UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-32599

WILLIAMS PARTNERS L.P.

(Exact name of registrant as specified in its charter)

DELAWARE		20-2485124
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
ONE WILLIAMS CENTER
TULSA, OKLAHOMA		74172-0172
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number: (918) 573-2000

NO CHANGE

(Former name, former address and former fiscal year, if changed since last report)

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

     The registrant had 255,777,452 common units outstanding as of July 28, 2010.

 

 

Williams Partners L.P.
Index

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income — Three and Six Months Ended June 30, 2010 and 2009			3
Consolidated Balance Sheet — June 30, 2010 and December 31, 2009			4
Consolidated Statement of Changes in Equity — Six Months ended June 30, 2010			5
Consolidated Statement of Cash Flows — Six Months ended June 30, 2010 and 2009			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 3. Quantitative and Qualitative Disclosures About Market Risk			40
Item 4. Controls and Procedures			41
Part II. Other Information			41
Item 1. Legal Proceedings			41
Item 1A. Risk Factors			41
Item 6. Exhibits			44
EX-12
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

     Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters.

     All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” or other similar expressions. These statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

•

Amounts and nature of future capital expenditures;

•

Expansion and growth of our business and operations;

•

Financial condition and liquidity;

•

Business strategy;

•

Cash flow from operations or results of operations;

•

The levels of cash distributions to unitholders;

•

Seasonality of certain business segments;

•

Natural gas and natural gas liquids prices and demand.

     Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Limited partner units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the risk factors discussed below in addition to the other information in this report. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment. Many of the factors that will

determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

•

Whether we have sufficient cash from operations to enable us to maintain current levels of cash distributions or to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner;

•

Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;

•

Inflation, interest rates and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

•

The strength and financial resources of our competitors;

•

Development of alternative energy sources;

•

The impact of operational and development hazards;

•

Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;

•

Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;

•

Changes in maintenance and construction costs;

•

Changes in the current geopolitical situation;

•

Our exposure to the credit risks of our customers;

•

Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;

•

Risks associated with future weather conditions;

•

Acts of terrorism; and

•

Additional risks described in our filings with the Securities and Exchange Commission (SEC).

     Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

     In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

     Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009, and Part II, Item 1A. Risk Factors of this Form 10-Q.

PART I — FINANCIAL INFORMATION

Item 1.		Financial Statements

Williams Partners L.P.

		Three months ended								Six months ended
		June 30,								June 30,
		2010				2009*				2010				2009*
		(Millions, except per-unit amounts)
Revenues:
Gas Pipeline		$	380			$	421			$	787			$	822
Midstream Gas & Liquids			987				663				2,038				1,221
Intercompany eliminations			—				(3	)			—				(5	)
Total revenues			1,367				1,081				2,825				2,038
Segment costs and expenses:
Costs and operating expenses			987				738				2,001				1,381
Selling, general and administrative expenses			68				71				127				141
Other (income) expense — net			(7	)			3				(10	)			—
Segment costs and expenses			1,048				812				2,118				1,522
General corporate expenses			28				26				62				51
Operating income:
Gas Pipeline			138				147				298				311
Midstream Gas & Liquids			181				122				409				205
General corporate expenses			(28	)			(26	)			(62	)			(51	)
Total operating income			291				243				645				465
Equity earnings			27				16				53				21
Interest accrued — third-party			(101	)			(51	)			(182	)			(102	)
Interest accrued — affiliate			(1	)			(16	)			(1	)			(30	)
Interest capitalized			7				17				19				31
Interest income			—				6				3				11
Other income (expense) — net			2				2				1				5
Income before income taxes			225				217				538				401
Provision for income taxes			—				2				—				3
Net income			225				215				538				398
Less: Net income attributable to noncontrolling interests			5				6				11				13
Net income attributable to controlling interests		$	220			$	209			$	527			$	385
Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests		$	220			$	209			$	527			$	385
Allocation of net income to general partner and Class C units			50				183				335				340
Allocation of net income to common units		$	170			$	26			$	192			$	45
Basic and diluted net income per common unit		$	0.66			$	0.48			$	1.24			$	0.84
Weighted average number of common units outstanding			255,777,452	(a)			52,777,452				154,838,225	(a)			52,777,452

See accompanying notes.

Williams Partners L.P.

		June 30,				December 31,
		2010				2009
		(Millions)
ASSETS
Current assets:
Cash and cash equivalents		$	218			$	153
Accounts receivable:
Trade			331				381
Affiliate			3				6
Inventories			170				129
Regulatory assets			66				77
Prepaid expense			53				26
Other current assets			55				49
Total current assets			896				821
Investments			589				593
Gross property, plant and equipment			15,668				15,416
Less accumulated depreciation			(5,415	)			(5,191	)
Property, plant and equipment — net			10,253				10,225
Regulatory assets, deferred charges and other			411				345
Total assets		$	12,149			$	11,984
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade		$	296			$	356
Affiliate			161				80
Accrued interest			124				49
Other accrued liabilities			154				136
Long-term debt due within one year			159				15
Total current liabilities			894				636
Long-term debt			6,073				2,981
Asset retirement obligations			477				477
Regulatory liabilities, deferred income and other			275				263
Contingent liabilities and commitments (Note 7)
Equity:
Common units (255,777,452 units outstanding at June 30, 2010 and 52,777,452 units outstanding at December 31, 2009)			5,388				1,631
General partner			(1,317	)			5,647
Accumulated other comprehensive income			13				2
Noncontrolling interests in consolidated subsidiaries			346				347
Total equity			4,430				7,627
Total liabilities and equity		$	12,149			$	11,984

See accompanying notes.

Williams Partners L.P.

		Williams Partners L.P.
														Accumulated Other
		Limited Partners								General				Comprehensive				Noncontrolling				Total
		Common				Class C				Partner				Income				Interests				Equity
		(Millions)
Balance — January 1, 2010		$	1,631			$	—			$	5,647			$	2			$	347			$	7,627
Comprehensive income:
Net income			167				156				204				—				11				538
Other comprehensive income:
Net unrealized income on cash flow hedges, net of reclassification adjustments			—				—				—				11				—				11
Total other comprehensive income																							11
Total comprehensive income																							549
Cash distributions			(68	)			(87	)			(34	)			—				—				(189	)
Dividends paid to noncontrolling interests			—				—				—				—				(12	)			(12	)
Issuance of units (203,000,000 Class C units)			—				6,946				(6,946	)			—				—				—
Distributions to The Williams Companies, Inc. — net			—				(3,357	)			(188	)			—				—				(3,545	)
Conversion of Class C units to Common (203,000,000 units)			3,658				(3,658	)			—				—				—				—
Balance — June 30, 2010		$	5,388			$	—			$	(1,317	)		$	13			$	346			$	4,430

See accompanying notes.

Williams Partners L.P.

		Six months ended June 30,
		2010				2009 *
		(Millions)
OPERATING ACTIVITIES:
Net income		$	538			$	398
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization			268				261
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			50				(51	)
Inventories			(41	)			10
Other assets and deferred charges			(10	)			(24	)
Accounts payable			5				52
Accrued liabilities			82				(49	)
Affiliates — net			84				(35	)
Other, including changes in noncurrent assets and liabilities			(9	)			75
Net cash provided by operating activities			967				637
FINANCING ACTIVITIES:
Proceeds from long-term debt			3,749				—
Payments of long-term debt			(513	)			—
Payment of debt issuance costs			(62	)			—
Dividends paid to noncontrolling interests			(12	)			(12	)
Distributions to limited partners and general partner			(189	)			(76	)
Distributions to the Williams Companies, Inc — net			(119	)			(59	)
Other — net			(8	)			(4	)
Net cash provided (used) by financing activities			2,846				(151	)
INVESTING ACTIVITIES:
Purchase of Contributed Entities			(3,426	)			—
Property, plant and equipment:
Capital expenditures			(339	)			(376	)
Net proceeds from dispositions			19				1
Changes in notes receivable from parent			—				(86	)
Purchase of investments			(15	)			(123	)
Distribution received from Gulfstream Natural Gas System, L.L.C.			—				73
Other — net			13				(7	)
Net cash used by investing activities			(3,748	)			(518	)
Increase (decrease) in cash and cash equivalents			65				(32	)
Cash and cash equivalents at beginning of period			153				133
Cash and cash equivalents at end of period		$	218			$	101

See accompanying notes.

Williams Partners L.P.

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 82 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us).

     The accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 8-K, dated May 12, 2010, for the year ended December 31, 2009. The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at June 30, 2010, results of operations for the three and six months ended June 30, 2010 and 2009, changes in equity for the six months ended June 30, 2010, and cash flows for the six months ended June 30, 2010 and 2009. We eliminated all intercompany transactions and reclassified certain amounts to conform to the current classifications.

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

     On May 24, 2010, we and Williams Pipeline Partners L.P. (WMZ) entered into a merger agreement (Merger Agreement) providing for the merger of WMZ into us (the Merger). The Merger and the Merger Agreement are described in detail in the Registration Statement on Form S-4 initially filed by us on June 9, 2010 and in our and WMZ’s joint proxy statement/prospectus dated July 15, 2010 that is being provided to holders of record of WMZ’s units at the close of business on July 15, 2010, who are the holders of WMZ’s units who will be entitled to vote on the Merger at the special meeting of WMZ’s unitholders scheduled for August 31, 2010. If the Merger is approved at that meeting, it is anticipated that the Merger will be consummated shortly thereafter, and all of WMZ’s units not already held by us will be exchanged for our units at an exchange ratio of 0.7584 of our units for each WMZ unit. Assuming the Merger is completed, we will own a 100 percent interest in Northwest Pipeline GP (Northwest Pipeline) and Williams will hold an approximate 80 percent interest in us, comprised of an approximate 78 percent limited partner interest and all of our 2 percent general partner interest.

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

Notes (Continued)

     This contribution was made in exchange for aggregate consideration of:

•

$3.5 billion in cash, less certain expenses incurred by us and other post-closing adjustments, which we financed by issuing $3.5 billion of senior unsecured notes (see Note 3).

•

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.

     These transactions are reflected in these consolidated financial statements. Because the acquired entities were affiliates of Williams at the time of the acquisition, this transaction is 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 $190 million and $354 million for the three and six months ended June 30, 2009, respectively. This acquisition did not impact historical earnings per limited partner unit as pre-acquisition earnings of the Contributed Entities were allocated to our general partner.

Description of Business

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

     Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline, which own and operates a combined total of approximately 13,900 miles of pipelines with a total annual throughput of approximately 2,700 TBtu of natural gas and peak-day delivery capacity of approximately 12 MMdt of natural gas. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5 percent interest in Gulfstream, which owns an approximate 745-mile pipeline with the capacity to transport approximately 1.26 million Dth per day of natural gas. Gas Pipeline also includes our indirect 45.7 percent limited partner interest and 2 percent general partner interest in WMZ, which holds the remaining 35 percent interest in Northwest Pipeline.

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

Notes (Continued)

Note 2. Allocation of Net Income and Distributions

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

		Three months ended								Six months ended
		June 30,								June 30,
		2010				2009				2010				2009
		(Millions)
Allocation of net income to general partner:
Net income		$	225			$	215			$	538			$	398
Net income applicable to pre-partnership operations allocated to general partner			—				(183	)			(163	)			(340	)
Net income applicable to noncontrolling interests			(5	)			(6	)			(11	)			(13	)
Net reimbursable costs charged directly to general partner			(2	)			1				(4	)			1
Income subject to 2% allocation of general partner interest			218				27				360				46
General partner’s share of net income			2.0	%			2.0	%			2.0	%			2.0	%
General partner’s allocated share of net income before items directly allocable to general partner interest			4				1				7				1
Incentive distributions paid to general partner*			30				—				30				7
Charges allocated directly to general partner			2				(1	)			4				(1	)
Pre-partnership net income allocated to general partner interest			—				183				163				340
Net income allocated to general partner		$	36			$	183			$	204			$	347
Net income		$	225			$	215			$	538			$	398
Net income allocated to general partner			36				183				204				347
Net income allocated to Class C limited partners			67				—				156				—
Net income allocated to noncontrolling interests			5				6				11				13
Net income allocated to common limited partners		$	117			$	26			$	167			$	38

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

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

     Total comprehensive income for the three months ended June 30, 2010 and 2009 is $248 million and $215 million, respectively, and for the six months ended June 30, 2010 and 2009 is $549 million and $397 million, respectively.

Notes (Continued)

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

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

Note 3. Debt and Banking Arrangements

Long-Term Debt

     As of June 30, 2010, our debt is unsecured with a weighted-average interest rate of 6.1 percent, payable through 2040. Interest rates range from 3.8 percent to 9.0 percent. Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, repurchase equity, and incur additional debt.

Revolving Credit and Letter of Credit Facility

     In connection with the Dropdown, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility with Transco and Northwest Pipeline as co-borrowers (Credit Facility). This Credit Facility replaced our unsecured $450 million credit facility, comprised of a $200 million revolving credit facility and a $250 million term loan, which was terminated as part of the Dropdown. At the closing, we utilized $250 million of the Credit Facility to repay the outstanding term loan. As of June 30, 2010, no loans are outstanding under the Credit Facility. The Credit Facility expires February 15, 2013, and may, under certain conditions, be increased by up to an additional $250 million. The full amount of the Credit Facility is available to us to the extent not otherwise utilized by Transco and Northwest Pipeline. Transco and Northwest Pipeline each have access to borrow up to $400 million under the Credit Facility to the extent not otherwise utilized by us. Each time funds are borrowed, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s adjusted base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. We are required to pay a commitment fee (currently 0.5 percent) based on the unused portion of the Credit Facility. The applicable margin and the commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. The Credit Facility contains various covenants that limit, among other things, a borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default and allow any material change in the nature of its business. Significant financial covenants under the Credit Facility include:

•

Our ratio of debt to EBITDA (each as defined in the Credit Facility) must be no greater than 5 to 1.

•

The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 55 percent for Transco and Northwest Pipeline.

Notes (Continued)

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

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

     At June 30, 2010, no loans are outstanding and no letters of credit are issued under the credit facility.

Issuances

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

		(Millions)
3.80% Senior Notes due 2015		$	750
5.25% Senior Notes due 2020			1,500
6.30% Senior Notes due 2040			1,250
Total		$	3,500

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

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

Note 4. Inventories

		June 30,				December 31,
		2010				2009
		(Millions)
Natural gas liquids		$	52			$	44
Natural gas in underground storage			51				20
Materials, supplies, and other			67				65
		$	170			$	129

Note 5. Fair Value Measurements

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

Notes (Continued)

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

•

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

•

Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. The instruments included in our Level 2 measurements consist primarily of over-the-counter instruments such as natural gas forward contracts and swaps.

•

Level 3 — Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments that are valued utilizing unobservable pricing inputs that are significant to the overall fair value.

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

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

		June 30, 2010																December 31, 2009
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
		(Millions)																(Millions)
Assets:
ARO Trust Investments (see Note 6)		$	33			$	—			$	—			$	33			$	22			$	—			$	—			$	22
Energy derivatives			—				3				20				23				—				—				2				2
Total assets		$	33			$	3			$	20			$	56			$	22			$	—			$	2			$	24
Liabilities:
Energy derivatives		$	—			$	5			$	—			$	5			$	—			$	—			$	2			$	2
Total liabilities		$	—			$	5			$	—			$	5			$	—			$	—			$	2			$	2

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

     The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit), and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

Notes (Continued)

     Forward and swap contracts included in Level 2 are valued using an income approach including present value techniques. Significant inputs into our Level 2 valuations include commodity prices and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

     The tenure of our derivatives portfolio is relatively short with all of our derivatives expiring by December 31, 2010. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.

     Certain instruments trade in less active markets with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. Certain inputs into the model are generally observable, such as interest rates, whereas natural gas liquids commodity prices are considered unobservable. The instruments included in Level 3 consist primarily of natural gas liquids swaps and forward contracts.

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

Level 3 Fair Value Measurements Using Significant Unobservable Inputs

		Net Energy Derivatives								Net Energy Derivatives
		Three months ended								Six months ended
		June 30,								June 30,
		2010				2009				2010				2009
		(Millions)								(Millions)
Beginning balance		$	4			$	1			$	—			$	1
Realized and unrealized gains (losses):
Included in net income			3				4				2				4
Included in other comprehensive income			16				—				21				—
Purchases, issuances, and settlements			(3	)			—				(3	)			—
Transfers into Level 3			—				—				—				—
Transfers out of Level 3			—				—				—				—
Ending balance		$	20			$	5			$	20			$	5
Unrealized gains (losses) included in net income relating to instruments still held at June 30		$	—			$	4			$	—			$	4

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

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

Notes (Continued)

Note 6. Financial Instruments, Derivatives and Concentrations of Credit Risk

Financial Instruments

Fair-value methods

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

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

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

     Long-term debt: The fair value of our publicly traded long-term debt is valued using indicative period-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings. At June 30, 2010 and December 31, 2009, approximately 44 percent and 91 percent, respectively, of our long-term debt was publicly traded. (See Note 3.)

     Other: Includes current and noncurrent notes receivable.

     Energy derivatives: Energy derivatives include forwards and swaps. These are carried at fair value in the Consolidated Balance Sheet. See Note 5 for discussion of valuation of our energy derivatives.

Carrying amounts and fair values of our financial instruments

		June 30, 2010								December 31, 2009
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
		(Millions)
Asset (Liability)
Cash and cash equivalents		$	218			$	218			$	153			$	153
ARO Trust Investments			33				33				22				22
Long-term debt, including current portion			(6,232	)			(6,582	)			(2,996	)			(3,194	)
Other			—				—				3				3
Net energy derivatives:
Energy commodity cash flow hedges — affiliate			17				17				(2	)			(2	)
Other energy derivatives			1				1				2				2

Energy Commodity Derivatives

Risk management activities

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

     We sell NGL volumes received as compensation for certain processing services at different locations throughout the United States. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs. To

Notes (Continued)

reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas market prices, we may enter into NGL or natural gas swap agreements, financial or physical forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas. These cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.

Volumes

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

•

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

•

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

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

Derivative Notional Volumes		Measurement		Fixed Price				Basis
Designated as Hedging Instruments
Midstream     Risk Management		MMBtu			11,460,000				7,615,000
Midstream     Risk Management		Gallons			(126,294,000	)
Not Designated as Hedging Instruments
Midstream     Risk Management		Gallons			(3,570,000	)

Fair values and gains (losses)

     The following table presents the fair value of energy commodity derivatives. Our derivatives are included in other current assets and other accrued liabilities in our Consolidated Balance Sheet. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur by December 31, 2010.

		June 30, 2010								December 31, 2009
		Assets				Liabilities				Assets				Liabilities
		(Millions)								(Millions)
Designated as hedging instruments		$	22			$	5			$	—			$	2
Not designated as hedging instruments			1				—				2				—
Total derivatives		$	23			$	5			$	2			$	2

Notes (Continued)

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

		Three months ended June 30,								Six months ended June 30,
		2010				2009				2010				2009				Classification
		(Millions)								(Millions)
Net gain recognized in other comprehensive income (effective portion)		$	20			$	—			$	14			$	—			AOCI
Net loss reclassified from accumulated other comprehensive income into income (effective portion)		$	(2	)		$	—			$	(4	)		$	—			Revenues
Gain (loss) recognized in income (ineffective portion)		$	—			$	—			$	—			$	—			Revenues

     There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness or as a result of reclassifications to earnings following the discontinuance of any cash flow hedges. As of June 30, 2010, we have hedged portions of future cash flows associated with anticipated NGL sales and natural gas purchases through December 31, 2010. Based on recorded values at June 30, 2010, net gains to be reclassified into earnings by December 31, 2010, are $17 million. These recorded values are based on market prices of the commodities as of June 30, 2010. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized by December 31, 2010, will likely differ from these values. These gains or losses will offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

     Gains recognized in revenues on our energy commodity derivatives not designated as hedging instruments were less than $1 million for the six months ended June 30, 2010 and $4 million for the six months ended June 30, 2009.

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

Credit-risk-related features

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

Guarantees

     In addition to the guarantees and payment obligations discussed in Note 7, we have issued guarantees and other similar arrangements as discussed below.

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

     At June 30, 2010, we do not expect these guarantees to have a material impact on our future liquidity or financial position. However, if we are required to perform on these guarantees in the future, it may have a material adverse effect on our results of operations.

Notes (Continued)

Note 7. Contingent Liabilities

Environmental Matters

     Since 1989, Transco has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At June 30, 2010, we had accrued liabilities of $4 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than $500,000, which is included in the environmental accrual discussed above. We expect that these costs will be recoverable through Transco’s rates.

     Beginning in the mid-1980s, Northwest Pipeline evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is conducting additional remediation activities at certain sites to comply with Washington’s current environmental standards. At June 30, 2010, we have accrued liabilities of $7 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

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

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

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

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

Notes (Continued)

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

     We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At June 30, 2010, we have accrued liabilities totaling $7 million for these costs.

     Summary of environmental matters

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

Rate Matters

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

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

Safety Matters

     The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration rules implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, including more frequent inspections and other safeguards in areas where the potential consequences of pipeline accidents pose the greatest risk to people and property. In accordance with the final rule, Transco and Northwest Pipeline developed Integrity Management Plans, identified high consequence areas, completed baseline assessment plans, and are on schedule to complete the required assessments within specified timeframes. Currently, Transco and Northwest Pipeline estimate that the cost to perform required assessments and remediation will be primarily capital and range between $140 and $200 million, and between $80 and $95 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.

Other Legal Matters

     Will Price (formerly Quinque)

     In 2001, we were named, along with other subsidiaries of Williams, as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants opposed class certification, and on September 18, 2009, the court denied plaintiffs’ most recent motion to certify the class. On October 2, 2009, the plaintiffs filed a motion for reconsideration of the denial. On March 31, 2010, the court entered an order denying plaintiffs’ motion for reconsideration and as a result, there are no class action allegations remaining in the case.

Notes (Continued)

Other

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

Summary

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

Note 8. Segment Disclosures

     Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. WMZ is consolidated within the Gas Pipeline segment. (See Note 1.)

Performance Measurement

     We currently evaluate segment operating performance based on segment profit from operations, which includes segment revenues from external and internal customers, segment costs and expenses, and equity earnings. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

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

•

Gas Pipeline — depreciation and operation and maintenance expenses;

•

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

Notes (Continued)

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

		Gas Pipeline				Midstream				Eliminations				Total
		(Millions)
Three months ended June 30, 2010
Segment revenues:
External		$	380			$	987			$	—			$	1,367
Internal			—				—				—				—
Total revenues		$	380			$	987			$	—			$	1,367
Segment profit		$	148			$	198			$	—			$	346
Less equity earnings			10				17				—				27
Segment operating income		$	138			$	181			$	—				319
General corporate expenses															(28	)
Total operating income														$	291
Three months ended June 30, 2009*
Segment revenues:
External		$	420			$	661			$	—			$	1,081
Internal			1				2				(3	)			—
Total revenues		$	421			$	663			$	(3	)		$	1,081
Segment profit		$	155			$	130			$	—			$	285
Less equity earnings			8				8				—				16
Segment operating income		$	147			$	122			$	—				269
General corporate expenses															(26	)
Total operating income														$	243

		Gas Pipeline				Midstream				Eliminations				Total
		(Millions)
Six months ended June 30, 2010
Segment revenues:
External		$	787			$	2,038			$	—			$	2,825
Internal			—				—				—				—
Total revenues		$	787			$	2,038			$	—			$	2,825
Segment profit		$	317			$	443			$	—			$	760
Less equity earnings			19				34				—				53
Segment operating income		$	298			$	409			$	—				707
General corporate expenses															(62	)
Total operating income														$	645
Six months ended June 30, 2009*
Segment revenues:
External		$	822			$	1,216			$	—			$	2,038
Internal			—				5				(5	)			—
Total revenues		$	822			$	1,221			$	(5	)		$	2,038
Segment profit		$	327			$	210			$	—			$	537
Less equity earnings			16				5				—				21
Segment operating income		$	311			$	205			$	—				516
General corporate expenses															(51	)
Total operating income														$	465

Notes (Continued)

Note 9. Subsequent Event

     In July 2010, we notified our partner in the Overland Pass Pipeline Company, LLC (OPPL) of our election to exercise our option to purchase an additional ownership interest, which will provide us a 50 percent ownership interest in OPPL. The option price is estimated to be approximately $425 million, which will reduce our available liquidity. Subject to government approvals, we expect to close the transaction within the third quarter of 2010.

Item 2

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

Recent Developments

The Dropdown

     On February 17, 2010, we closed a transaction with our general partner, our operating company, The Williams Companies, Inc. (Williams) and certain subsidiaries of Williams, pursuant to which Williams contributed to us the ownership interests in the entities that made up Williams’ Gas Pipeline and Midstream 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 Williams’ Canadian, Venezuelan, and olefin operations and 25.5 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream). Such entities are hereafter referred to as the “Contributed Entities.” This contribution was made in exchange for aggregate consideration of:

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

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

WMZ Exchange Offer

     On May 24, 2010, we entered into a merger agreement with WMZ (Merger Agreement) providing for the merger of WMZ into us (the Merger). The Merger and the Merger Agreement are described in detail in our Registration Statement on Form S-4 initially filed on June 9, 2010, and in WMZ’s and our joint proxy statement/prospectus dated July 15, 2010, that is being provided to holders of record of WMZ’s units at the close of business on July 15, 2010, who are the holders of WMZ’s units who will be entitled to vote on the Merger at the special meeting of WMZ’s unitholders scheduled for August 31, 2010. If the Merger is approved at that meeting, it is anticipated that the Merger will be consummated shortly thereafter, and all of WMZ’s units not already held by us will be exchanged at a ratio of 0.7584 of our units for each WMZ unit. Assuming the Merger is completed, we will own a 100 percent interest in Northwest Pipeline GP (Northwest Pipeline), and Williams will hold an approximate 80 percent interest in us, comprised of an approximate 78 percent limited partner interest and all of our 2 percent general partner interest.

Credit Facility

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

Management’s Discussion and Analysis (Continued)

Overland Pass Pipeline

     In July 2010, we notified our partner in the Overland Pass Pipeline Company, LLC (OPPL) of our election to exercise our option to purchase an additional ownership interest, which will provide us a 50 percent ownership interest in OPPL. The option price is estimated to be approximately $425 million. (See Results of Operations — Segments, Midstream Gas & Liquids.)

Overview

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

	•		Gas Pipeline includes Transco and a 65 percent interest in Northwest Pipeline, which own and operate a combined total of approximately 13,900 miles of pipelines with a total annual throughput of approximately 2,700 trillion British thermal units (TBtu) of natural gas and peak-day delivery capacity of approximately 12 million dekatherms (MMdt) of natural gas. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5 percent interest in Gulfstream, which owns an approximate 745-mile pipeline with the capacity to transport approximately 1.26 MMdt per day of natural gas.
	•		Midstream includes natural gas gathering, processing and treating facilities, and crude oil gathering and transportation facilities with primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, and Pennsylvania.

Company Outlook

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

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

     We continue to invest in our businesses in a way that meets customer needs and enhances our competitive position by:

	•		Continuing to invest in and grow our gathering and processing and interstate natural gas pipeline systems;
	•		Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

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

	•		Lower than anticipated commodity prices;
	•		Lower than expected levels of cash flow from operations;
	•		Availability of capital;
	•		Counterparty credit and performance risk;

Management’s Discussion and Analysis (Continued)

	•		Decreased volumes from third parties served by our midstream business;
	•		General economic, financial markets, or industry downturn;
	•		Changes in the political and regulatory environments;
	•		Physical damages to facilities, especially damage to offshore facilities by named windstorms for which our aggregate insurance policy limit is $75 million in the event of a material loss.

     We continue to address these risks through utilization of commodity hedging strategies, disciplined investment strategies, and maintaining ample liquidity from cash and cash equivalents and unused revolving credit facility capacity.

Fair Value Measurements

     Certain of our energy derivative assets and energy derivative liabilities trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. At June 30, 2010, 87 percent of our energy derivative assets and none of our energy derivative liabilities measured at fair value on a recurring basis are included in Level 3. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.

     The determination of fair value for our energy derivative assets and our energy derivative liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At June 30, 2010, the credit reserve is significantly less than $1 million on both our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.

     Our entire derivatives portfolio expires by December 31, 2010. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.

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

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

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

     The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2010, compared to the three and six months ended June 30, 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

		Three months ended																Six months ended
		June 30,																June 30,
		2010				2009				$				%				2010				2009				$				%
		(Millions)								Change*				Change*				(Millions)								Change*				Change*
Revenues		$	1,367			$	1,081				+ 286				+26	%		$	2,825			$	2,038				+ 787				+39	%
Costs and expenses:
Costs and operating expenses			987				738				- 249				-34	%			2,001				1,381				- 620				-45	%
Selling, general and administrative expenses			68				71				+ 3				+4	%			127				141				+ 14				+10	%
Other (income) expense — net			(7	)			3				+ 10				NM				(10	)			—				+ 10				NM
General corporate expenses			28				26				- 2				-8	%			62				51				- 11				-22	%
Total costs and expenses			1,076				838												2,180				1,573
Operating income			291				243												645				465
Equity earnings			27				16				+ 11				+69	%			53				21				+ 32				+152	%
Interest accrued — net			(95	)			(50	)			- 45				-90	%			(164	)			(101	)			- 63				-62	%
Interest income			—				6				- 6				-100	%			3				11				- 8				-73	%
Other income — net			2				2				—				0	%			1				5				- 4				-80	%
Income before income taxes			225				217												538				401
Provision for income taxes			—				2				+ 2				+100	%			—				3				+ 3				+100	%
Net Income			225				215												538				398
Less: Net income attributable to noncontrolling interests			5				6				+ 1				+17	%			11				13				+ 2				+15	%
Net income attributable to controlling interests		$	220			$	209											$	527			$	385