Exhibit 99.1

Item 6. Supplemental Selected Financial Data

     The following financial data at December 31, 2009 and 2008 and for each of the three years in the period ended December 31, 2009 is derived from our supplemental audited financial statements included in Item 8 of this Exhibit 99.1 and should be read in conjunction with the other financial information included in this Exhibit 99.1. The following financial data at December 31, 2007, 2006, and 2005 and for the years ended December 31, 2006 and 2005 has been prepared from our accounting records. As described in Item 8.01 of this Exhibit 99.1, the following financial data at December 31, 2009, 2008 and 2007, and for each of the three years in the period ended December 31, 2009, has been retrospectively adjusted as a result of the Piceance Acquisition. For a description of the Piceance Acquisition, please read Supplemental Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments – Midstream Piceance Acquisition. However, the following financial data at December 31, 2005 and for each of the years ended December 31, 2006 and 2005 has not been retrospectively adjusted for the Piceance Acquisition as the effect of such an adjustment would not be material to these periods and the detailed information necessary to calculate the exact amount of such an adjustment is not readily available.

		2009				2008				2007				2006				2005
						(Millions, except per-unit amounts)
Revenues		$	4,602			$	5,847			$	5,684			$	4,711			$	3,994
Income before cumulative effect of change in accounting principle			1,036				2,108				1,462				822				553
Net income			1,036				2,108				1,462				822				552
Net income attributable to controlling interests			1,009				2,083				1,462				822				552
Income before cumulative effect of change in accounting principle per limited partner unit:
Common unit		$	2.88			$	3.08			$	1.99			$	1.73			$	.49	(1)
Subordinated unit			N/A				N/A			$	1.99			$	1.73			$	.49	(1)
Net income per limited partner unit:
Common unit		$	2.88			$	3.08			$	1.99			$	1.73			$	.44	(1)
Subordinated unit			N/A				N/A			$	1.99			$	1.73			$	.44	(1)
Total assets at December 31		$	12,475			$	12,167			$	11,419			$	10,499			$	9,473
Short-term notes payable and long-term debt due within one year at December 31			15				—				75				253				8
Long-term debt at December 31 (2)			2,981				2,971				2,821				2,386				1,513
Total equity at December 31			8,103				7,867				6,215				5,670				5,991
Cash dividends declared per unit		$	2.540			$	2.435			$	2.045			$	1.605			$	0.1484

Item 7.		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. Except for the WMZ Merger discussion below, we have not otherwise updated for activities or events occurring after the date these items were originally presented, which included the effects of the Dropdown discussed below. See Note 21. Subsequent Events of the supplemental consolidated financial statements and related notes included elsewhere herein for a discussion of certain subsequent events not reflected in the following discussion and analysis. Included in this subsequent events note is information about borrowings entered into related to the completion of the Piceance Acquisition.

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.

     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 supplemental management’s discussion and analysis in conjunction with our issuance of the supplemental consolidated financial statements and notes included elsewhere herein. The supplemental consolidated financial statements and notes, which recast our historical consolidated financial statements and notes to reflect the combined historical results for all prior periods presented are being provided prior to our filing of Piceance Acquisition post-combination results.

     The effect of recasting our financial statements to account for this common control transaction increased net income $5 million, $6 million and $13 million for 2009, 2008 and 2007, respectively. 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, Williams and certain subsidiaries of Williams, pursuant to which Williams contributed to us the ownership interests in the entities that make 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 contributed entities are hereafter referred to 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 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.”

     After the consummation of the Dropdown, our operations are divided into two business segments: Gas Pipeline and Midstream. All of the operations we conducted prior to the Dropdown are reported within the Midstream segment. The Contributed Entities’ business activities are included in our two business segments as follows:

	•		Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (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 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 the natural gas gathering, processing and treating facilities located primarily in the Rocky Mountain and Gulf Coast regions of the United States and natural gas and crude oil gathering and transportation facilities in the Gulf Coast region of the United States.

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, 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.

New Credit Facility

     In connection with the Dropdown, we entered into a new $1.75 billion senior unsecured revolving three-year credit facility with 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 (New Credit Facility). The New Credit Facility replaced our previous $450 million senior unsecured credit agreement. At the closing of the Dropdown, we borrowed $250 million under the New Credit Facility to repay the term loan outstanding under our previously existing credit facility.

Overview of 2009

     The following discussion of our results of operations reflects our business which has been recast to include the impacts of the Dropdown and the Piceance Acquisition discussed above and as reflected in the supplemental consolidated financial statements and related notes included elsewhere herein.

     Our operating results throughout the second half of 2009 demonstrated significant continued improvement from the difficult circumstances experienced during the last quarter of 2008 and the first half of 2009 when low NGL commodity prices and hurricane-related damages significantly decreased the profitability of our gathering and processing businesses. These circumstances resulted in lower operating income in 2009 compared to 2008. During 2009, Williams provided us with significant, additional support, which assisted us in maintaining a higher level of cash retention and a stronger overall liquidity position. Williams waived its incentive distribution rights (IDRs) related to the 2009 distribution periods. These waived IDRs represented approximately $29.0 million, on an annual basis. In addition, our omnibus agreement with Williams was amended to increase the aggregate amount of the

credit we could receive related to certain general and administrative expenses for 2009. Williams’ additional support during 2009 combined with the improved commodity environment in the second half of 2009 allowed us to maintain our prior per-unit level of cash distributions throughout 2009.

Critical Accounting Policies and Estimates

     Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. The selection of these policies has been discussed with the audit committee of the board of directors of our general partner. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.

Impairments of Long-Lived Assets and Investments

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

     In addition to those long-lived assets for which impairment charges were recorded (please read Note 5, Asset Sales, Impairments and Other Accruals, of our Notes to Supplemental Consolidated Financial Statements included elsewhere herein), certain others were reviewed for which no impairment was required. These reviews included certain of Midstream’s Gulf Coast assets, which were evaluated for impairment utilizing judgments and assumptions including future volumes, fees and margins. These underlying variables are subjective and susceptible to change. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the supplemental consolidated financial statements. Based on our evaluation, we are not currently aware of any significant assets that are approaching impairment thresholds.

Contingent Liabilities

     We record liabilities for estimated loss contingencies, including environmental matters, when we determine that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. Please read Note 19, Contingent Liabilities and Commitments, in our Notes to Supplemental Consolidated Financial Statements included elsewhere herein.

Results of Operations

Consolidated Overview

     The following table and discussion summarize our consolidated results of operations for the three years ended December 31, 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion and relate to the segment tables in Note 20, Segment Disclosures, in our Notes to Supplemental Consolidated Financial Statements included elsewhere herein.

		Years Ended December 31,
						% Change								% Change
						from								from
		2009				2008(1)				2008				2007(1)				2007
										(Millions)
Revenues		$	4,602				(21	)%		$	5,847				+3	%		$	5,684
Costs and expenses:
Costs and operating expenses			3,100				+26	%			4,206				(7	)%			3,936
Selling, general and administrative expense			300				(6	)%			282				(4	)%			271
Other (income) expense – net			(34	)		NM					10			NM					(20	)
General corporate expenses			109				(15	)%			95				+6	%			101
Total costs and expenses			3,475				+24	%			4,593				(7	)%			4,288
Operating income			1,127				(10	)%			1,254				(10	)%			1,396
Equity earnings			81				+7	%			76				(4	)%			79
Interest accrued – net			(201	)			+4	%			(209	)			(4	)%			(201	)
Interest income			20				(20	)%			25				—				25
Other income – net			13				+30	%			10				(47	)%			19
Income before income taxes			1,040				(10	)%			1,156				(12	)%			1,318
Provision (benefit) for income taxes			4			NM					(952	)		NM					(144	)
Net income			1,036				(51	)%			2,108				+44	%			1,462
Less: Net income attributable to noncontrolling interests			27				(8	)%			25			NM					—
Net income attributable to controlling interests		$	1,009				(52	)%		$	2,083				+42	%		$	1,462

  2009 vs. 2008

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

     Revenues decreased due primarily to lower commodity prices for NGL and crude oil sales and lower marketing revenues at Midstream.

     Costs and operating expenses decreased primarily due to lower commodity prices for NGL and crude oil marketing purchases and natural gas associated with NGL production at Midstream.

     Selling, general and administrative expenses increased due primarily to higher employee-related expenses.

     Other (income) expense — net within operating income in 2009 includes a $40 million gain on the sale of our Cameron Meadows NGL processing plant at Midstream.

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

	•		Gain of $10 million on the sale of certain south Texas assets at Gas Pipeline;
	•		Income of $17 million resulting from involuntary conversion gains at Midstream;
	•		Expense of $23 million related to project development costs at Gas Pipeline;
	•		Expense of $17 million related to impairments and other asset writedowns at Midstream.

     General corporate expenses allocated from Williams increased due primarily to higher Williams’ employee-related expenses.

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

     Provision (benefit) for income taxes changed unfavorably due primarily to the impact in 2008 of Transco’s conversion to a single member limited liability company. As a result of that conversion, all of Transco’s deferred taxes were eliminated through income, and Transco no longer provided for income taxes. Please read Note 7, Provision (Benefit) for Income Taxes, of our Notes to Supplemental Consolidated Financial Statements included elsewhere herein for a reconciliation of the effective tax rates compared to the federal statutory rate for both years and a discussion of the conversion of Transco to a single member limited liability company.

  2008 vs. 2007

     Our income before income taxes for 2008 decreased compared to 2007. These results were influenced considerably by favorable results in the first three quarters of the year, followed by a sharp decline in the fourth quarter due to a rapid decline in energy commodity prices.

     Revenues increased slightly due primarily to Midstream’s higher commodity sales prices and fee revenues, partially offset by lower volumes. In addition, Gas Pipeline’s transportation revenue increased following implementation of Transco’s new rates.

     Costs and operating expenses increased due primarily to Midstream’s higher natural gas costs associated with our NGL production businesses and higher repair costs, depreciation expense and employee-related expenses.

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

	•		Income of $18 million associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral;
	•		Income of $17 million associated with a change in estimate related to a regulatory liability at Northwest Pipeline;
	•		Income of $12 million related to a favorable litigation outcome at Midstream;
	•		Expense of $18 million related to impairments of offshore assets and other asset writedowns at Midstream.

     The decrease in operating income reflects decreased operating income at Midstream primarily due to a sharp decline in energy commodity prices in the latter part of 2008, combined with other changes previously discussed.

     Provision (benefit) for income taxes changed favorably due primarily to impacts in 2008 and 2007 of the conversion of Transco and Northwest Pipeline to single member limited liability companies on December 31, 2008 and October 1, 2007, respectively. As a result of the conversion, all deferred taxes were eliminated through income, and Transco and Northwest Pipeline no longer provided for income taxes. Please read Note 7, Provision (Benefit) for Income Taxes, of our Notes to Supplemental Consolidated Financial Statements included elsewhere herein for a reconciliation of the effective tax rates compared to the federal statutory rate for both years and a discussion of the conversion of Transco and Northwest Pipeline to single member limited liability companies.

     Net income attributable to noncontrolling interests increased in 2008 due to WMZ’s initial public offering.

Results of Operations — Segment

     In conjunction with the impacts of the Dropdown discussed above, we are now organized into Gas Pipeline and Midstream segments. Our management evaluates performance based on segment profit from operations.

Gas Pipeline

Overview

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

     Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission (FERC) and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

  Gas Pipeline master limited partnership

     At December 31, 2009, we own approximately 47.7 percent of WMZ, including 100 percent of the general partner and incentive distribution rights. Considering the presumption of control of the general partner, we consolidate WMZ within our Gas Pipeline segment. Gas Pipeline’s segment profit includes 100 percent of WMZ’s segment profit.

     Significant events of 2009 include:

Completed Expansion Projects

  Gulfstream Phase IV

     In September 2007, our 24.5 percent-owned equity investee, Gulfstream, received FERC approval to construct 17.8 miles of 20-inch pipeline and to install a new compressor facility. The pipeline expansion was placed into service in the fourth quarter of 2008, and the compressor facility was placed into service in January 2009. The expansion increased capacity by 155 Mdt/d. Gulfstream’s cost of this project was $190 million.

  Sentinel

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

  Colorado Hub Connection

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

Outlook for 2010

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

Year-Over-Year Operating Results

		Years Ended December 31,
		2009				2008				2007
						(Millions)
Segment revenues		$	1,591			$	1,637			$	1,623
Segment profit		$	635			$	661			$	649

  2009 vs. 2008

     Segment revenues decreased primarily due to a $53 million decrease in revenues from lower transportation imbalance settlements in 2009 compared to 2008 (offset in costs and operating expenses), partially offset by a $17 million increase in other service revenues and expansion projects placed into service by Transco.

     Costs and operating expenses decreased $27 million, or 3 percent, primarily due to a $53 million decrease in costs associated with lower transportation imbalance settlements in 2009 compared to 2008 (offset in segment revenues) and $11 million of income from an adjustment of state franchise taxes. Partially offsetting these decreases is a $13 million increase in depreciation expense due primarily to projects placed into service, a $10 million increase in transportation-related fuel expense resulting from less favorable recovery from customers due to pricing differences, and $7 million higher employee-related expenses.

     Selling, general and administrative expenses increased $6 million, or 4 percent, primarily due to an increase in pension expense.

     Other (income) expense — net reflects the absence of a $10 million gain on the sale of certain south Texas assets and a $9 million gain on the sale of excess inventory gas, both of which were recorded by Transco in 2008. Partially offsetting these unfavorable changes was $16 million lower project development costs in 2009.

     Segment profit decreased primarily due to the previously described changes, partially offset by higher equity earnings from Gulfstream.

  2008 vs. 2007

     Segment revenues increased primarily due to a $52 million increase in transportation revenues resulting primarily from Transco’s new rates, which were approved by the FERC as part of a general rate case and became effective March 2007, and expansion projects that Transco placed into service in the fourth quarter of 2007. In addition, segment revenues increased $28 million due to transportation imbalance settlements (offset in costs and operating expenses). Partially offsetting these increases is the absence of $59 million associated with a 2007 sale of excess inventory gas (offset in costs and operating expenses).

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

     Other (income) expense — net changed unfavorably by $31 million primarily due to the absence of $18 million of income recognized in 2007 associated with payments received for a terminated firm transportation agreement on Northwest Pipeline’s Grays Harbor lateral and the absence of $17 million of income recorded in 2007 for a change in estimate related to a regulatory liability at Northwest Pipeline. In addition, project development costs were $21 million higher in 2008. Partially offsetting these unfavorable changes was a $10 million gain on the sale of certain south Texas assets, and a $9 million gain on the sale of excess inventory gas, both of which were recorded by Transco in 2008.

     The increase in segment profit is primarily due to the previously described changes and higher equity earnings from Gulfstream.

Midstream Gas & Liquids

Overview of 2009

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

     Significant events during 2009 include the following:

  Cameron Meadows Plant

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

  Willow Creek

     The Willow Creek facility in western Colorado began processing natural gas production and extracting NGLs in early August and achieved full processing operations in September. Currently, the 450-million-cubic-feet-per-day (MMcf/d) gas processing plant primarily processes Williams’ Exploration & Production segment’s wellhead production, has a peak capacity of 30,000 barrels of NGLs per day, and is recovering approximately 20,000 barrels per day. In the current processing arrangement with Williams’ Exploration & Production segment, Midstream receives a volumetric-based processing fee and a percent of the NGLs extracted.

  Laurel Mountain Midstream, LLC

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

  Volatile commodity prices

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

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

  Hurricane impact to insurance coverage

     While our insurance expense has increased modestly in 2009 compared to 2008, the overall level of coverage on our offshore assets in the Gulf Coast region against named windstorm events has substantially decreased, including the absence of coverage on certain of our assets. (Please read Note 10, Property, Plant and Equipment, of Notes to Supplemental Consolidated Financial Statements included elsewhere herein.)

     Outlook for 2010

     The following factors could impact our business in 2010.

  Commodity price changes

•

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

•

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

  Gathering, processing, and NGL sales volumes

	•		The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities. Our customers are generally large producers, and we have not experienced and do not anticipate an overall significant decline in volumes due to reduced drilling activity.
	•		In the onshore region, we expect higher fee revenues, NGL volumes, depreciation expense and operating expenses in 2010 compared to 2009 as our Willow Creek facility moves into a full year of operation, and our expansion at Echo Springs is completed late in 2010.
	•		We expect fee revenues, NGL volumes, depreciation expense, and operating expenses in our offshore Gulf Coast region to increase from 2009 levels as our new Perdido Norte expansion begins start-up operations in the first quarter of 2010. Increases from our Perdido Norte expansion are expected to be partially offset by lower volumes in other Gulf Coast areas due to expected changes in gas processing contracts, as described below, and natural declines.
	•		Certain of our gas processing contracts contain provisions that allow customers to periodically elect processing services on either a fee basis, keep-whole, or percent-of-liquids basis. If customers switch from keep-whole to fee-based processing, this would reduce our NGL equity sales volumes.

Year-Over-Year Operating Results

		Years Ended December 31,
		2009				2008				2007
						(Millions)
Segment revenues		$	3,018			$	4,220			$	4,065
Segment profit (loss):
Gathering & processing		$	646			$	850			$	913
NGL marketing and other			114				(7	)			86
Indirect general and administrative expense			(78	)			(79	)			(72	)
Total		$	682			$	764			$	927

     In order to provide additional clarity, this discussion and analysis of Midstream’s operating results separately reflects the portion of general and administrative expense not allocated to an asset group as indirect general and administrative expense. These charges represent any overhead cost not directly attributable to one of the specific asset groups noted in this discussion.

  2009 vs. 2008

     The decrease in segment revenues is largely due to:

	•		A $716 million decrease in revenues associated with the production of NGLs primarily due to lower average NGL prices.
	•		A $513 million decrease in marketing revenues primarily due to lower average NGL and crude prices, partially offset by higher NGL volumes.

     These decreases are partially offset by a $65 million increase in fee revenues primarily due to higher volumes resulting from connecting new supplies in the deepwater Gulf of Mexico in the latter part of 2008 and new fees for processing Williams’ Exploration & Production segment’s natural gas production at Willow Creek.

     Segment costs and expenses decreased $1,119 million, or 32 percent, primarily as a result of:

	•		A $643 million decrease in marketing purchases primarily due to lower average NGL and crude prices, including the absence of a $9 million charge in 2008 to write down the value of NGL inventories, partially offset by higher NGL volumes.
	•		A $435 million decrease in costs associated with the production of NGLs primarily due to lower average natural gas prices.
	•		A $40 million gain on the 2009 sale of our Cameron Meadows processing plant.
	•		The absence of $17 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations.

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

     Gathering & processing

     The decrease in gathering & processing segment profit includes a $193 million decrease in the onshore region and an $11 million decrease in the Gulf Coast region.

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

	•		A $213 million decrease in NGL margins due to a significant decrease in average NGL prices, partially offset by a significant decrease in production costs reflecting lower natural gas prices. NGL equity volumes were slightly higher as both periods were impacted by significant volume changes. Current year volumes include the unfavorable impact of certain producers electing to convert, in accordance with those gas processing agreements, from keep-whole to fee-based processing at the beginning of 2009. Prior year NGL equity volumes sold were unusually low primarily due to an increase in inventory as we transitioned from product sales at the plant to shipping volumes through a pipeline for sale downstream, lower ethane recoveries to accommodate restrictions on the volume of NGLs we could deliver into the pipelines and hurricane-related disruptions at a third-party fractionation facility at Mont Belvieu, Texas, which resulted in an NGL inventory build-up. Lower NGL transportation costs in the onshore region due to the transition from our previous shipping arrangement to transportation on the Overland Pass pipeline also favorably impacted NGL margins in 2009.
	•		An $8 million decrease in involuntary conversion gains related to our Ignacio plant. These insurance recoveries in both years were used to rebuild the plant.
	•		A $44 million increase in fee revenues primarily due to new fees for processing Williams’ Exploration & Production segment’s natural gas production at Willow Creek, unusually low gathering and processing volumes in the first quarter of 2008 related to severe winter weather conditions, and producers converting from keep-whole to fee-based processing in the first quarter of 2009.

     The decrease in the Gulf Coast region’s segment profit includes:

•

A $68 million decrease in NGL margins reflecting lower average NGL prices and lower volumes. Lower production costs reflecting lower natural gas prices partially offset these decreases. Both periods were impacted by unfavorable volume changes. Current year volumes include the unfavorable impact of periods of reduced NGL recoveries during the first quarter due to unfavorable NGL economics and natural declines in production sources. Prior year volumes were unusually low primarily due to periods of reduced NGL recoveries during the fourth quarter and as a result of hurricanes in the third quarter.

	•		A $40 million gain in 2009 on the sale of our Cameron Meadows processing plant, partially offset by the absence of a $5 million involuntary conversion gain in 2008 related to our Cameron Meadows plant.
	•		$26 million higher fee revenues primarily due to higher volumes resulting from connecting new supplies in the Blind Faith prospect in the deepwater in the latter part of 2008.
	•		The absence of $16 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations.
	•		An $11 million increase in depreciation primarily due to our Blind Faith pipeline extensions that came into service during the latter part of 2008.

     NGL marketing and other

     The significant components of the increase in segment profit of our NGL marketing and other operations include:

•

$124 million in higher margins related to the marketing of NGLs primarily due to favorable changes in pricing while product was in transit during 2009 as compared to significant unfavorable changes in pricing while product was in transit in 2008 and the absence of a $9 million charge in 2008 to write down the value of NGL inventories.

  2008 vs. 2007

     The increase in segment revenues is largely due to:

	•		A $163 million increase in revenues associated with the production of NGLs primarily due to higher average NGL prices, partially offset by lower volumes. Lower volumes resulted from reduced ethane recoveries at the plants during the third and fourth quarters of 2008 compared to higher volumes during 2007 as we transitioned from shipping volumes through a pipeline for sale downstream to product sales at the plant.
	•		A $65 million increase in fee-based revenues primarily due to the onshore region, the deepwater Gulf Coast region and at our Conway fractionation and storage facilities.

     These increases are partially offset by an $85 million decrease in marketing revenues primarily due to lower volumes, partially offset by higher prices.

     Segment costs and expenses increased $311 million, or 10 percent, primarily as a result of:

	•		A $191 million increase in costs associated with the production of NGLs primarily due to higher average natural gas prices.
	•		A $98 million increase in operating costs including higher depreciation, repair costs and property insurance deductibles related to the hurricanes, gas transportation expenses in the eastern Gulf of Mexico, employee costs, and higher operating costs associated with new processing facilities related to the Piceance Acquisition that were placed in service during the first quarter of 2008.
	•		A $12 million increase in marketing purchases primarily due to a $9 million charge in 2008 to write down the value of NGL inventories.
	•		The absence of a $12 million favorable litigation outcome in 2007.

These increases are partially offset by:

•

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

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

     Gathering & processing

     The decrease in gathering & processing segment profit includes a $56 million decrease in the onshore region and a $7 million decrease in the Gulf Coast region.

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

	•		A $45 million decrease in NGL margins due to a significant increase in costs associated with the production of NGLs reflecting higher natural gas prices and lower volumes sold. The decrease in volumes sold is primarily due to restricted transportation capacity, unfavorable ethane economics, an increase in inventory during 2008, hurricane-related disruptions at a third-party fractionation facility, and lower equity volumes as processing agreements change from keep-whole to fee-based. These decreases were partially offset by a full year of production from the fifth train at our Opal processing plant, which began production in the first quarter of 2007.
	•		A $60 million increase in operating costs driven by higher turbine and engine overhaul expenses, depreciation expense, employee costs, and higher operating costs associated with new processing facilities related to the Piceance Acquisition that were placed in service during the first quarter of 2008.
	•		The absence of a $12 million favorable litigation outcome in 2007.
	•		A $41 million increase in fee revenues including new lease revenues from Gas Pipeline for the Parachute lateral transferred to Midstream in December 2007.
	•		A $12 million involuntary conversion gain in 2008 related to our Ignacio plant. These insurance recoveries were used to rebuild the plant.

     The decrease in the Gulf Coast region’s segment profit is primarily due to $39 million higher operating costs including higher depreciation, gas transportation expenses and hurricane repair and property insurance deductibles. These increased expenses are partially offset by $18 million higher NGL margins and $8 million higher fee revenues primarily due to connecting new supplies in the deepwater.

     NGL marketing and other

     The significant components of the decrease in segment profit of our NGL marketing and other operations include $95 million in lower margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices during the fourth quarter of 2008 on a higher volume of product inventory in transit. This also includes a $9 million charge in 2008 to write down the value of NGL inventories.

Supplemental Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

     This Supplemental Management’s Discussion and Analysis of Financial Condition and Liquidity has only been changed from its original presentation to reflect the recast of our Results of Operations — Cash Flows for the Piceance Acquisition for all periods presented. See Note 21. Subsequent Events of the supplemental consolidated financial statements and related notes included elsewhere herein for a discussion of certain subsequent events not reflected in the following discussion and analysis. Included in this subsequent events note is information about borrowings entered into related to the completion of the Piceance Acquisition.

Outlook

     For 2010, we expect operating results and cash flows to improve from 2009 levels due to the impact of expected higher energy commodity prices and the start-up of certain expansion capital projects. However, as previously mentioned, energy commodity prices are volatile and difficult to predict. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are substantially insulated from unfavorable commodity price movements, as follows:

	•		Firm demand and capacity reservation transportation revenues under long-term contracts at Gas Pipeline;
	•		Fee-based revenues from certain gathering and processing services at Midstream;
	•		Hedged NGL sales and natural gas purchases for a portion of activities at Midstream.

     We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following expectations for 2010:

	•		We expect to increase our per-unit quarterly distribution from $0.6350 to $0.6575 beginning with the distribution with respect to first quarter of 2010.
	•		We expect to fund capital and investment expenditures, debt service payments, distributions to unitholders and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or long-term debt issuances and utilization of our revolving credit facilities as needed.

Liquidity

     Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2010. Our internal and external sources of liquidity include:

	•		Cash and cash equivalents on hand;
	•		Cash generated from operations, including cash distributions from our equity-method investees;
	•		Cash proceeds from offerings of our common units and/or long-term debt;
	•		Capital contributions from Williams pursuant to the omnibus agreement;
	•		Use of credit facilities, as needed and available.

     We anticipate our more significant uses of cash to be:

	•		Maintenance and expansion capital expenditures;
	•		Contributions to our equity-method investees to fund their expansion capital expenditures;

	•		Interest on our long-term debt;
	•		Quarterly distributions to our unitholders and/or general partner.

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

	•		Lower than expected levels of cash flow from operations.
	•		Sustained reductions in energy commodity prices from expected 2010 levels.
	•		Exposure associated with our efforts to resolve regulatory and litigation issues (Please read Note 19, Commitments and Contingencies, of our Notes to Supplemental Consolidated Financial Statements).
	•		Physical damages to facilities, especially damage to offshore facilities by named windstorms for which our aggregate policy limit is $37.5 million in the event of a material loss.

Available Liquidity

		February 18, 2010
		(In millions)
Cash and cash equivalents		$	117
Available capacity under our $1.75 billion three-year senior unsecured credit facility (expires February 15, 2013)			1,500
		$	1,617

Shelf Registration

     On October 28, 2009, we filed a shelf registration statement as a well-known seasoned issuer that allows us to issue an unlimited amount of registered debt and limited partnership unit securities.

Distributions from Equity Method Investees

     Our equity method investees’ organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. Our more significant equity method investees include: Aux Sable Liquid Products, Discovery, Gulfstream and Laurel Mountain.

Omnibus Agreement with Williams

     In connection with the closing of the Dropdown, we entered into a separate omnibus agreement with Williams. Pursuant to this omnibus agreement, Williams is obligated to indemnify us from and against or reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries in respect of certain U.S. Department of Transportation projects, up to a maximum aggregate amount of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received prior to the closing of the Dropdown for services to be rendered by us in the future at the Devils Tower floating production platform located in Mississippi Canyon Block 773. In addition, we will be obligated to pay to Williams the net proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement in Docket No. RP06-569.

Credit Facilities

     At December 31, 2009, we had a $450 million senior unsecured credit agreement (Credit Agreement) with Citibank, N.A. as administrative agent, comprised of a $200 million revolving credit facility available for borrowings and letters of credit and a $250 million term loan. In connection with the Dropdown, we terminated the

Credit Agreement and entered into a new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with Transco and Northwest Pipeline, as co-borrowers, and Citibank, N.A. as the administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may be increased by up to an additional $250 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by us. At the closing of the Dropdown, we borrowed $250 million under the New Credit Facility to repay the $250 million term loan outstanding under the Credit Agreement.

     Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin or (2) a periodic fixed rate equal to LIBOR plus the 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 pay a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.

     The New Credit Facility contains various covenants that limit, among other things, a borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default and allow any material change in the nature of its business.

     In addition, we are required to maintain a ratio of debt to EBITDA (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for us and our consolidated subsidiaries. For each of Transco and Northwest Pipeline and their respective consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55 percent. Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter, and the debt to EBITDA ratio will be measured on a rolling four-quarter basis.

     The New Credit Facility includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the New 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 New Credit Facility and exercise other rights and remedies.

     We also had a $20 million revolving credit facility with Williams as the lender at December 31, 2009. The facility was available exclusively to fund working capital borrowings. This credit facility was terminated in connection with the Dropdown.

  Credit ratings

     The table below presents our current credit ratings and outlook on our senior unsecured long-term debt.

						Senior Unsecured
Rating Agency		Date of Last Change		Outlook		Debt Rating
Standard & Poor’s		January 12, 2010		Positive		BBB-
Moody’s Investor Service		February 17, 2010		Stable		Baa3
Fitch Ratings		February 2, 2010		Stable		BBB-

     The ratings changes noted above reflect the announcement and completion of the Dropdown.

     With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.

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

     With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

     Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios.

Capital Expenditures

     Each of our businesses is capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of:

	•		Maintenance capital expenditures, which are generally not discretionary, include (1) capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives and (2) certain well connection expenditures and expenditures which are mandatory and/or essential for maintaining the reliability of our operations;
	•		Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, include (1) expenditures to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities and (2) well connection expenditures which are not classified as maintenance expenditures.

     The following table provides summary information related to our expected capital expenditures for 2010 (in millions):

		Maintenance												Expansion
Segment		Low				Midpoint				High				Low				Midpoint				High
Gas Pipeline		$	210			$	220			$	230			$	340			$	355			$	370
Midstream			80				90				100				320				410				500
Total		$	290			$	310			$	330			$	660			$	765			$	870

     Expansion capital expenditures include expenditures for the following Gas Pipeline and Midstream projects:

Gas Pipeline

  Mobile Bay South

     In May 2009, we received approval from the FERC to construct a compression facility in Alabama allowing transportation service to various southbound delivery points. The cost of the project is estimated to be $37 million. The estimated project in-service date is May 2010 and will increase capacity by 253 Mdt/d.

  85 North

     In September 2009, we received approval from the FERC to construct an expansion of our existing natural gas transmission system from Alabama to various delivery points as far north as North Carolina. The cost of the project is estimated to be $241 million. Phase I service is anticipated to begin in July 2010 and will increase capacity by 90 Mdt/d. Phase II service is anticipated to begin in May 2011 and will increase capacity by 218 Mdt/d.

  Mobile Bay South II

     In November 2009, we filed an application with the FERC to construct additional compression facilities and modifications to existing facilities in Alabama allowing transportation service to various southbound delivery points. The cost of the project is estimated to be $36 million. The estimated project in-service date is May 2011 and will increase capacity by 380 Mdt/d.

  Sundance Trail

     In November 2009, we received approval from the FERC to construct approximately 16 miles of 30-inch pipeline between our existing compressor stations in Wyoming. The project also includes an upgrade to our existing compressor station and is estimated to cost up to $65 million. The estimated in-service date is November 2010 and will increase capacity by 150 Mdt/d.

Midstream

  Perdido Norte

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

  Wamsutter

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

  Marcellus Shale

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

     In addition to our initial investment, we intend to invest additional capital within our Laurel Mountain joint venture to grow the existing gathering infrastructure in 2010 and beyond.

Cash Distributions to Unitholders

     We have paid quarterly distributions to unitholders and our general partner after every quarter since our initial public offering on August 23, 2005. We expect to increase our quarterly distribution from $0.6350 to $0.6575 per unit effective with our distribution with respect to the first quarter of 2010. As part of the consideration for the Dropdown, we issued 203 million Class C limited partnership units to Williams, which are identical to our common limited partnership units except that for the first quarter of 2010 they will receive a prorated quarterly distribution since they were not outstanding during the full quarterly period. These Class C units will automatically convert into our common limited partnership units following the record date for the first-quarter 2010 cash distribution.

Results of Operations — Cash Flows

     The following table summarizes our cash flows:

		Years Ended December 31,
		2009				2008				2007
						(In millions)
Net cash provided (used) by:
Operating activities		$	1,474			$	1,480			$	1,876
Investing activities			(910	)			(1,003	)			(1,237	)
Financing activities			(544	)			(390	)			(654	)
Increase (decrease) in cash and cash equivalents		$	20			$	87			$	(15	)

Operating Activities

     Net cash provided by operating activities decreased $6 million in 2009 as compared to 2008 due primarily to lower operating income.

     Net cash provided by operating activities decreased $396 million in 2008 as compared to 2007 due primarily to lower Midstream operating income and payment of $144 million of rate refunds in 2008 by Transco.

Investing Activities

     Capital expenditures in 2009, 2008 and 2007 totaled $907 million, $1,018 million and $1,185 million. Also, 2009 included a $108 million cash payment for Midstream’s 51 percent ownership interest in the Laurel Mountain joint venture.

Financing Activities

     Net cash used by financing activities in 2009 included:

	•		Distributions to Williams of $384 million.
	•		Distributions to limited partner unitholders and our general partner of $144 million.

     Net cash used by financing activities in 2008 included:

	•		Distributions to Williams of $623 million.
	•		Distributions to limited partner unitholders and our general partner of $155 million.
	•		$333 million proceeds from the completion of the WMZ initial public offering.
	•		$250 million issuance by Northwest Pipeline of 6.05 percent senior unsecured notes. These proceeds were used to repay Northwest Pipeline’s $250 million loan under Williams’ $1.5 billion credit facility.
	•		$175 million borrowing by Transco under Williams’ $1.5 billion credit facility to retire Transco’s $100 million 6.25 percent notes that matured in January 2008 and a $75 million adjustable rate note due in April 2008.
	•		$250 million issuance by Transco of 6.05 percent senior unsecured notes due 2018. These proceeds were used to repay Transco’s $175 million loan under Williams’ $1.5 billion credit facility.

     Net cash used by financing activities in 2007 included:

	•		Distributions to Williams of $1,313 million.
	•		Distributions to limited partner unitholders and our general partner of $87 million.

	•		Proceeds of $492 million from the issuance of our limited partner units and proceeds from issuance of $250 million variable rate term loan related to the purchase of ownership interests in Wamsutter.
	•		$185 million issuance by Northwest Pipeline of 5.95 percent senior unsecured notes due 2017. These proceeds were used to retire $175 million of Northwest Pipeline’s 8.125 percent senior unsecured notes, plus an early retirement premium of approximately $7 million.
	•		$250 million borrowing by Northwest Pipeline under Williams’ $1.5 billion credit facility to retire Northwest Pipeline’s $250 million 6.25 percent notes that matured in December 2007.

Contractual Obligations

     A summary of our contractual obligations at December 31, 2009:

		2010				2011-2012				2013-2014				2015+				Total
								(in millions)
Long-term debt:
Principal (a)		$	15			$	1,034			$	—			$	1,952			$	3,001
Interest			196	(b)			352				262				527				1,337
Capital leases			—				—				—				—				—
Operating leases (c)			27				40				33				125				225
Purchase obligations			529				449				382				1,535				2,895
Other long term obligations			—				—				—				—				—
Total		$	767			$	1,875			$	677			$	4,139			$	7,458

		2010				2011-2012				2013-2014				Thereafter				Total
										(Millions)
Long-term debt, including current portion:
Issuance of the $3.5 billion senior notes		$	—			$	—			$	—			$	3,500			$	3,500
Retirement of the $250 million term loan under our $450 million credit facility			—				(250	)			—				—				(250	)
Issuance of $250 million term loan under our new $1.75 billion credit facility			—				—				250				—				250
Total		$	—			$	(250	)		$	250			$	3,500			$	3,500

Off-Balance Sheet Arrangements

     We have guarantees on behalf of certain entities in which we have an equity ownership interest which guarantee operating performance. These are disclosed in Note 9, Investments, of our Notes to Supplemental Consolidated Financial Statements. Other than these arrangements, we had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at December 31, 2009.

Effects of Inflation

     Our operations have benefited from relatively low inflation rates. Following the Dropdown, approximately 64 percent of our gross property, plant and equipment is at Gas Pipeline. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For Midstream, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in oil and natural gas and related commodities than by changes in general inflation. Crude, natural gas, and natural gas liquids prices are particularly sensitive to the Organization of the Petroleum Exporting Countries (OPEC) production levels and/or the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to these price changes is reduced through the use of hedging instruments and the fee-based nature of certain of our services.

Environmental

     We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $19.3 million, all of which are recorded as liabilities on our balance sheet at December 31, 2009. We will seek recovery of approximately $12.6 million of these costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2009, we paid approximately $3.6 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $3.2 million in 2010 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2009, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

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

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

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 $150 million and $220 million, and between $65 million and $85 million, 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.

Report of Independent Registered Public Accounting Firm

The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.

We have audited the accompanying supplemental consolidated balance sheets of Williams Partners L.P. as of December 31, 2009 and 2008, and the related supplemental consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2009. These supplemental financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these supplemental financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting for the supplemental financial statements. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The supplemental consolidated financial statements give retroactive effect to the Piceance Acquisition as described in Note 1 to the supplemental consolidated financial statements. The Piceance Acquisition was not previously held by Williams Partners L.P., and such acquisition has been accounted for in a manner similar to a pooling-of-interests as described in Note 1 to the supplemental consolidated financial statements. Generally accepted accounting principles proscribe giving effect to a consummated acquisition accounted for by the pooling-of-interests method in the financial statements that do not include the date of consummation. These supplemental financial statements do not extend through the date of consummation. However, they will become the historical consolidated financial statements of Williams Partners L.P. after financial statements covering the date of consummation of the acquisition are issued.

In our opinion, the supplemental financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles applicable after financial statements are issued for a period which includes the date of the consummation of the transaction.

/s/ Ernst & Young LLP
Tulsa, Oklahoma
December 10, 2010

WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS*

		December 31,
		2009				2008
		(In millions)
ASSETS
Current assets:
Cash and cash equivalents		$	153			$	133
Accounts receivable:
Trade			381				273
Affiliate			6				5
Notes receivable from parent			—				252
Inventories			129				147
Regulatory assets			77				89
Other current assets			75				87
Total current assets			821				986
Investments			593				524
Property, plant and equipment — net			10,716				10,307
Regulatory assets, deferred charges and other			345				350
Total assets		$	12,475			$	12,167
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade		$	356			$	315
Affiliate			80				71
Accrued liabilities			185				257
Long-term debt due within one year			15				—
Total current liabilities			636				643
Long-term debt			2,981				2,971
Asset retirement obligations			492				460
Regulatory liabilities, deferred income and other			263				226
Contingent liabilities and commitments (Note 19)
Equity:
Common unitholders (52,777,452 units outstanding at December 31, 2009 and 2008)			1,631				1,620
General partner			6,123				5,901
Accumulated other comprehensive income			2				4
Noncontrolling interests in consolidated subsidiaries			347				342
Total equity			8,103				7,867
Total liabilities and equity		$	12,475			$	12,167

See accompanying notes to supplemental consolidated financial statements

WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF INCOME*

		Year Ended December 31,
		2009				2008				2007
		(In millions, except per-unit amounts)
Revenues:
Gas Pipeline		$	1,591			$	1,637			$	1,623
Midstream Gas & Liquids			3,018				4,220				4,065
Intercompany eliminations			(7	)			(10	)			(4	)
Total revenues			4,602				5,847				5,684
Segment costs and expenses:
Costs and operating expenses			3,100				4,206				3,936
Selling, general and administrative expense			300				282				271
Other (income) expense — net			(34	)			10				(20	)
Segment costs and expenses			3,366				4,498				4,187
General corporate expenses			109				95				101
Operating income:
Gas Pipeline			600				630				622
Midstream Gas & Liquids			636				719				875
General corporate expenses			(109	)			(95	)			(101	)
Total operating income			1,127				1,254				1,396
Equity earnings			81				76				79
Interest accrued — third-party			(207	)			(217	)			(206	)
Interest accrued — affiliate			(52	)			(35	)			(20	)
Interest capitalized			58				43				25
Interest income — third-party			1				2				7
Interest income — affiliate			19				23				18
Other income — net			13				10				19
Income before income taxes			1,040				1,156				1,318
Provision (benefit) for income taxes			4				(952	)			(144	)
Net income			1,036				2,108				1,462
Less: Net income attributable to noncontrolling interests in subsidiaries			27				25				—
Net income attributable to controlling interests		$	1,009			$	2,083			$	1,462
Allocation of net income for calculation of earnings per unit:
Net income attributable to controlling interests		$	1,009			$	2,083			$	1,462
Allocation of net income to general partner			857				1,921				1,377
Allocation of net income to limited partners		$	152			$	162			$	85
Basic and diluted net income per limited partner unit		$	2.88			$	3.08			$	1.99
Weighted average number of common units outstanding			52,777,452				52,775,710	(a)			40,131,195	(a)(b)

See accompanying notes to supplemental consolidated financial statements

WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CHANGES IN EQUITY*

		Williams Partners L.P.
		Limited Partners
																		Accumulated Other
														General				Comprehensive				Noncontrolling				Total
		Common				Class B				Subordinated				Partner				Income (Loss)				Interests				Equity
		(In millions)
Balance — December 31, 2006		$	734			$	242			$	109			$	4,580			$	5			$	—			$	5,670
Comprehensive income:
Net income — 2007			65				9				15				1,373				—				—				1,462
Other comprehensive loss:
Net unrealized losses on cash flow hedges, net of reclassification adjustments			—				—				—				—				(11	)			—				(11	)
Total other comprehensive loss																							—				(11	)
Total comprehensive income																											1,451
Cash distributions			(60	)			(6	)			(14	)			(7	)			—				—				(87	)
Conversion of Class B units into common (6,805,492 units)			245				(245	)			—				—				—				—				—
Issuance of units to public (9,250,000 common units)			335				—				—				—				—				—				335
Issuance of units to general partner (4,163,257 common units)			157				—				—				—				—				—				157
Distributions to The Williams Companies, Inc. — net			—				—				—				(1,313	)			—				—				(1,313	)
Other			(2	)			—				(1	)			5				—				—				2
Balance — December 31, 2007			1,474				—				109				4,638				(6	)			—				6,215
Net income — 2008			163				—				2				1,918				—				25				2,108
Other comprehensive income:
Net unrealized gains on cash flow hedges, net of reclassification adjustments			—				—				—				—				10				—				10
Total other comprehensive income																							—				10
Total comprehensive income																							—				2,118
Cash distributions			(124	)			—				(4	)			(27	)			—				—				(155	)
Sale of Williams Pipeline Partners L.P. limited partner units			—				—				—				—				—				333				333
Dividends paid to noncontrolling interests			—				—				—				—				—				(12	)			(12	)
Conversion of subordinated units into common (7,000,000 units)			107				—				(107	)			—				—				—				—
Distributions to The Williams Companies, Inc. — net			—				—				—				(623	)			—				—				(623	)
Other			—				—				—				(5	)			—				(4	)			(9	)
Balance — December 31, 2008			1,620				—				—				5,901				4				342				7,867
Net income — 2009			145				—				—				864				—				27				1,036
Other comprehensive income:
Net unrealized losses on cash flow hedges, net of reclassification adjustments			—				—				—				—				(2	)			—				(2	)
Total other comprehensive loss																							—				(2	)
Total comprehensive income																							—				1,034
Cash distributions			(134	)			—				—				(10	)			—				—				(144	)
Dividends paid to noncontrolling interests			—				—				—				—				—				(23	)			(23	)
Distributions to The Williams Companies, Inc. — net			—				—				—				(384	)			—				—				(384	)
Reclassification of notes receivable (see Note 3)			—				—				—				(253	)			—				—				(253	)
Other			—				—				—				5				—				1				6
Balance — December 31, 2009		$	1,631			$	—			$	—			$	6,123			$	2			$	347			$	8,103

See accompanying notes to supplemental consolidated financial statements.

WILLIAMS PARTNERS L.P.
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS*

		Year Ended December 31,
		2009				2008				2007
						(In millions)
OPERATING ACTIVITIES:
Net income		$	1,036			$	2,108			$	1,462
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization			553				518				487
Provision (benefit) for deferred income taxes			—				(997	)			(306	)
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			(93	)			142				(99	)
Inventories			17				(42	)			38
Other current assets			8				(81	)			17
Accounts payable			2				(194	)			71
Accrued liabilities			(73	)			36				156
Affiliates — net			16				(9	)			(37	)
Other, including changes in noncurrent assets and liabilities			8				(1	)			87
Net cash provided by operating activities			1,474				1,480				1,876
FINANCING ACTIVITIES:
Proceeds from long-term debt			—				674				684
Payments of long-term debt			(2	)			(600	)			(428	)
Proceeds from sale of our limited partner units			—				29				492
Redemption of common units from general partner			—				(29	)			—
Proceeds from sale of Williams Pipeline Partners L.P. limited partner units			—				333				—
Dividends paid to noncontrolling interests in subsidiaries			(23	)			(12	)			—
Distributions to The Williams Companies, Inc. — net			(384	)			(623	)			(1,313	)
Distributions to limited partner unitholders and general partner			(144	)			(155	)			(87	)
Other — net			9				(7	)			(2	)
Net cash used by financing activities			(544	)			(390	)			(654	)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(907	)			(1,018	)			(1,185	)
Net proceeds from dispositions			46				30				(9	)
Changes in notes receivable from parent			(1	)			1				(24	)
Cumulative distributions received in excess of equity earnings of Discovery			9				36				—
Distribution received from Gulfstream Natural Gas System, L.L.C.			73				—				—
Purchases of investments			(131	)			(50	)			(19	)
Purchase of ARO trust investments			(46	)			(31	)			—
Proceeds from sale of ARO trust investments			41				14				—
Other — net			6				15				—
Net cash used by investing activities			(910	)			(1,003	)			(1,237	)
Increase (decrease) in cash and cash equivalents			20				87				(15	)
Cash and cash equivalents at beginning of year			133				46				61
Cash and cash equivalents at end of year		$	153			$	133			$	46

See accompanying notes to supplemental consolidated financial statements

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS

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).

  Basis of Presentation

     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 Williams Pipeline Partners L.P. (WMZ), but excluding its Canadian, Venezuelan and olefins operations, and 25.5 percent of Gulfstream Natural Gas System, L.L.C.(Gulfstream ), collectively, the Contributed Entities.

     This contribution was made in exchange for aggregate consideration of:

	•		$3.5 billion in cash, less certain expenses incurred by us, which we financed by issuing $3.5 billion of senior unsecured notes (see Note 13);
	•		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 has been 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 this common control transaction increased net income $878 million, $1,911 million and $1,284 million for 2009, 2008 and 2007, respectively. This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.

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 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 reporting segment.

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     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. The 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.

     The effect of recasting our financial statements to account for this common control transaction increased net income $5 million, $6 million and $13 million for 2009, 2008 and 2007, respectively. 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.

     Under an omnibus agreement entered into in connection with the Piceance Acquisition, a subsidiary of Williams is obligated to reimburse us for (1) amounts incurred by us or our subsidiaries for any costs required to complete the pipeline and compression projects known collectively as the Ryan Gulch Expansion Project, (2) amounts up to $20 million related to the development of a potential cryogenic processing facility incurred by us or our subsidiaries prior to January 31, 2011, if an arrangement for cryogenic processing with a subsidiary of Williams is not reached, and (3) amounts incurred by us or our subsidiaries for notice of violation or enforcement actions related to compression station land use permits or other losses, costs and expenses related to certain surface lease use agreements. In addition, we are obligated to reimburse a subsidiary of Williams for any costs related to the pipeline and compression projects known collectively as the Kokopelli Expansion, irrespective of whether those costs were incurred prior to the effective date of the Piceance Acquisition.

  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 is comprised primarily of the following interstate natural gas pipeline assets:

	•		Transcontinental Gas Pipe Line Company, LLC (Transco), an interstate natural gas pipeline extending from the Gulf of Mexico region to the northeastern United States;
	•		Northwest Pipeline GP (Northwest Pipeline), an interstate natural gas pipeline extending from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington;
	•		A 24.5 percent equity interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), an interstate natural gas pipeline extending from the Mobile Bay area in Alabama to markets in Florida.

     Midstream is comprised of the following natural gas gathering, processing and treating facilities, oil gathering and transportation facilities and natural gas liquids (NGL) transportation, fractionation and storage facilities and investments:

•

Two gathering systems and the Echo Springs and Opal processing plants serving the Wamsutter and southwest areas of Wyoming;

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	•		A gathering system, the Ignacio, Kutz and Lybrook processing plants and the Milagro and Esperanza natural gas treating plants, all serving the San Juan basin in New Mexico and Colorado;
	•		A gathering system, natural gas liquids (NGL) pipeline and the Willow Creek and Parachute processing plants in Colorado;
	•		An equity interest in a gathering system serving the Appalachian Basin in southwest Pennsylvania;
	•		Onshore and offshore natural gas gathering pipelines in the Gulf Coast region;
	•		The Mobile Bay and Markham processing plants in the Gulf Coast region;
	•		The Canyon Station and Devils Tower offshore production platforms in the Gulf of Mexico;
	•		Three Gulf of Mexico deepwater crude oil pipelines;
	•		NGL storage facilities in the Conway, Kansas area;
	•		Interests in two NGL fractionation facilities: one near Conway, Kansas and the other in Baton Rouge, Louisiana;
	•		An equity interest in Discovery Producer Services LLC (Discovery), whose assets include a processing plant and a fractionation plant in Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico;
	•		An equity interest in Aux Sable Liquid Products L.P., whose assets include a processing plant and a fractionator in Illinois.

Note 2. Summary of Significant Accounting Policies

  Principles of consolidation

     The supplemental consolidated financial statements include the accounts of Williams Partners L.P., OLLC and our other wholly owned subsidiaries. We eliminated all intercompany accounts and transactions. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20 percent to 50 percent of the voting interest or otherwise exercise significant influence over operating and financial policies of the company. We also apply the equity method of accounting for investments where our majority ownership does not provide us with control due to the significant participatory rights of other owners.

     In January 2008, WMZ completed an initial public offering of 16.25 million common units at a price of $20 per unit. In February 2008, the underwriters exercised their right to purchase an additional 1.65 million common units at the same price. The initial asset of the partnership is a 35 percent interest in Northwest Pipeline. As of December 31, 2009, we owned approximately 47.7 percent of the interests in WMZ, including the interests of the general partner (Williams Pipeline GP LLC), which is wholly owned by us, and IDRs. We consolidate WMZ within our Gas Pipeline segment due to our control through the general partner. See Note 21. Subsequent Events—WMZ Merger, for current information regarding our ownership of WMZ.

     We hold a 50 percent undivided interest in the Conway NGL fractionation facility, for which no separate legal entity exits. Accordingly, we proportionately consolidate our share of the fractionator revenues, costs and expenses, and property, plant and equipment. Liabilities in the Supplemental Consolidated Balance Sheets include those incurred on behalf of the co-owners with corresponding receivables from the
co-owners.

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

  Use of estimates

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

     Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include:

	•		Impairment assessments of long-lived assets;
	•		Loss contingencies;
	•		Environmental remediation obligations;
	•		Asset retirement obligations.

These estimates are discussed further throughout these notes.

  Regulatory accounting

     Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates established by the FERC are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these businesses that are regulated can differ from the accounting requirements for non-regulated businesses. These differences are discussed further throughout these notes.

  Cash and Cash Equivalents

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

  Accounts Receivable

     Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We do not recognize an allowance for doubtful accounts at the time the revenue which generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The allowance for doubtful accounts at December 31, 2009 and 2008 was immaterial.

  Inventory Valuation

     All inventories are stated at the lower of cost or market. We determine the cost of certain natural gas inventories held by Transco using the last-in, first-out (LIFO) cost method. We determine the cost of the remaining inventories

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

primarily using the average-cost method. LIFO inventory at December 31, 2009 and 2008 was $7 million and $11 million, respectively.

  Property, Plant and Equipment

     Property, plant and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized.

     As regulated entities, Transco and Northwest Pipeline provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method.

     Northwest Pipeline’s levelized rate design for a 2003 pipeline expansion project created a revenue stream that remains constant over the related 25-year and 15-year customer contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. FERC has approved the accounting for the differences between book depreciation and the levelized depreciation as a regulatory asset with the offsetting credit to income. Credits totaling $2 million in 2009, $3 million in 2008 and $4 million in 2007 are recorded in the accompanying Supplemental Consolidated Statements of Income. The accompanying Supplemental Consolidated Balance Sheets reflect the related regulatory assets of $31 million and $29 million at December 31, 2009 and 2008, respectively. The regulatory asset will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.

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

     We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. The regulated pipelines record the ARO asset depreciation offset to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as corresponding accretion expense included in costs and operating expenses, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with the collection of those costs in rates.

  Derivative Instruments and Hedging Activities

     We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swap agreements, option contracts and forward contracts involving short- and long-term purchases and sales of physical energy commodities. The counterparty to certain of these instruments is a Williams affiliate. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, on the Supplemental Consolidated Balance Sheets in other current assets, accrued liabilities, regulatory assets, deferred charges and other or regulatory liabilities, deferred income and other as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual contracts. We report these amounts on a gross basis.

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The accounting for changes in the fair value of a commodity derivative depends on whether the derivative has been designated in a hedging relationship and whether we have elected the normal purchases and normal sales exception. The accounting for the change in fair value can be summarized as follows:

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

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

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

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

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

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

	•		Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;
	•		The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
	•		Realized gains and losses on all derivatives that settle financially other than natural gas derivatives for NGL processing activities;
	•		Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

  Gas Pipeline revenues

     Gas Pipeline revenues are primarily from services pursuant to long-term firm transportation and storage agreements. These agreements provide for a demand charge based on the volume of a contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for demand charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services, and storage injection and withdrawal services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.

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

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

  Midstream revenues

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

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

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

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

  Impairment of Long-Lived Assets and Investments

     We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the carrying value of the assets is recoverable. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes, including selling in the near term or holding for the remaining estimated useful life. If the carrying value is not

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

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

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

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

  Environmental

     Environmental expenditures that relate to current or future revenues are expensed or capitalized based upon the nature of the expenditures. Expenditures that relate to an existing contamination caused by past operations that do not contribute to current or future revenue generation are expensed. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account our prior remediation experience, and are not discounted. Environmental contingencies are recorded independently of any potential claim for recovery.

  Capitalized Interest

     We generally capitalize interest during construction on major projects with construction periods of at least three months and a total project cost in excess of $1 million. Our nonregulated operations capitalize interest based on our average interest rate on debt to the extent we incur interest expense. Our regulated operations capitalize interest on all projects. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. Interest capitalized on internally generated funds reported as a component of other income — net was $10 million, $5 million and $12 million in 2009, 2008 and 2007, respectively. The rates used by regulated companies are calculated in accordance with FERC rules. Historically, Williams provided the financing for capital expenditures of the nonregulated companies acquired in the Dropdown; hence, the rates used by those companies were based on Williams’ average interest rate on debt.

  Income Taxes

     We are not a taxable entity for federal and state income tax purposes. The tax on our net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Although the Contributed Entities’ operations were included in the Williams’ consolidated federal income tax return prior to the Dropdown, following their acquisition by us, their operations are now treated as a partnership. Therefore, other than Transco and Northwest Pipeline, the historical operations exclude income taxes for all periods presented. Transco and Northwest Pipeline converted from corporations to limited liability companies on December 31, 2008 and October 1, 2007, respectively, and were not subject to income taxes after those respective dates. The effect of Transco and Northwest Pipeline’s change in tax status is included in the provision (benefit) for income taxes in the respective period of the change.

     During 2006, the state of Texas passed a law that imposed a partnership-level tax on us beginning in 2007 based on the net revenues of our assets apportioned to the state of Texas. This tax is included in the provision (benefit) for income taxes.

  Earnings Per Unit

     We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common, Class B and subordinated units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.

  Issuance of equity of consolidated subsidiary

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

  Accounting standards issued but not yet effective

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

Note 3. Related Party Transactions

     The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with the operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to the employee retirement, medical plans and paid time off. Our share of those costs is charged to us through affiliate billings and reflected in costs and operating expenses in the accompanying Supplemental Consolidated Statements of Income.

     In addition, all of our general and administrative employees are employees of Williams, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. Our share of direct administrative expenses is reflected in selling, general and administrative expense, and our share of allocated administrative expenses is reflected in general corporate expenses in the accompanying Supplemental Consolidated

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Statements of Income. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.

     Under an omnibus agreement entered into in connection with the Dropdown, Williams is obligated to reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the Dropdown for services to be rendered by us in the future at the Devils Tower floating production platform. In addition, we will be obligated to pay to Williams the proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement.

     Under a separate omnibus agreement entered into in August 2005 with Williams, we are provided a quarterly credit for general and administrative expenses, which is reflected as a capital contribution from our general partner. During 2009, Williams agreed to provide up to an additional $10 million credit, in addition to the credit previously provided, to the extent that 2009 non-segment profit general and administrative expenses exceeded a certain level. We recorded total general and administrative expenses (including those expenses subject to the credit by Williams) as an expense, and we recorded any credits as capital contributions from Williams. The expense subject to this credit is allocated entirely to our general partner. As a result, the net income allocated to limited partners on a per-unit basis reflects the benefit of this credit. The total general and administrative credits received from Williams were $3 million, $2 million and $2 million in 2009, 2008 and 2007, respectively.

     We have a contribution receivable from our general partner of less than $1 million at December 31, 2009 and 2008 for amounts reimbursable to us under the omnibus agreement. We net this receivable against equity on the Supplemental Consolidated Balance Sheets.

     Gas Pipeline revenues include revenues from transportation and exchange services and rental of communication facilities with subsidiaries of Williams. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly-situated nonaffiliated customers.

     Midstream revenues include revenues from the following types of transactions with affiliates:

	•		Sales of feedstock commodities to Williams Olefins, LLC (Williams Olefins), a wholly owned subsidiary of Williams, for use in their facilities. These sales are generally made at market prices at the time of sale.
	•		Gathering, treating and processing services for Williams Production Company (WPC), a wholly owned subsidiary of Williams, under several contracts. We believe that the rates charged to provide these services are reasonable as compared to those that are charged to similarly-situated nonaffiliated customers.
	•		We buy and sell natural gas from and to Williams Gas Marketing, Inc. (WGM), a wholly owned subsidiary of Williams, related to our “crosshauling” activity on our Four Corners gathering system. Crosshauling typically involves the movement of some natural gas between gathering systems at established interconnect points to optimize flow, reduce expenses or increase profitability. As a result, we must purchase gas for delivery to customers at certain plant outlets, and we have excess volumes to sell at other plant outlets. WGM conducts these purchase and sale transactions at current market prices at each location. Because the transactions are entered into in contemplation of each other, we report them net in revenues.

WILLIAMS PARTNERS L. P.

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Costs and operating expenses also include charges for the following types of transactions with affiliates:

	•		Our Midstream segment purchases NGLs for resale from WPC and Williams Olefins at market prices at the time of purchase.
	•		Our Midstream segment purchases natural gas for shrink replacement and fuel for processing plants, the co-generation plant and a fractionator from WGM at market prices at the time of purchase or contract execution.
	•		Our Gas Pipeline segment purchases natural gas from WGM at contract or market prices.
	•		We transferred a transportation capacity agreement to WGM in a prior year. To the extent that WGM does not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimburse WGM for these transportation costs.
	•		The amortization of a gas purchase contract transferred to us by Williams, for the purchase of a portion of our fuel requirements at a fractionator, at a market price not to exceed a specified level. This contract terminated on December 31, 2007.

     Below is a summary of the related party transactions discussed above.

		Years Ended December 31,
		2009				2008				2007
		(In millions)
Gas Pipeline revenues		$	29			$	38			$	45
Midstream revenues
Product sales			75				164				127
Gathering and processing			143				103				95
Costs and operating expenses
Product purchases			497				972				680
Employee costs			206				215				195
Other			9				11				1
Selling, general and administrative expense
Employee costs			234				211				214