	•		Our ratio of debt to EBITDA (each as defined in the Credit Facility) must be no greater than 5 to 1.
	•		The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 55 percent for Transco and Northwest Pipeline.

Each of the above ratios are tested at the end of each fiscal quarter, and the debt to EBITDA ratio is measured on a rolling four-quarter basis (with the first full year measured on an annualized basis). At September 30, 2010, we are in compliance with these financial covenants.

     The Credit Facility includes customary events of default. If an event of default with respect to a borrower occurs under the Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility and exercise other rights and remedies.

Issuances

     In connection with the Dropdown, we issued $3.5 billion face value of senior unsecured notes as follows:

		(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

     Prior to the issuance of this debt, we entered into forward starting interest rate swaps to hedge against variability in interest rates on a portion of the anticipated debt issuance. Upon the issuance of the debt, these instruments were terminated, which resulted in a payment of $7 million. This amount has been recorded in accumulated other comprehensive income (loss) (AOCI) and is being amortized over the term of the related debt.

     As part of the issuance of the $3.5 billion unsecured notes, we entered into registration rights agreements with the initial purchasers of the notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in June 2010 and completed in July 2010.

Offering of Senior Notes

     In November 2010, we completed a public offering of $600 million of our 4.125 percent senior notes due 2020 at a price of 99.991 percent of par. We used the proceeds from the offering to fund a portion of the cash consideration paid in the Piceance Acquisition (See Note 1).

Notes (Continued)

Note 5. Partners’ Capital

     On August 31, 2010, the WMZ unitholders approved the merger between WMZ and us (see Note 1). As a result of the merger, effective September 1, 2010, WMZ unitholders, other than its general partner, received 0.7584 WPZ common units for each WMZ common unit they owned at the effective time of the merger, for a total issuance of 13,580,485 common units.

     On September 28, 2010, we completed an equity issuance of 9,250,000 common units representing limited partner interests in us at a price of $42.40 per unit. The proceeds of approximately $380 million, net of the underwriters’ discount and fees of approximately $12 million were used to repay borrowings incurred to fund a portion of our additional $424 million investment in OPPL. This additional investment increases our ownership interest in OPPL to 50 percent, which is included in our Midstream segment and is accounted for using the equity method of accounting.

     On October 8, 2010, we sold an additional 1,387,500 common units to the underwriters upon the underwriters’ exercise of their option to purchase additional common units pursuant to our common unit offering in September 2010. The proceeds of $57 million, net of the underwriters’ discount and fees of approximately $2 million were used for general corporate purposes.

Note 6. 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 measurements primarily consist of financial instruments that are exchange traded.
	•		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. The instruments included in our Level 2 measurements consist primarily of over-the-counter instruments such as natural gas forward contracts and swaps.
	•		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 measurements consist of instruments that are valued utilizing 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.

Notes (Continued)

     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.

		September 30, 2010																December 31, 2009
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
						(Millions)																(Millions)
Assets:
ARO Trust Investments (see Note 7)		$	37			$	—			$	—			$	37			$	22			$	—			$	—			$	22
Energy derivatives			—				1				1				2				—				—				2				2
Total assets		$	37			$	1			$	1			$	39			$	22			$	—			$	2			$	24
Liabilities:
Energy derivatives		$	—			$	6			$	2			$	8			$	—			$	—			$	2			$	2
Total liabilities		$	—			$	6			$	2			$	8			$	—			$	—			$	2			$	2

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

     The determination of fair value 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.

     Forward and swap contracts included in Level 2 are valued using an income approach including present value techniques. Significant inputs into our Level 2 valuations include commodity prices and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. 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.

     The tenure of our derivatives portfolio is relatively short with all of our derivatives expiring by December 31, 2010. 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. These instruments are valued with a present value technique 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. Certain inputs into the model are generally observable, such as interest rates, whereas natural gas liquids commodity prices are considered unobservable. The instruments included in Level 3 consist primarily of natural gas liquids swaps and forward contracts.

     Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the period ended September 30, 2010. The following tables present a reconciliation of changes in the fair value of our net energy derivatives classified as Level 3 in the fair value hierarchy.

Notes (Continued)

Level 3 Fair Value Measurements Using Significant Unobservable Inputs

		Net Energy Derivatives								Net Energy Derivatives
		Three months ended								Nine months ended
		September 30,								September 30,
		2010				2009				2010				2009
		(Millions)								(Millions)
Beginning balance		$	20			$	5			$	—			$	1
Realized and unrealized gains (losses):
Included in net income			8				—				10				4
Included in other comprehensive income (loss)			(20	)			—				1				—
Purchases, issuances, and settlements			(9	)			(2	)			(12	)			(2	)
Transfers into Level 3			—				—				—				—
Transfers out of Level 3			—				—				—				—
Ending balance		$	(1	)		$	3			$	(1	)		$	3
.
Unrealized gains (losses) included in net income relating to instruments still held at September 30		$	—			$	—			$	—			$	3

     Realized and unrealized gains (losses) included in net income for the above periods are reported in revenues in our Supplemental Consolidated Statement of Income.

     For the periods ended September 30, 2010 and 2009, there were no assets or liabilities measured at fair value on a nonrecurring basis.

Note 7. Financial Instruments, Derivatives and Concentrations 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: The carrying amounts reported in the Supplemental Consolidated Balance Sheet approximate fair value due to the short-term maturity of these instruments.

     ARO Trust Investments: 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. The ARO Trust invests in a portfolio of mutual funds that are reported at fair value in regulatory assets, deferred charges and other in the Supplemental 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 valued using indicative period-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 September 30, 2010 and December 31, 2009, approximately 100 percent and 91 percent, respectively, of our long-term debt was publicly traded. (See Note 4.)

     Other: Includes current and noncurrent notes receivable.

     Energy derivatives: Energy derivatives include forwards and swaps. These are carried at fair value in other current assets and other accrued liabilities in the Supplemental Consolidated Balance Sheet. See Note 6 for discussion of valuation of our energy derivatives.

Notes (Continued)

Carrying amounts and fair values of our financial instruments

		September 30, 2010								December 31, 2009
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
						(Millions)
Asset (Liability)
Cash and cash equivalents		$	92			$	92			$	153			$	153
ARO Trust Investments			37				37				22				22
Long-term debt, including current portion			(6,223	)			(6,958	)			(2,996	)			(3,194	)
Other			—				—				3				3
Net energy derivatives:
Energy commodity cash flow hedges — affiliate			(7	)			(7	)			(2	)			(2	)
Other energy derivatives			1				1				2				2

Energy Commodity Derivatives

   Risk management activities

     We are exposed to market risk from changes in energy commodity prices within our operations. We may utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases of natural gas and forecasted sales of 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 sell NGL volumes received as compensation for certain processing services at different locations throughout the United States. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs. 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 market prices, we may enter into NGL or natural gas swap agreements, financial or physical forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas. 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.

   Volumes

     Our energy commodity derivatives are comprised of both contracts to purchase commodities (long positions) and contracts to sell commodities (short positions). Derivative transactions are categorized into two 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.

     The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of September 30, 2010. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLs are presented in gallons.

Derivative Notional Volumes

Measurement

Fixed Price

Basis

Designated as Hedging Instruments

Midstream   Risk Management

MMBtu

6,365,000

4,305,000

Midstream   Risk Management

Gallons

(69,636,000

)

Not Designated as Hedging Instruments

Midstream   Risk Management

Gallons

(3,360,000

)

Notes (Continued)

   Fair values and gains (losses)

     The following table presents the fair value of energy commodity derivatives. Our derivatives are included in other current assets and other accrued liabilities in our Supplemental Consolidated Balance Sheet. 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 by December 31, 2010.

		September 30, 2010								December 31, 2009
		Assets				Liabilities				Assets				Liabilities
		(Millions)								(Millions)
Designated as hedging instruments		$	1			$	8			$	—			$	2
Not designated as hedging instruments			1				—				2				—
Total derivatives		$	2			$	8			$	2			$	2

     The following table presents gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.

		Three months ended								Nine months ended
		September 30,								September 30,
		2010				2009				2010				2009				Classification
		(Millions)								(Millions)
Net loss recognized in other comprehensive income (effective portion)		$	(20	)		$	—			$	(6	)		$	—			AOCI
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)		$	4			$	—			$	—			$	—			Revenues
Gain (loss) recognized in income (ineffective portion)		$	—			$	—			$	—			$	—			Revenues

     There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness or as a result of reclassifications to earnings following the discontinuance of any cash flow hedges. As of September 30, 2010, we have hedged portions of future cash flows associated with anticipated NGL sales and natural gas purchases through December 31, 2010. Based on recorded values at September 30, 2010, net losses to be reclassified into earnings by December 31, 2010, are $7 million. These recorded values are based on market prices of the commodities as of September 30, 2010. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized by December 31, 2010, will likely differ from these values. These gains or losses will offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

     We recognized losses of less than $1 million and gains of $3 million in revenues for the nine months ended September 30, 2010, and 2009, respectively, on our energy commodity derivatives not designated as hedging instruments.

     The cash flow impact of our derivative activities is presented in the Supplemental Consolidated Statement of Cash Flows as changes in other assets and deferred charges and changes in accrued liabilities.

   Credit-risk-related features

     Our financial swap contracts are with Williams Gas Marketing, Inc., and the derivative contracts not designated as cash flow hedging instruments are primarily physical commodity sale contracts. These agreements do not contain any provisions that require us to post collateral related to net liability positions.

Notes (Continued)

Guarantees

     In addition to the guarantees and payment obligations discussed in Note 8, 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.

     At September 30, 2010, 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.

Note 8. Contingent Liabilities

Environmental Matters

     Since 1989, Transco has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At September 30, 2010, we had accrued liabilities of $4 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, Northwest Pipeline 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. Currently, Northwest Pipeline is conducting additional remediation activities for mercury and other constituents at certain sites to comply with Washington’s current environmental standards. At September 30, 2010, we have accrued liabilities of $7 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

     In March 2008, the EPA issued a new air quality standard for ground level ozone. 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 the fourth quarter 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 our operations, causing us to incur additional capital expenditures to comply. At this time we are unable to estimate the cost that may be required to meet these regulations. We expect that costs associated with these compliance efforts for our interstate gas pipelines will be recoverable through their rates.

Notes (Continued)

     In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO₂) National Ambient Air Quality Standard. The effective date of the new NO₂ standard was April 12, 2010. This new standard is subject to numerous challenges in federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

     In September 2007, the EPA requested, and Transco 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 notices of violations (NOVs) alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted its response denying the allegations in June 2008. In July 2009, the EPA requested additional information pertaining to these compressor stations and in August 2009, Transco submitted the requested information. On August 20, 2010, the EPA requested, and Transco later provided, similar information for a compressor station in Maryland.

     In April 2010, we entered into a global settlement with the New Mexico Environmental Department’s Air Quality Bureau (NMED) to resolve allegations of various air emissions violations at certain of our facilities. The settlement resolves NOVs dating back to 2007 and includes a $400,000 penalty, as well as environmental projects totaling $1.35 million.

     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.

     We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2010, we have accrued liabilities totaling $6 million for these costs.

   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 any incremental amount cannot be reasonably estimated at this time.

Rate Matters

     On August 31, 2006, Transco submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing (Docket No. RP06-569) principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.

     The one issue reserved for litigation or further settlement relates to Transco’s proposal to change the design of the rates for service under one of its storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties have sought rehearing of the FERC’s order.

Safety Matters

     The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration rules implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, including more frequent inspections and other safeguards in areas where the potential consequences of pipeline accidents pose the greatest risk to people and property. In accordance with the final rule, Transco and Northwest Pipeline developed Integrity Management Plans, identified high consequence areas, completed baseline assessment plans, and are on schedule to complete the required assessments within specified timeframes. Currently, Transco and Northwest Pipeline estimate that the cost to perform required assessments and remediation will be primarily capital and range between $120 and $180 million, and between $80 and $95 million,

Notes (Continued)

respectively, over the remaining assessment period of 2010 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through their respective rates.

Other Legal Matters

   Will Price (formerly Quinque)

     In 2001, we were named, along with other subsidiaries of Williams, 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 within our Midstream business. 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. On March 31, 2010, the court entered an order denying plaintiffs’ motion for reconsideration and as a result, there are no class action allegations remaining in the case.

   Other

     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.

Note 9. Segment Disclosures

     Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge.

Performance Measurement

     We currently evaluate segment operating performance based on segment profit from operations, which includes segment revenues from external and internal customers, segment costs and expenses, and equity earnings. 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:

	•		Gas Pipeline — depreciation and operation and maintenance expenses;
	•		Midstream — commodity purchases (primarily for NGL and crude marketing, shrink and fuel), depreciation, and operation and maintenance expenses.

Notes (Continued)

     The following table reflects the reconciliation of segment revenues to revenues and segment profit to operating income as reported in the Supplemental Consolidated Statement of Income.

		Gas Pipeline				Midstream				Eliminations				Total
						(Millions)
Three months ended September 30, 2010*
Segment revenues:
External		$	408			$	919			$	—			$	1,327
Internal			1				—				(1	)			—
Total revenues		$	409			$	919			$	(1	)		$	1,327
Segment profit		$	161			$	210			$	—			$	371
Less equity earnings			10				14				—				24
Segment operating income		$	151			$	196			$	—				347
General corporate expenses															(30	)
Total operating income														$	317
Three months ended September 30, 2009*
Segment revenues:
External		$	380			$	821			$	—			$	1,201
Internal			—				1				(1	)			—
Total revenues		$	380			$	822			$	(1	)		$	1,201
Segment profit		$	148			$	199			$	—			$	347
Less equity earnings			10				20				—				30
Segment operating income		$	138			$	179			$	—				317
General corporate expenses															(27	)
Total operating income														$	290

		Gas Pipeline				Midstream				Eliminations				Total
						(Millions)
Nine months ended September 30, 2010*
Segment revenues:
External		$	1,195			$	3,022			$	—			$	4,217
Internal			1				—				(1	)			—
Total revenues		$	1,196			$	3,022			$	(1	)		$	4,217
Segment profit		$	478			$	678			$	—			$	1,156
Less equity earnings			29				48				—				77
Segment operating income		$	449			$	630			$	—				1,079
General corporate expenses															(93	)
Total operating income														$	986
Nine months ended September 30, 2009*
Segment revenues:
External		$	1,202			$	2,086			$	—			$	3,288
Internal			—				6				(6	)			—
Total revenues		$	1,202			$	2,092			$	(6	)		$	3,288
Segment profit		$	475			$	418			$	—			$	893
Less equity earnings			26				25				—				51
Segment operating income		$	449			$	393			$	—				842
General corporate expenses															(79	)
Total operating income														$	763

Item 2

Supplemental Management’s Discussion and Analysis of
Financial Condition and Results of Operations

     Please read the following discussion of our financial condition and results of operations in conjunction with the supplemental consolidated financial statements and related notes included elsewhere herein. This Supplemental Management’s Discussion and Analysis of Financial Condition and Results of Operations has only been changed from its original presentation to reflect the combined historical results of the Partnership and the Piceance Acquisition discussed below for all periods presented. We have not otherwise updated for activities or events occurring after the date these items were originally presented. For example, we have not updated this discussion and analysis related to the November 2010 borrowings entered into for the Piceance Acquisition, which included Credit Facility borrowings and a public offering of $600 million of our 4.125 percent senior notes due 2020.

Recent Developments

Midstream Piceance Acquisition

     On November 19, 2010, we closed the acquisition of a business represented by certain gathering and processing assets in Colorado’s Piceance Basin from a subsidiary of The Williams Companies, Inc. (Williams) (the Piceance Acquisition). The Piceance Acquisition was made in exchange for consideration of $702 million in cash, approximately 1.8 million of our common units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner ownership interest. These gathering and processing assets will be reported in our Midstream Gas & Liquids (Midstream) reporting segment.

     This acquisition will be reflected in our December 31, 2010 consolidated financial statements. Because the gathering and processing assets acquired in the Piceance Acquisition were acquired from affiliates of Williams at the time of the acquisition, this transaction will be accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities acquired are combined with ours at their historical amounts. Accordingly, we have revised the following management’s discussion and analysis in conjunction with our issuance of the supplemental consolidated financial statements and notes included elsewhere herein. Supplemental consolidated financial statements and notes which recast our historical supplemental consolidated financial statements and notes to reflect the combined historical results for all periods presented are being provided prior to our filing of post-combination results.

     The effect of recasting our financial statements to account for this common control transaction increased net income $27 million and $51 million for the three and nine months ended September 30, 2010, respectively, reduced net income $1 million for the three months ended September 30, 2009 and increased net income $7 million for the nine months ended September 30, 2009. The revenues from the Piceance assets acquired reflect a cost-of-service based gathering and processing rate, which is not representative of the revenue these assets will generate in future periods. The revenues generated by these assets in future periods will be based on a new natural gas gathering agreement with a wholly owned subsidiary of Williams entered into in conjunction with the closing of the Piceance Acquisition. We believe that the rates charged under the new agreement are reasonable as compared to those that are charged to similarly situated nonaffiliated customers.

The Dropdown

     On February 17, 2010, we closed a transaction with our general partner, our operating company, The Williams Companies, Inc. (Williams) and certain subsidiaries of Williams, pursuant to which Williams contributed to us the ownership interests in the entities that made up Williams’ Gas Pipeline and Midstream businesses to the extent not already owned by us, including Williams’ limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding Williams’ Canadian, Venezuelan, and olefin operations and 25.5 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream). Such entities are hereafter referred to as the “Contributed Entities.” This contribution was made in exchange for aggregate consideration of:

Supplemental Management’s Discussion and Analysis (Continued)

	•		$3.5 billion in cash, less certain expenses incurred by us and other post-closing adjustments, relating to our acquisition of the Contributed Entities. This cash consideration was financed through the private issuance of $3.5 billion of senior unsecured notes with net proceeds of $3.466 billion.
	•		203 million Class C units, which received a prorated initial distribution and were then converted to regular common units on May 10, 2010.
	•		An increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest.

     The transactions described in the preceding paragraph are referred to as the “Dropdown.”

WMZ Merger

     On May 24, 2010, we entered into a merger agreement with WMZ (Merger Agreement) providing for the merger of WMZ into us (the Merger). On August 31, 2010, the WMZ unitholders approved the proposed merger between the two master limited partnerships and the merger has been completed. All of WMZ’s common units not held by its general partner were exchanged at a ratio of 0.7584 of our units for each WMZ unit. We now own a 100 percent interest in Northwest Pipeline GP (Northwest Pipeline), and Williams holds an approximate 77 percent interest in us, comprised of an approximate 75 percent limited partner interest and all of our 2 percent general partner interest.

Credit Facility

     In connection with the Dropdown, we entered into a new $1.75 billion senior unsecured revolving three-year credit facility (Credit Facility) with Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline, as co-borrowers with borrowing sublimits of $400 million each, and Citibank, N.A., as administrative agent, and other lenders named therein. The Credit Facility replaced our previous $450 million senior unsecured credit agreement. At the closing of the Dropdown, we borrowed $250 million under the Credit Facility to repay the term loan outstanding under our previously existing credit facility. As of September 30, 2010, no loans are outstanding under the Credit Facility.

Overland Pass Pipeline

     In July 2010, we notified our partner in the Overland Pass Pipeline Company LLC (OPPL) of our election to exercise our option to purchase an additional ownership interest, which provides us with a 50 percent ownership interest in OPPL, for approximately $424 million. This transaction was completed on September 9, 2010, and funded primarily with proceeds from our credit facility. (See Results of Operations — Segments, Midstream Gas & Liquids.) Additionally, during September 2010, we completed an equity offering resulting in net proceeds of $380 million, which was used to reduce the borrowing on the credit facility. (See Note 5 of Notes to Supplemental Consolidated Financial Statements.)

Overview

     We manage our business and analyze our results of operations on a segment basis. Our operations are divided into two business segments: Gas Pipeline and Midstream.

•

Gas Pipeline includes Transco and Northwest Pipeline, which own and operate a combined total of approximately 13,900 miles of pipelines with a total annual throughput of approximately 2,700 trillion British thermal units (TBtu) of natural gas and peak-day delivery capacity of approximately 12 million dekatherms (MMdt) of natural gas. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5 percent interest in Gulfstream, which owns an approximate 745-mile pipeline with the capacity to transport approximately 1.26 MMdt per day of natural gas.

•

Midstream includes natural gas gathering, processing and treating facilities, and crude oil gathering and transportation facilities with primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, and Pennsylvania.

Supplemental Management’s Discussion and Analysis (Continued)

Company Outlook

     We believe we are well positioned to continue to execute on our 2010 business plan and to capture attractive growth opportunities. While the economic environment in the latter half of 2009 and first quarter of 2010 improved compared to conditions earlier in 2009, this trend has moderated in the second and third quarters of 2010 as global economies continue to struggle. However, energy commodity price indicators continue to reflect an expectation of growth and increasing demand. Given the potential volatility of these measures, it is reasonably possible that the economy could worsen and/or energy commodity prices could further decline, negatively impacting future operating results and increasing the risk of nonperformance of counterparties or impairments of long-lived assets.

     As a result of the Dropdown, we believe we are better positioned to drive additional growth and pursue value-adding growth strategies. Additionally, the Dropdown enhances our access to capital markets.

     We continue to 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;
	•		Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

     Potential risks and 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 volumes from third parties served by our midstream business;
	•		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 $75 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 ample liquidity from cash and cash equivalents and unused revolving credit facility capacity.

Fair Value Measurements

     Certain of our energy derivative assets and energy derivative liabilities 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 September 30, 2010, 50 percent of our energy derivative assets and 25 percent of our energy derivative 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 energy derivative assets and our energy derivative 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 energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net

Supplemental Management’s Discussion and Analysis (Continued)

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 September 30, 2010, the credit reserve is significantly less than $1 million on both our net derivative assets and 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.

     Our entire derivatives portfolio expires by December 31, 2010. 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.

     The instruments included in Level 3 at September 30, 2010, consist primarily of natural gas liquids swaps and forward contracts used to manage the price risk of future natural gas liquid sales. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices.

     Our financial swap contracts are with Williams Gas Marketing, Inc., and the derivative contracts not designated as cash flow hedging instruments are primarily physical commodity sale contracts. These agreements do not contain any provisions that require us to post collateral related to net liability positions.

Supplemental 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, 2010, compared to the three and nine months ended September 30, 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

		Three months ended																Nine months ended
		September 30,																September 30,
		2010				2009				$ Change*				% Change*				2010				2009				$ Change*				% Change*
		(Millions)																(Millions)
Revenues		$	1,327			$	1,201				+ 126				+10	%		$	4,217			$	3,288				+ 929				+28	%
Costs and expenses:
Costs and operating expenses			923				810				- 113				-14	%			2,958				2,225				- 733				-33	%
Selling, general and administrative expenses			70				75				+ 5				+7	%			202				221				+ 19				+9	%
Other income — net			(13	)			(1	)			+ 12			NM					(22	)			—				+ 22			NM
General corporate expenses			30				27				-3				-11	%			93				79				- 14				-18	%
Total costs and expenses			1,010				911												3,231				2,525
Operating income			317				290												986				763
Equity earnings			24				30				-6				-20	%			77				51				+ 26				+51	%
Interest accrued — net			(96	)			(50	)			- 46				-92	%			(260	)			(151	)			- 109				-72	%
Interest income			—				5				-5				-100	%			3				16				- 13				-81	%
Other income — net			9				4				+ 5				+125	%			10				9				+ 1				+11	%
Income before income taxes			254				279												816				688
Provision for income taxes			1				1				—				—				1				4				+ 3				+75	%
Net Income			253				278												815				684
Less: Net income attributable to noncontrolling interests			5				7				+ 2				+29	%			16				20				+ 4				+20	%
Net income attributable to controlling interests		$	248			$	271											$	799			$	664