Edgar Filing: Williams Partners L.P.

Form 10-Q

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

For the quarterly period ended September 30, 2011

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

For the transition period from to

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, including area code: (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 ¨

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 ¨

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 ¨ Non-accelerated filer ¨ (Do not check if a smaller reporting company) 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 ¨ No þ

The registrant had 290,477,159 common units outstanding as of November 1, 2011.

Williams Partners L.P.

Index


	Page
Part I. Financial Information

Item 1. Financial Statements

Consolidated Statement of Income —Three and Nine Months Ended September 30, 2011 and 2010		3

Consolidated Balance Sheet – September 30, 2011 and December 31, 2010		4

Consolidated Statement of Changes in Equity – Nine Months Ended September 30, 2011		5

Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2011 and 2010		6

Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19

Item 3. Quantitative and Qualitative Disclosures About Market Risk		37

Item 4. Controls and Procedures		38

Part II. Other Information		38

Item 1. Legal Proceedings		38

Item 1A. Risk Factors		39

Item 6. Exhibits		40

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 cash distributions 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 climate change regulation 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;

•

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, 2010, and Part II, Item 1A. Risk Factors of this Form 10-Q.

PART I – FINANCIAL INFORMATION

Williams Partners L.P.

Consolidated Statement of Income

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
	(Millions, except per-unit amounts)
Revenues:
Gas Pipeline	$	429		$	409		$	1,252		$	1,196
Midstream Gas & Liquids		1,244			918			3,671			3,021

Total revenues		1,673			1,327			4,923			4,217
Segment costs and expenses:
Costs and operating expenses		1,169			923			3,437			2,958
Selling, general, and administrative expenses		69			70			216			202
Other (income) expense – net		4			(13	)		(8	)		(22	)

Segment costs and expenses		1,242			980			3,645			3,138
General corporate expenses		29			30			86			93

Operating income:
Gas Pipeline		153			151			457			449
Midstream Gas & Liquids		278			196			821			630
General corporate expenses		(29	)		(30	)		(86	)		(93	)

Total operating income		402			317			1,192			986
Equity earnings		40			24			101			77
Interest accrued		(105	)		(103	)		(320	)		(286	)
Interest capitalized		3			7			8			26
Interest income		—			—			1			3
Other income (expense) – net		2			8			5			9

Net income		342			253			987			815
Less: Net income attributable to noncontrolling interests		—			5			—			16

Net income attributable to controlling interests	$	342		$	248		$	987		$	799

Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests	$	342		$	248		$	987		$	799
Allocation of net income to general partner and Class C units		79			85			224			444

Allocation of net income to common units	$	263		$	163		$	763		$	355

Basic and diluted net income per common unit	$	0.91		$	0.63		$	2.63		$	1.87
Weighted average number of common units outstanding (thousands)		290,477			260,508			290,181			190,448
Cash distributions per common unit	$	0.7475		$	0.6875		$	2.1975		$	2.0175

See accompanying notes.

Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)


	September 30, 2011			December 31, 2010
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	143		$	187
Accounts and notes receivable:
Trade		460			404
Affiliate		6			8
Inventories		160			195
Regulatory assets		42			51
Other current assets		70			53

Total current assets		881			898
Investments		1,341			1,045
Gross property, plant, and equipment		17,418			16,707
Less accumulated depreciation		(6,061	)		(5,706	)

Property, plant, and equipment – net		11,357			11,001
Regulatory assets, deferred charges, and other		468			460

Total assets	$	14,047		$	13,404


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	453		$	322
Affiliate		86			154
Accrued interest		101			105
Other accrued liabilities		229			174
Long-term debt due within one year		333			458

Total current liabilities		1,202			1,213
Long-term debt		6,815			6,365
Asset retirement obligations		506			460
Regulatory liabilities, deferred income, and other		400			290
Contingent liabilities (Note 8)
Equity:
Common units (290,477,159 units outstanding at September 30, 2011 and 289,844,575 units outstanding at December 31, 2010)		6,715			6,564
General partner		(1,586	)		(1,485	)
Accumulated other comprehensive income (loss)		(5	)		(3	)

Total equity		5,124			5,076

Total liabilities and equity	$	14,047		$	13,404

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Changes in Equity

(Unaudited)

		000000000000			000000000000			000000000000			000000000000
	Common Units			General Partner			Accumulated Other Comprehensive Income (Loss)			Total Equity
	(Millions)
Balance – January 1, 2011	$	6,564		$	(1,485	)	$	(3	)	$	5,076
Comprehensive income:
Net income		776			211			—			987
Other comprehensive loss:
Net change in cash flow hedges		—			—			(2	)		(2	)

Total other comprehensive loss											(2	)

Total comprehensive income											985

Cash distributions		(625	)		(205	)		—			(830	)
Excess of purchase price over contributed basis of the investment in Gulfstream Natural Gas System, L.L.C.		—			(123	)		—			(123	)
Other		—			16			—			16

Balance – September 30, 2011	$	6,715		$	(1,586	)	$	(5	)	$	5,124

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)


	Nine months ended September 30,
	2011			2010
	(Millions)
OPERATING ACTIVITIES:
Net income	$	987		$	815
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization		459			420
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		(56	)		40
Inventories		35			(31	)
Other assets and deferred charges		(8	)		9
Accounts payable		73			(4	)
Accrued liabilities		51			91
Affiliate accounts receivable and payable – net		(66	)		67
Other, including changes in noncurrent assets and liabilities		42			5

Net cash provided by operating activities		1,517			1,412


FINANCING ACTIVITIES:
Proceeds from long-term debt		1,023			4,179
Payments of long-term debt		(700	)		(953	)
Payment of debt issuance costs		(12	)		(62	)
Proceeds from sales of common units		—			380
General partner contributions		16			20
Dividends paid to noncontrolling interests		—			(18	)
Distributions to limited partners and general partner		(830	)		(410	)
Excess of purchase price over contributed basis of the investment in Gulfstream Natural Gas System, L.L.C.		(123	)		—
Distributions to The Williams Companies, Inc. – net		—			(191	)
Other – net		2			(6	)

Net cash provided (used) by financing activities		(624	)		2,939


INVESTING ACTIVITIES:
Purchase of business and investments from affiliates		(174	)		(3,426	)
Property, plant and equipment:
Capital expenditures		(598	)		(587	)
Net proceeds from dispositions		—			65
Purchases of business and investments		(171	)		(450	)
Other – net		6			(14	)

Net cash used by investing activities		(937	)		(4,412	)

Increase (decrease) in cash and cash equivalents		(44	)		(61	)
Cash and cash equivalents at beginning of period		187			153

Cash and cash equivalents at end of period	$	143		$	92

See accompanying notes.

Williams Partners L.P.

Notes to Consolidated Financial Statements

(Unaudited)

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

Organization

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

We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of September 30, 2011, Williams owns an approximate 73 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 for the year ended December 31, 2010 in our Annual report on Form 10-K. The accompanying unaudited consolidated financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2011, results of operations for the three and nine months ended September 30, 2011 and 2010, changes in equity for the nine months ended September 30, 2011, and cash flows for the nine months ended September 30, 2011 and 2010.

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.

Basis of Presentation

In May 2011, we closed the acquisition of a 24.5 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream) from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. As the acquired equity interest was purchased from a subsidiary of Williams, the transaction was accounted for as a combination of entities under common control whereby the investment acquired is combined with ours at its historical amount as of the date of transfer. The excess of the cash purchase price over the historical carrying amount is recognized as a reduction of general partner equity. This investment is reported in our Gas Pipeline segment.

In November 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). As the acquired assets were purchased from a subsidiary of Williams, the transaction was accounted for as a combination of entities under common control whereby the assets and liabilities acquired are combined with ours at their historical amounts. The acquired assets are reported in our Midstream Gas & Liquids (Midstream) segment, which includes a recast of the statement of income for the prior period. The effect of recasting our financial statements to account for this transaction increased net income by $27 million for the three months and $51 million for the nine months ended September 30, 2010. This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.

Accounting Standards Issued But Not Yet Adopted

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-4, “Fair Value Measurement (Topic 820) Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (ASU 2011-4). ASU 2011-4 primarily eliminates the

Notes (Continued)

differences in fair value measurement principles between the FASB and International Accounting Standards Board. It clarifies existing guidance, changes certain fair value measurements and requires expanded disclosure primarily related to Level 3 measurements and transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-4 is effective on a prospective basis for interim and annual periods beginning after December 15, 2011. We are assessing the application of this Update to our Consolidated Financial Statements.

In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5). ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. The Update requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income. The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. We currently report net income in the Consolidated Statement of Income and report other comprehensive income in the Consolidated Statement of Changes in Equity. The standard is effective beginning the first quarter of 2012, with a retrospective application to prior periods. We plan to apply the new presentation beginning in 2012.

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 49 percent equity interest in Gulfstream, an interstate natural gas pipeline extending from the Mobile Bay area in Alabama to markets in Florida.

Midstream is comprised primarily of

•

Large-scale natural gas gathering, processing and treating facilities in the Rocky Mountain, Four Corners, Piceance basin, and Pennsylvania’s Marcellus Shale regions;

•

Offshore deepwater oil and natural gas production platforms, gathering and transportation facilities in the Gulf of Mexico, as well as significant natural gas gathering, processing and treating facilities on the Gulf Coast;

•

A natural gas liquid (NGL) fractionator and storage facilities near Conway, Kansas;

•

Various equity investments in domestic natural gas gathering and processing assets and NGL fractionation and transportation assets.

Notes (Continued)

Note 2. Allocation of Net Income and Distributions

The allocation of net income among our general partner, limited partners, and noncontrolling interests for the three and nine months ended September 30, 2011 and 2010, is as follows:

		000000000			000000000			000000000			000000000
	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
	(Millions)
Allocation of net income to general partner:
Net income	$	342		$	253		$	987		$	815
Net income applicable to pre-partnership operations allocated to general partner		—			(27	)		—			(214	)
Net income applicable to noncontrolling interests		—			(5	)		—			(16	)
Net reimbursable costs charged directly to general partner		—			—			(2	)		(4	)

Income subject to 2% allocation of general partner interest		342			221			985			581
General partner’s share of net income		2	%		2	%		2	%		2	%

General partner’s allocated share of net income before items directly allocable to general partner interest		7			4			20			11
Incentive distributions paid to general partner^*		67			45			189			75
Net reimbursable costs charged directly to general partner		—			—			2			4
Pre-partnership net income allocated to general partner interest		—			27			—			214

Net income allocated to general partner	$	74		$	76		$	211		$	304

Net income	$	342		$	253		$	987		$	815
Net income allocated to general partner		74			76			211			304
Net income allocated to Class C limited partners		—			—			—			156
Net income allocated to noncontrolling interests		—			5			—			16

Net income allocated to common limited partners	$	268		$	172		$	776		$	339

In the calculation of basic and diluted net income per limited partner unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period, but paid in the subsequent period. The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period.

The net reimbursable costs charged directly to general partner may include the net of both income and expense items. Under the terms of omnibus agreements, we are reimbursed by our general partner for certain expense items and are required to distribute certain income items to our general partner.

Total comprehensive income for the three months ended September 30, 2011 and 2010 is $340 million and $230 million, respectively, and for the nine months ended September 30, 2011 and 2010 is $985 million and $803 million, respectively. Any difference between total comprehensive income and net income for all periods is due to net changes in cash flow hedges.

Notes (Continued)

We paid or have authorized payment of the following partnership cash distributions during 2010 and 2011 (in millions, except for per unit amounts):


							General Partner
Payment Date	Per Unit Distribution		Common Units		Class C Units		2%		Incentive Distribution Rights		Total Cash Distribution
2/12/2010	$	0.6350	$	33	$	—	$	1	$	—	$	34
5/14/2010	$	0.6575	$	35	$	87	$	3	$	30	$	155
8/13/2010	$	0.6725	$	172	$	—	$	4	$	45	$	221
11/12/2010	$	0.6875	$	192	$	—	$	5	$	53	$	250
2/11/2011	$	0.7025	$	204	$	—	$	5	$	59	$	268
5/13/2011	$	0.7175	$	208	$	—	$	5	$	63	$	276
8/12/2011	$	0.7325	$	213	$	—	$	6	$	67	$	286
11/11/2011(a)	$	0.7475	$	217	$	—	$	6	$	71	$	294

(a)	The Board of Directors of our general partner declared this cash distribution on October 24, 2011, to be paid on November 11, 2011, to unitholders of record at the close of business on November 4, 2011.

Note 3. Asset Sales and Other Accruals

The following table presents significant gains or losses from asset sales and other accruals or adjustments reflected in other (income) expense – net within segment costs and expenses.


	Three months ended					Nine months ended
	September 30,					September 30,
	2011		2010			2011			2010
	(Millions)
Gas Pipeline
Capitalization of project feasibility costs previously expensed	$	—	$	—		$	(10	)	$	—
Midstream
Involuntary conversion gains		—		(7	)		—			(18	)
Gain on sale of certain assets		—		(12	)		—			(12	)

The reversal of project feasibility costs from expense to capital in 2011 at Gas Pipeline is associated with a natural gas pipeline expansion project. This reversal was made upon determining that the related project was probable of development. These costs will be included in the capital costs of the project, which we believe are probable of recovery through the project rates.

Additional Item

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. During the three and nine months ended September 30, 2011, we recorded $6 million and $13 million, respectively, of charges to costs and operating expenses at Gas Pipeline primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.

Note 4. Inventories


	September 30,		December 31,
	2011		2010
	(Millions)
Natural gas liquids	$	70	$	61
Natural gas in underground storage		24		62
Materials, supplies, and other		66		72

	$	160	$	195

Notes (Continued)

Note 5. Debt and Banking Arrangements

Credit Facility

In June 2011, we entered into a new $2 billion five-year senior unsecured revolving credit facility agreement with Transco and Northwest Pipeline as co-borrowers. The new agreement is considered a modification for accounting purposes. It replaced our existing $1.75 billion credit facility agreement that was scheduled to expire on February 17, 2013. At the closing, we refinanced $300 million outstanding under the existing facility via a non-cash transfer of the obligation to the new credit facility. The new credit facility may, under certain conditions, be increased up to an additional $400 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 the other co-borrowers. Significant financial covenants include:

•

Our ratio of debt to EBITDA (each as defined in the credit facility) must be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1;

•

The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline.

At September 30, 2011, we are in compliance with these financial covenants.

Each time funds are borrowed, a 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. We are required to pay a commitment fee (currently 0.25 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. The credit facility contains various covenants that may limit, among other things, a borrower’s and its respective material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business.

The new 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 and exercise other rights and remedies.

Letter of credit capacity under our new credit facility is $1.3 billion. At September 30, 2011, no letters of credit have been issued and $400 million in loans are outstanding under the credit facility.

Issuances and Retirements

Utilizing cash on hand, we retired $150 million of 7.5 percent senior unsecured notes that matured on June 15, 2011.

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. A portion of these proceeds were used to repay Transco’s $300 million 7 percent senior unsecured notes that matured on August 15, 2011. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco is obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing and to use commercially reasonable efforts to

Notes (Continued)

cause the registration statement to be declared effective within 270 days after closing and to consummate the exchange offer within 30 business days after such effective date. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

Note 6. Fair Value Measurements

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


	September 30, 2011								December 31, 2010
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)
Assets:
ARO Trust investments (see Note 7)	$	27	$	—	$	—	$	27	$	40	$	—	$	—	$	40
Energy derivatives		—		4		—		4		—		—		—		—

Total assets	$	27	$	4	$	—	$	31	$	40	$	—	$	—	$	40

Liabilities:
Energy derivatives	$	—	$	8	$	—	$	8	$	—	$	—	$	—	$	—

Total liabilities	$	—	$	8	$	—	$	8	$	—	$	—	$	—	$	—

The instruments included in our Level 1 measurements consist of a portfolio of mutual funds. (See Note 7.)

The instruments included in our Level 2 measurements consist primarily of over-the-counter (OTC) instruments such as natural gas and NGL swaps. 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.

Certain instruments trade 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 because these inputs have a significant impact on the measurement of fair value. As of September 30, 2011 and December 31, 2010, we do not have any instruments classified as Level 3.

The tenure of our energy derivatives portfolio is relatively short with all of our derivatives expiring by March 31, 2012. 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.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the period ended September 30, 2011 or 2010.

The following table presents a reconciliation of changes in the fair value of our net energy derivatives classified as Level 3 in the fair value hierarchy.

Notes (Continued)

Level 3 Fair Value Measurements Using Significant Unobservable Inputs


	Three months ended September 30,					Nine months ended September 30,
	2011		2010			2011			2010
	(Millions)
Beginning balance	$	—	$	20		$	—		$	—
Realized and unrealized gains (losses):
Included in net income		—		8			—			10
Included in other comprehensive income (loss)		—		(20	)		(5	)		1
Settlements		—		(9	)		—			(12	)
Transfers into Level 3		—		—			—			—
Transfers out of Level 3		—		—			5			—

Ending balance	$	—	$	(1	)	$	—		$	(1	)

Unrealized gains (losses) included in net income relating to instruments still held at September 30	$	—	$	—		$	—		$	—

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

For the nine months ended September 30, 2011 and 2010, there were no assets or liabilities measured at fair value on a nonrecurring basis.

Note 7. Financial Instruments, Derivatives, and Guarantees

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 determined using indicative period-end traded bond market prices. The fair value of our private debt is based on market rates and the prices of similar securities with similar terms and credit ratings. At September 30, 2011 and December 31, 2010, approximately 89 percent and 100 percent, respectively, of our long-term debt was publicly traded. (See Note 5.)

Other: Includes current and noncurrent notes receivable and margin deposits.

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

Notes (Continued)

Carrying amounts and fair values of our financial instruments


	September 30, 2011						December 31, 2010
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(Millions)
Asset (Liability)
Cash and cash equivalents	$	143		$	143		$	187		$	187
ARO Trust investments	$	27		$	27		$	40		$	40
Long-term debt, including current portion	$	(7,148	)	$	(7,815	)	$	(6,823	)	$	(7,283	)
Other	$	10		$	10		$	—		$	—
Energy commodity cash flow hedges	$	(4	)	$	(4	)	$	—		$	—

Energy Commodity Derivatives

Risk management activities

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

We sell NGL volumes received as compensation for certain processing services at different locations throughout the United States. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas market prices, we may enter into NGL or natural gas swap agreements, financial or physical forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas. Those designated as 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:

•

Central hub risk: Financial derivative exposures to Henry Hub for natural gas and Mont Belvieu for NGLs;

•

Basis risk: Financial derivative exposures to the difference in value between the central hub and another specific delivery point.

The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of September 30, 2011. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLs are presented in barrels.

Unit of

Central Hub

Derivative Notional Volumes

Measurement

Risk

Basis Risk

Designated as Hedging Instruments

Midstream Risk Management

MMBtu

5,060,000

4,370,000

Midstream Risk Management

Barrels

(1,380,000

)

Not Designated as Hedging Instruments

Midstream Risk Management

Barrels

105,000

Notes (Continued)

Fair values and gains (losses)

The following table presents the fair value of energy commodity derivatives. Our derivatives are included in other current assets and other accrued liabilities in our 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 within the next 12 months.


	September 30, 2011				December 31, 2010
	Assets		Liabilities		Assets		Liabilities
	(Millions)				(Millions)
Designated as hedging instruments	$	4	$	8	$	—	$	—
Not designated as hedging instruments		—		—		—		—

Total derivatives	$	4	$	8	$	—	$	—

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


	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010			Classification
	(Millions)						(Millions)
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	(8	)	$	(20	)	$	(14	)	$	(6	)		AOCI
Net gain (loss) reclassified from accumulated othercomprehensive income (loss) into income (effective portion)	$	(6	)	$	4		$	(10	)	$	—			Revenues or Costs and Operating Expenses
Gain (loss) recognized in income (ineffective portion)	$	—		$	—		$	—		$	—			Revenues or Costs and Operating Expenses

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness or as a result of reclassifications to earnings following the discontinuance of any cash flow hedges. As of September 30, 2011, we have hedged portions of future cash flows associated with anticipated NGL sales and natural gas purchases through 2011. Based on recorded values at September 30, 2011, net losses to be reclassified into earnings by December 31, 2011, are $4 million. These recorded values are based on market prices of the commodities as of September 30, 2011. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized by December 31, 2011, 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. There are no designated derivative contracts that expire beyond December 31, 2011.

We recognized losses of $1 million and less than $1 million in revenues for the nine months ended September 30, 2011 and 2010, respectively, on our energy commodity derivatives not designated as hedging instruments.

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

The majority of our financial swap contracts are with our affiliate, WPX Energy Marketing, LLC, and the derivative contracts not designated as cash flow hedging instruments are primarily NGL swaps. These agreements do not contain any provisions that require us to post collateral related to net liability positions.

Notes (Continued)

Guarantees

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

At September 30, 2011, 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 an adverse effect on our results of operations.

Note 8. Contingent Liabilities

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. As of September 30, 2011, we have accrued liabilities totaling $19 million for these matters, as discussed below. Our estimated costs reflect the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Actual costs 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. As a result, any incremental amount cannot be reasonably estimated at this time.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide emission limits. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyl, mercury contamination, and other hazardous substances. These activities have involved the EPA, various state environmental authorities and identification as a potentially responsible party at various Superfund waste sites. At September 30, 2011, we have accrued liabilities of $11 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2011, we have accrued liabilities totaling $8 million for these costs.

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

Notes (Continued)

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. If the FERC were to reverse their opinion on rehearing, we believe any refunds would not be material to our results of operations.

Safety Matters

Transco and Northwest Pipeline have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, they have identified high consequence areas and developed baseline assessment plans. They are on schedule to complete the required assessments within required timeframes. Currently, we estimate the cost to complete the required initial assessments over the period of 2011 through 2012 and associated remediation will be primarily capital in nature and range between $80 million and $110 million for Transco and between $65 million and $75 million for Northwest Pipeline. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. 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 our rates.

Other

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

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties. We disclose all significant matters for which we are unable to reasonably estimate a range of possible loss.

Litigation, arbitration, regulatory matters, environmental matters, and safety matters are subject to inherent uncertainties and there always exists uncertainty about our future results of operations. As a result, if an unforeseen, unfavorable event occurred, there exists the possibility of a material adverse impact on the results of operations in the period in which the event occurs. Management, including internal counsel, currently believes that the ultimate resolution of these matters, taken as a whole, will not have a material adverse effect upon our future liquidity or financial position. In certain circumstances, we may be eligible for insurance recoveries, or reimbursements from others. Any such recoveries or reimbursements will be recognized only when realizable.

Note 9. Segment Disclosures

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

Performance Measurement

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

Notes (Continued)

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.

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		Total
	(Millions)
*Three months ended September 30, 2011*
Segment revenues	$	429	$	1,244	$	1,673

Segment profit	$	170	$	301	$	471
Less equity earnings		17		23		40

Segment operating income	$	153	$	278		431

General corporate expenses						(29	)

Total operating income					$	402

*Three months ended September 30, 2010*
Segment revenues	$	409	$	918	$	1,327

Segment profit	$	161	$	210	$	371
Less equity earnings		10		14		24

Segment operating income	$	151	$	196		347

General corporate expenses						(30	)

Total operating income					$	317

*Nine months ended September 30, 2011*
Segment revenues	$	1,252	$	3,671	$	4,923

Segment profit	$	497	$	882	$	1,379
Less equity earnings		40		61		101

Segment operating income	$	457	$	821		1,278

General corporate expenses						(86	)

Total operating income					$	1,192

*Nine months ended September 30, 2010*
Segment revenues	$	1,196	$	3,021	$	4,217

Segment profit	$	478	$	678	$	1,156
Less equity earnings		29		48		77

Segment operating income	$	449	$	630		1,079

General corporate expenses						(93	)

Total operating income					$	986

Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

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 & Liquids (Midstream).

•

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. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 49 percent interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), which owns an approximate 745-mile pipeline.

•

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.

As of September 30, 2011, The Williams Companies, Inc. (Williams) holds an approximate 75 percent interest in us, comprised of an approximate 73 percent limited partner interest and all of our 2 percent general partner interest.

Overview of Nine Months Ended September 30, 2011

Net Income for the nine months ended September 30, 2011, changed favorably by $172 million compared to the nine months ended September 30, 2010, primarily due to improved natural gas liquids (NGL) margins partially offset by higher interest expense associated with increased debt levels in conjunction with the 2010 contribution of subsidiaries from our general partner. (See Results of Operations – Consolidated Overview.)

Our net cash provided by operating activities for the nine months ended September 30, 2011, increased $105 million compared to the nine months ended September 30, 2010, primarily due to higher operating income partially offset by net unfavorable changes in working capital including the timing of settling certain affiliate balances.

Recent Events

In May 2011, we closed the acquisition of a 24.5 percent interest in Gulfstream from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. As the acquired equity interest was purchased from a subsidiary of Williams, the transaction was accounted for as a combination of entities under common control whereby the investment acquired is combined with ours at its historical amount as of the date of transfer. This investment is reported in our Gas Pipeline segment.

In October 2011, we executed an agreement with two significant producers to provide certain production handling services in the eastern deepwater Gulf of Mexico. We will design, construct and install a floating production system (Gulfstar FPS™) that will have the capacity to handle 60 thousand barrels per day (Mbbls/d) of oil, up to 200 million cubic feet per day (MMcf/d) of natural gas, and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be placed into service in 2014 and to be capable of serving as a central host facility for other deepwater prospects in the area. We may consider a joint venture partner for this project.

In the months of April, July, and October of 2011, our general partner’s Board of Directors approved a 2 percent increase in our quarterly distribution to unitholders. (See Management’s Discussion and Analysis of Financial Condition and Liquidity.)

During the second quarter of 2011, Williams became a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company which shares losses among its members. In addition to certain property insurance coverages, Williams also purchased named windstorm coverage from OIL. The OIL named windstorm insurance provides coverage up to $150 million per occurrence (60 percent of $250 million of losses in excess of $100 million), with an annual aggregate limit of $300 million and subject to a per-event shared limit aggregate of $750 million for all members.

Company Outlook

We believe we are well-positioned to continue to execute on our 2011 business plan and to capture attractive growth opportunities. Through the nine months ended September 30, 2011, we have experienced increases in our operating results over 2010 primarily due to continued strong per-unit NGL margins in our Midstream business in relation to five-year averages and our significant 2010 growth capital investments. Although energy prices and the broader economy have declined in the third quarter of 2011, we still anticipate increased operating results for the full year of 2011 over 2010. However, the declines in energy prices and the broader economy increase the risks of nonperformance of counterparties and impairments of our long-lived assets.

We believe we are positioned to drive additional organic growth and aggressively pursue value-adding growth opportunities.

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, to some extent, 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 energy commodity prices and margins;

•

Lower than expected levels of cash flow from operations;

•

Availability of capital;

•

Counterparty credit and performance risk;

•

Decreased volumes from third parties served by our midstream business;

•

General economic, financial markets, or industry downturn;

•

Changes in the political and regulatory environments;

•

Physical damages to facilities, especially damage to offshore facilities by named windstorms.

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.

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2011, compared to the three and nine months ended September 30, 2010. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three months ended September 30,											Nine months ended September 30,
	2011			2010			$ Change*		% Change*			2011			2010			$ Change*		% Change*
	(Millions)											(Millions)
Revenues	$	1,673		$	1,327			+346		+26	%	$	4,923		$	4,217			+706		+17	%
Costs and expenses:
Costs and operating expenses		1,169			923			- 246		-27	%		3,437			2,958			- 479		-16	%
Selling, general and administrative expenses		69			70			+1		+1	%		216			202			- 14		-7	%
Other (income) expense – net		4			(13	)		- 17		NM			(8	)		(22	)		- 14		-64	%
General corporate expenses		29			30			+1		+3	%		86			93			+7		+8	%

Total costs and expenses		1,271			1,010								3,731			3,231
Operating income		402			317								1,192			986
Equity earnings		40			24			+16		+67	%		101			77			+24		+31	%
Interest accrued – net		(102	)		(96	)		- 6		-6	%		(312	)		(260	)		- 52		-20	%
Interest income		—			—			—		—			1			3			- 2		-67	%
Other income (expense) – net		2			8			- 6		-75	%		5			9			- 4		-44	%

Net income		342			253								987			815
Less: Net income attributable to noncontrolling interests		—			5			+5		+100	%		—			16			+16		+100	%

Net income attributable to controlling interests	$	342		$	248							$	987		$	799

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

Three months ended September 30, 2011 vs. three months ended September 30, 2010

The increase in revenues is primarily due to higher marketing revenues and NGL production revenues at Midstream due to higher average energy commodity prices. Additionally, fee revenues increased at Midstream primarily due to higher gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired in late 2010 and the Piceance basin as a result of an agreement executed in November 2010 with Williams Exploration & Production.

The increase in costs and operating expenses is primarily due to increased marketing purchases at Midstream primarily due to higher average energy commodity prices. Additionally, increased operating costs are primarily due to higher maintenance and higher depreciation costs.

Other (income) expense – net within operating income in 2010 includes a $12 million gain on the sale of part of our ownership interest in certain Piceance gathering assets at Midstream.

The increase in operating income generally reflects an improved energy commodity price environment in 2011 compared to 2010.

Management’s Discussion and Analysis (Continued)

Equity earnings increased primarily due to an $8 million increase from Gulfstream due to an increased ownership interest at Gas Pipeline and a $5 million increase from Discovery Producer Services LLC (Discovery) at Midstream.

Nine months ended September 30, 2011 vs. nine months ended September 30, 2010

The increase in revenues is primarily due to higher marketing and NGL production revenues at Midstream from higher average energy commodity prices, partially offset by lower crude marketing volumes and lower equity NGL volumes. Additionally, fee revenues increased at Midstream primarily due to higher gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired in late 2010 and the Piceance basin as a result of an agreement executed in November 2010 with Williams Exploration & Production. Gas Pipeline transportation revenues increased primarily due to expansion projects placed in service in 2010 and 2011.

The increase in costs and operating expenses is primarily due to increased marketing purchases at Midstream primarily due to higher average energy commodity prices, partially offset by lower crude marketing volumes. Additionally, operating costs increased primarily due to higher maintenance and higher depreciation costs. These increases are partially offset by decreased costs associated with production of NGLs reflecting lower average natural gas prices and lower equity NGL volumes at Midstream.

The increase in selling, general and administrative expenses (SG&A) is primarily due to higher employee-related expenses at Gas Pipeline.

Other (income) expense – net within operating income in 2011 includes $10 million related to the reversal of project feasibility costs from expense to capital at Gas Pipeline. (See Note 3 of Notes to Consolidated Financial Statements.)

Other (income) expense – net within operating income in 2010 includes $18 million of involuntary conversion gains at Midstream and a $12 million gain on the sale of part of our ownership interest in certain Piceance gathering assets at Midstream.

General corporate expenses in 2010 includes $12 million of outside services incurred related to the dropdown of assets from our general partner.

The increase in operating income generally reflects an improved energy commodity price environment in 2011 compared to 2010.

Equity earnings increased primarily due to a $13 million increase from Gulfstream due to an increased ownership interest at Gas Pipeline and a $13 million increase from the acquisition of an increased ownership interest in Overland Pass Pipeline Company LLC (OPPL) at Midstream.

The increase in interest accrued – net is primarily due to the $3.5 billion of senior notes issued in February 2010 and $600 million of senior notes issued in November 2010. In addition, 2010 project completions at Midstream contributed to a decrease in interest capitalized.

Net income attributable to noncontrolling interest decreased due to the merger with Williams Pipeline Partners L.P., which was completed in the third quarter of 2010.

Management’s Discussion and Analysis (Continued)

Results of Operations – Segments

Gas Pipeline

Overview of Nine Months Ended September 30, 2011

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.

85 North expansion project

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 $222 million. Phase I was placed into service in July 2010 and increased capacity by 90 thousand dekatherms per day (Mdt/d). Phase II was placed into service in May 2011 and increased capacity by 219 Mdt/d.

Mobile Bay South II expansion project

In July 2010, we received approval from the FERC to construct additional compression facilities and modifications to existing Mobile Bay line facilities in Alabama allowing transportation service to various southbound delivery points. Construction began in October 2010 and is estimated to cost $33 million. The project was placed into service in May 2011 and increased capacity by 380 Mdt/d.

Gulfstream acquisition

In May 2011, we acquired from Williams an additional 24.5 percent interest in Gulfstream in exchange for aggregate consideration of $297 million of cash, 632,584 limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. We funded the cash consideration for this transaction through our credit facility.

Outlook for the Remainder of 2011

Expansion projects

Mid-South

In August 2011, we received approval from the FERC to upgrade compressor facilities and expand our existing natural gas transmission system from Alabama to markets as far north as North Carolina. The cost of the project is estimated to be $217 million. The project is expected to be phased into service in September 2012 and June 2013, with an increase in capacity of 225 Mdt/d.

Mid-Atlantic Connector

In July 2011, we received approval from the FERC to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The cost of the project is estimated to be $55 million and will increase capacity by 142 Mdt/d. We plan to place the project into service in November 2012.

Management’s Discussion and Analysis (Continued)

Eminence Storage Field Leak

On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers.

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. We estimate the total abandonment costs, which will be capital in nature, will be approximately $76 million, which is expected to be spent in 2011, 2012, and the first half of 2013. This estimate is subject to change as work progresses and additional information becomes known. As of September 30, 2011, we have incurred $31 million in abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note 7 of Notes to Consolidated Financial Statements.)

For the three and nine months ended September 30, 2011, we incurred $6 million and $13 million, respectively, of expense related primarily to assessment and monitoring costs to ensure the safety of the surrounding area.

Period-Over-Period Operating Results


	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(Millions)				(Millions)
Segment revenues	$	429	$	409	$	1,252	$	1,196

Segment profit	$	170	$	161	$	497	$	478

Three months ended September 30, 2011 vs. three months ended September 30, 2010

Segment revenues increased $20 million, or 5 percent, primarily due to $18 million higher transportation revenues associated with expansion projects placed into service in 2010 and 2011.

Costs and operating expenses increased $21 million, or 10 percent, primarily due to $6 million increased operations and maintenance expense related to the Eminence Storage Field leak, $5 million higher depreciation expense resulting from additional assets placed in service in 2010 and 2011, $4 million higher employee-related expenses, and $3 million increased pipeline maintenance expense.

Equity earnings improved $7 million primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

Segment profit increased primarily due to the previously described changes.

Nine months ended September 30, 2011 vs. nine months ended September 30, 2010

Segment revenues increased $56 million, or 5 percent, primarily due to $41 million higher transportation revenues associated with expansion projects placed into service in 2010 and 2011, and $19 million higher system management gas sales (offset in costs and operating expenses). These increases are partially offset by $4 million lower sales of base gas from Hester Storage Field.

Costs and operating expenses increased $54 million, or 9 percent, primarily due to $19 million higher system management gas costs (offset in segment revenues), $13 million increased operations and maintenance expense related to the Eminence Storage Field leak, $11 million higher depreciation expense resulting from additional assets placed in service in 2010 and 2011, and $7 million increased pipeline maintenance expense.

Management’s Discussion and Analysis (Continued)

Selling, general and administrative expenses increased $7 million, or 7 percent, primarily due to higher employee-related expenses.

Other income (expense) – net improved $13 million primarily due to a $10 million reversal of project feasibility costs from expense to capital, associated with an expansion project, upon determining that the related project was probable of development. These costs will be included in the capital costs of the project, which we believe are probable of recovery through the project rates.

Equity earnings improved $11 million primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

Segment profit increased due to the previously described changes.

Midstream Gas & Liquids

Overview of Nine Months Ended September 30, 2011

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 2011 include the following:

Gulfstar FPS™ Deepwater Project

In October 2011, we executed agreements with two significant producers to provide production handling services for the Tubular Bells discovery located in the eastern deepwater Gulf of Mexico. The operator of the Tubular Bells field will utilize our proprietary floating-production system, Gulfstar FPS™. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. We will design, construct, and install our Gulfstar FPS™ with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services. The facility is a spar-based floating production system that utilizes a standard design approach that will allow customers to reduce their cycle time from discovery to first production. Construction is underway and the project is expected to be in service in 2014. We may consider a joint venture partner for this project.

Eagle Ford Shale

We have completed construction on a pipeline segment and related modifications necessary to reverse the flow of an existing Transco pipeline segment in southwest Texas, which began to gather south Texas gas to our Markham gas processing facility in the second quarter of 2011. In addition, we connected a third-party pipeline to our Markham plant during the third quarter that is delivering Eagle Ford Shale gas to the plant. We have executed both fee-based and keep whole processing agreements which we expect will push utilization of our Markham facility to full capacity. With the 2010 expansion, Markham is capable of processing 500 MMcf/d of gas with an NGL handling capacity of 45 Mbbls/d, subject to 25 Mbbls/d of available NGL take-away capacity until third-party pipeline connections are completed in early 2013.

Perdido Norte

During the fourth quarter of 2010, both oil and gas production began to flow on a sustained basis through our Perdido Norte expansion, located in the western deepwater of the Gulf of Mexico. The project includes a 200 MMcf/d expansion of our onshore Markham gas processing facility and a total of 179 miles of deepwater oil and gas lines that expand the scale of our existing infrastructure. While annual production volumes are significantly lower than originally expected, they have increased each quarter of 2011, as producers have resolved several technical issues. With these improvements and with the addition of a new well, we anticipate volumes to continue to increase during the fourth quarter of 2011.

Management’s Discussion and Analysis (Continued)

Overland Pass Pipeline

We became the operator of OPPL effective April 1, 2011. We own a 50 percent interest in OPPL which includes a 760-mile NGL pipeline from Opal, Wyoming, to the Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the Piceance and Denver-Julesburg basins in Colorado, respectively. Our equity NGL volumes from our two Wyoming plants and our Willow Creek plant in Colorado are dedicated for transport on OPPL under a long-term shipping agreement. We plan to participate in the construction of a pipeline connection and capacity expansions, to increase the pipeline’s capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.

Marcellus Shale Gathering Asset Transition and Expansion

We assumed the operational activities for a gathering business in Pennsylvania’s Marcellus Shale which we acquired at the end of 2010. This business includes 75 miles of gathering pipelines and two compressor stations. We expect gathered volumes to increase in the remainder of 2011 under our long-term dedicated gathering agreement for the seller’s production. Additionally, engineering and construction activities continue on our Springville gathering pipeline which will connect the gathering system into the Transco pipeline. Our long-term dedicated gathering agreement was revised in the second quarter of 2011, such that we will ultimately provide capacity on the Springville pipeline of approximately 625 MMcf/d.

NGL equity volumes lower in third quarter

Our NGL equity sales volumes for the third quarter of 2011 were impacted by unplanned maintenance at our Opal plant along with a shutdown of a third-party fractionator for approximately 10 days for an expansion project. As a result of the fractionator shutdown, NGL take-away capacity from our western plants on OPPL was reduced, which forced our western plants to curtail ethane recoveries. To mitigate the impact, we maximized local sales, arranged for alternative temporary transportation and sales avenues, and rescheduled planned maintenance to take place concurrent with the shutdown.

Volatile commodity prices

Average per-unit NGL margins in the nine months ending September 30, 2011 are significantly higher than the same period in 2010, benefiting from a strong demand for NGLs resulting in higher NGL prices and slightly lower natural gas prices driven by abundant natural gas supplies.

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. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

Management’s Discussion and Analysis (Continued)

LOGO

Outlook for the Remainder of 2011

The following factors could impact our business in 2011.

Commodity price changes

•

We expect our average per-unit NGL margins in 2011 to be higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets.

•

As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of approximately 20 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink gas requirements for the remainder of 2011. The combined impact of these energy commodity derivatives will provide a margin on the hedged volumes of $62 million. The following table presents our energy commodity hedging instruments as of October 25, 2011.

Management’s Discussion and Analysis (Continued)


	Period		Volumes Hedged		Weighted Average Hedge Price
Designated as hedging instruments:					(per gallon)
NGL sales – ethane (million gallons)		Oct - Dec 2011		20.8	$	0.70
NGL sales – propane (million gallons)		Oct - Dec 2011		15.1	$	1.39
NGL sales – isobutane (million gallons)		Oct - Dec 2011		5.0	$	1.91
NGL sales – normal butane (million gallons)		Oct - Dec 2011		6.3	$	1.81
NGL sales – natural gasoline (million gallons)		Oct - Dec 2011		10.7	$	2.46
					(per MMbtu)
Natural gas purchases (Tbtu)		Oct - Dec 2011		5.1	$	4.13

Gathering, processing, and NGL sales volumes

•

The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities.

•

We anticipate growth in our onshore businesses’ gas gathering and processing volumes as our infrastructure grows to support drilling activities in the Piceance and Appalachian basins. However, we anticipate no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. Due to the high proportion of fee-based processing agreements in the Piceance basin, we anticipate only a slight increase in NGL equity sales volumes.

•

In our Gulf Coast businesses, we expect higher gas gathering, processing, and crude transportation volumes as our Perdido Norte pipelines move into a full year of operation and other in-process drilling is completed. Increases in permitting, subsequent to the 2010 drilling moratorium, give us reason to expect gradual increased drilling activities in the Gulf of Mexico. While we expect an overall increase in processed gas volumes in 2011, NGL equity volumes are expected to be lower as a major contract changed from “keep-whole” to “percent-of-liquids” processing.

Expansion projects

We have planned growth capital and investment expenditures of $460 million to $690 million in 2011. Major projects include expansions to our gathering system in northeastern Pennsylvania as well as our Laurel Mountain Midstream, LLC (Laurel Mountain) equity investment in southwestern Pennsylvania, which combined are expected to provide 2.75 Bcf/d of gathering capacity by 2015. In addition to the previously discussed Gulfstar FPS™ deepwater project, we plan to pursue expansion and growth opportunities in the Gulf of Mexico, as well as in the Piceance basin. Our ongoing major expansion projects include:

Marcellus Shale

Additional gathering assets, including compression and dehydration, in the Marcellus Shale region of northeastern Pennsylvania, which is planned to provide approximately 1.25 Bcf/d of gathering capacity. Various compression and dehydration projects to increase the capacity of the acquired gathering system to approximately 550 MMcf/d are complete; however, volumes are constrained until take-away capacity is in service.

Our Springville pipeline, which is expected to be completed in the fourth quarter of 2011, will allow full use of the current capacity. In conjunction with a long-term agreement with a significant producer, we are constructing and will operate the Springville pipeline, a 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline. The first phase of the Springville project is expected to be completed in the fourth quarter of 2011 and will allow us to deliver approximately 300 MMcf/d to Transco. Expansions to the Springville compression facilities in 2012 will eventually increase the capacity to approximately 625 MMcf/d.

Construction of a new non-contiguous gathering system is complete and was placed into service in October 2011. This system currently has the capacity to deliver approximately 50 MMcf/d into a third-party interstate pipeline via another third-party gathering system. We will continue to expand this gathering system to a planned capacity of 150 MMcf/d.

Management’s Discussion and Analysis (Continued)

Laurel Mountain

Capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region, to enable the rapid expansion of our gathering system including the initial stages of projects that are planned to provide approximately 1.5 Bcf/d of gathering capacity and 1,400 miles of gathering lines, including 400 new miles of 6-inch to 24-inch diameter pipeline. The initial phase of our Shamrock compressor station went in service during the first quarter of 2011, providing 30 MMcf/d of additional capacity, with another 150 MMcf/d expected to be available in the first quarter of 2012. This compressor station is expandable to 350 MMcf/d and will likely be the largest central delivery point out of the Laurel Mountain system. In other separate compression projects, an additional 20 MMcf/d of capacity began operating in the second quarter of 2011 and we continue to progress on further additions. In the third quarter of 2011, Laurel Mountain executed agreements with Williams Exploration & Production to provide gathering services in Westmoreland County, Pennsylvania beginning in the second quarter of 2012.

Parachute

In conjunction with a new basin-wide agreement for all gathering and processing services provided by us to Williams Exploration & Production in the Piceance basin, we plan to construct a 350 MMcf/d cryogenic gas processing plant. The Parachute TXP I plant is expected to be in service in 2014.

Period-Over-Period Operating Results


	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(Millions)				(Millions)
Segment revenues	$	1,244	$	918	$	3,671	$	3,021

Segment profit	$	301	$	210	$	882	$	678

Three months ended September 30, 2011 vs. three months ended September 30, 2010

The increase in segment revenues includes:

•

A $184 million increase in marketing revenues primarily due to higher average NGL and crude prices. These changes are substantially offset by similar changes in marketing purchases.

•

A $102 million increase in revenues associated with our equity NGLs reflecting an increase of $96 million associated with a 43 percent increase in average NGL per-unit prices and a $6 million increase in revenues associated with a 1 percent increase in NGL volumes.

•

A $39 million increase in fee revenues primarily due to a minimum volume commitment fee and new volumes transported on our Perdido Norte gas and oil pipelines in the deepwater of the western Gulf of Mexico which went into service in late 2010, new gathering fee revenues from our gathering assets in the Marcellus Shale in northeastern Pennsylvania acquired in late 2010, and higher fees in the Piceance basin as a result of an agreement with Williams Exploration & Production executed in November 2010.

Segment costs and expenses increased $243 million, or 34 percent, including:

•

A $181 million increase in marketing purchases primarily due to higher average NGL and crude prices. These changes are offset by similar changes in marketing revenues.

•

A $40 million increase in operating costs reflecting $26 million higher maintenance expenses including unplanned maintenance during the third quarter of 2011, along with planned maintenance performed during the previously mentioned outage of a third-party fractionator. In addition, depreciation expense is $10 million higher primarily due to our new Perdido Norte pipelines, increased depreciation of our Lybrook plant which is scheduled to be idled at the end of 2011 when the gas will be redirected to our Ignacio plant, and our Echo Springs expansion which went into service in late 2010.

•

A $19 million unfavorable change related to gains recognized in 2010 including the sale of certain assets in Colorado’s Piceance basin and involuntary conversion gains due to insurance recoveries in excess of the carrying value of our Gulf assets which were damaged by Hurricane Ike in 2008.

The increase 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.

Management’s Discussion and Analysis (Continued)

The increase in Midstream’s segment profit includes:

•

A $98 million increase in NGL margins reflecting:

•

A $93 million increase in the onshore businesses’ NGL margins reflecting a $79 million increase related to commodity price changes, primarily from a 45 percent increase in average NGL prices. NGL equity volumes sold are 8 percent higher reflecting new production capacity at our Echo Springs plant, offset by the impact of unplanned maintenance at our Opal plant in the third quarter of 2011. The previously discussed impact of a shutdown of a third-party fractionator, which limited plant production deliveries into OPPL and related planned maintenance, is offset by a similar event in the third quarter of 2010.

•

A $5 million increase in the Gulf Coast businesses’ NGL margins reflecting a $10 million increase from favorable changes in commodity prices, primarily a 33 percent increase in average NGL prices. This was partially offset by a $5 million unfavorable change related to 36 percent lower NGL equity volumes. NGL equity volumes sold were lower primarily due to a change in a major contract from “keep-whole” to “percent-of-liquids” processing.

•

A $39 million increase in fee revenues as previously discussed.

•

A $9 million increase in equity earnings primarily due to higher Discovery equity earnings from higher NGL prices and higher OPPL equity earnings as a result of our purchase of an increased ownership interest in September 2010.

•

A $40 million increase in operating costs as previously discussed.

•

A $19 million unfavorable change related to gains recognized in 2010 as previously discussed.

Nine months ended September 30, 2011 vs. nine months ended September 30, 2010

The increase in segment revenues includes:

•

A $418 million increase in marketing revenues primarily due to higher average NGL and crude prices, partially offset by lower crude volumes. These changes are substantially offset by similar changes in marketing purchases.

•

A $158 million increase in revenues from our equity NGLs reflecting an increase of $185 million associated with a 23 percent increase in average NGL per-unit sales prices, partially offset by a decrease of $27 million associated with a 4 percent decrease in equity NGL volumes.

•

A $73 million increase in fee revenues primarily due to higher gathering and processing fee revenues. In the Piceance basin higher fees are primarily a result of an agreement with Williams Exploration & Production executed in November 2010. In addition, we have fees from new volumes on our gathering assets in the Marcellus Shale in northeastern Pennsylvania, which we acquired at the end of 2010 and on our Perdido Norte gas and oil pipelines in the deepwater of the western Gulf of Mexico, which went into service in late 2010. These increases are partially offset by a decline in gathering and transportation fees in the deepwater of the eastern Gulf of Mexico, the Four Corners, and southwest Wyoming areas primarily due to natural field declines.

Segment costs and expenses increased $458 million, or 19 percent, including:

•

A $387 million increase in marketing purchases primarily due to higher average NGL and crude prices, partially offset by lower crude volumes. These changes are offset by similar changes in marketing revenues.

•

An $81 million increase in operating costs reflecting $46 million higher maintenance expenses, including unplanned maintenance in the third quarter of 2011, planned maintenance performed during the previously mentioned outage of a

Management’s Discussion and Analysis (Continued)

third-party fractionator, maintenance expenses for our gathering assets in northeastern Pennsylvania acquired at the end of 2010, and higher property insurance expense. In addition, depreciation expense is $28 million higher primarily due to our new Perdido Norte pipelines, our Echo Springs expansion which went into service in late 2010, and increased depreciation of our Lybrook plant which is scheduled to be idled at the end of 2011 when the gas will be redirected to our Ignacio plant.

•

A $30 million unfavorable change related to gains recognized in 2010 including involuntary conversion gains due to insurance recoveries in excess of the carrying value of our Ignacio plant which was damaged by a fire in 2007 and Gulf Coast assets which were damaged by Hurricane Ike in 2008 and gains associated with sales of certain assets in Colorado’s Piceance basin.

•

A $40 million decrease in costs associated with our equity NGLs reflecting a decrease of $22 million associated with a 7 percent decrease in average natural gas prices and an $18 million decrease reflecting lower equity NGL volumes.

The increase in Midstream’s segment profit includes:

•

A $198 million increase in NGL margins reflecting:

•

A $194 million increase in the onshore businesses’ NGL margins reflecting a $177 million increase from favorable commodity price changes including a 24 percent increase in average NGL prices and a 4 percent decrease in average natural gas prices. NGL equity volumes sold are 4 percent higher reflecting new capacity at our Echo Springs plant, partially offset by severe winter weather conditions in early 2011 that limited producers’ ability to deliver gas to the plants and more maintenance at our Opal plant.

•

A $4 million increase in the Gulf Coast business’s NGL margins related to a $27 million increase from favorable commodity price changes, partially offset by 39 percent lower NGL equity volumes sold primarily due to a change in a major contract from “keep-whole” to “percent-of-liquids” processing.

•

A $73 million increase in fee revenues as previously discussed.

•

A $31 million increase in margins related to the marketing of NGLs and crude.

•

A $13 million increase in equity earnings primarily due to higher OPPL equity earnings as a result of our purchase of an increased ownership interest in September 2010.

•

An $81 million increase in operating costs as previously discussed.

•

A $30 million unfavorable change related to gains recognized in 2010 as previously discussed.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

For 2011, we expect operating results and cash flows to be higher than 2010 levels due to the combination of expected higher energy commodity margins and the start-up of certain expansion capital projects. However, 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 not directly impacted by short-term 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.

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, unitholder distributions and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following for 2011:

•

We increased our per-unit quarterly distribution with respect to the third quarter of 2011 from $0.7325 to $0.7475. We expect to increase quarterly limited partner cash distributions by approximately 6 percent to 10 percent annually.

•

As of September 30, 2011, we have $333 million of current debt maturities. We anticipate funding these maturities with new debt issuances.

•

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 facility as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.95 billion and $2.1 billion in 2011.

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. 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 an omnibus agreement;

•

Use of our credit facility, as needed and available.

We anticipate our more significant uses of cash to be:

•

Maintenance and expansion capital expenditures;

•

Payment of debt maturities (pursuant to expected issuances of new long-term debt);

•

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

•

Interest on our long-term debt;

Management’s Discussion and Analysis (Continued)

•

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;

•

Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;

•

Sustained reductions in energy commodity margins from expected 2011 levels;

•

Physical damages to facilities, especially damage to offshore facilities by named windstorms.


	September 30, 2011
Available Liquidity	(Millions)
Cash and cash equivalents	$	143
Available capacity under our $2 billion five-year senior unsecured revolving credit facility (expires June 3, 2016) (1)		1,600

	$	1,743

(1)

In June 2011, we replaced our existing $1.75 billion unsecured revolving credit facility agreement with a new $2 billion five-year senior unsecured revolving credit facility agreement. 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, under certain conditions, be increased by up to an additional $400 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the credit facility to the extent not otherwise utilized by the other co-borrowers. At September 30, 2011, we are in compliance with the financial covenants associated with this new credit facility agreement. (See Note 5 of Notes to Consolidated Financial Statements.)

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 LP, Discovery, Gulfstream, Laurel Mountain, and OPPL.

Omnibus Agreement with Williams

In connection with the Dropdown in February 2010, we entered into an 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 are 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.

Debt Offering

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. A portion of these proceeds were used to retire Transco’s $300 million 7 percent senior unsecured notes that matured on August 15, 2011.

Credit Ratings

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


Rating Agency	Date of Last Change	Outlook	Senior Unsecured Debt Rating
Standard & Poor’s	January 12, 2010	Positive	BBB-

Moody’s Investor Service	February 16, 2011	Under review for possible upgrade	Baa3

Fitch Ratings	February 2, 2010	Stable	BBB-

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

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

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of September 30, 2011, we estimate that a downgrade to a rating below investment grade would require us to post up to $65 million in additional collateral with third parties.

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, including (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, (2) expenditures which are mandatory and/or essential to comply with laws and regulations and maintain the reliability of our operations, and (3) certain well connection expenditures.

•

Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, including (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.

Management’s Discussion and Analysis (Continued)

The following table provides summary information related to our actual and expected capital expenditures and purchase of business and investments for 2011. These amounts reflect total increases to property, plant, and equipment, including accrued amounts, and investments:


	Maintenance				Expansion				Total
Segment	2011 Estimate		Nine Months Ended September 30, 2011		2011 Estimate		Nine Months Ended September 30, 2011		2011 Estimate		Nine Months Ended September 30, 2011
	(Millions)
Gas Pipeline	$	305-330	$	231	$	560-610	$	315	$	865-940	$	546
Midstream		90-110		63		460-690		384		550-800		447

Total	$	395-440	$	294	$	1,020-1,300	$	699	$	1,415-1,740	$	993

See Results of Operations – Segments, Gas Pipeline and Midstream for discussions describing the general nature of these expenditures.

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. However, Williams waived its incentive distribution rights related to the 2009 distribution periods. We have increased our quarterly distribution from $0.7325 to $0.7475 per unit, which resulted in a third-quarter 2011 distribution of approximately $294 million that will be paid on November 11, 2011, to the general and limited partners of record at the close of business on November 4, 2011.

Sources (Uses) of Cash


	Nine months ended September 30,
	2011			2010
	(Millions)
Net cash provided (used) by:
Operating activities	$	1,517		$	1,412
Financing activities		(624	)		2,939
Investing activities		(937	)		(4,412	)

Increase (decrease) in cash and cash equivalents	$	(44	)	$	(61	)

Operating activities

Net cash provided by operating activities for the nine months ended September 30, 2011, increased from the same period in 2010 primarily due to higher operating income, partially offset by net unfavorable changes in working capital including the timing of settling certain affiliate balances.

Financing activities

Significant transactions include:

•

$375 million received from Transco’s issuance of senior unsecured notes in August 2011;

•

$300 million paid to retire Transco’s senior unsecured notes that matured in August 2011;

•

$300 million received in revolver borrowings from our $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011;

Management’s Discussion and Analysis (Continued)

•

We refinanced $300 million outstanding under the previous $1.75 billion credit facility via a non-cash transfer of the obligation to the new $2 billion credit facility in June 2011;

•

$150 million paid to retire senior unsecured notes that matured in June 2011;

•

$123 million distributed to Williams related to the excess purchase price over the contributed basis of Gulfstream in May 2011;

•

$430 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used to fund our increased ownership in OPPL, a transaction that closed in September 2010;

•

$380 million received from our September 2010 equity offering used to reduce revolver borrowings mentioned above;

•

$3.5 billion of net proceeds from the issuance of senior unsecured notes in 2010;

•

$191 million in distributions to Williams primarily related to the contributed entities prior to the closing of the Dropdown in February 2010;

•

$250 million received from revolver borrowings on our $1.75 billion unsecured credit facility in February 2010 to repay a term loan outstanding under our credit agreement which expired at the closing of the Dropdown in February 2010;

•

$830 million and $410 million in 2011 and 2010, respectively, related to quarterly cash distributions paid to limited partners and our general partner.

Investing activities

Significant transactions include:

•

$174 million related to our acquisition of a 24.5 percent interest in Gulfstream from Williams in May 2011 (see Results of Operations – Segments, Gas Pipeline);

•

$424 million cash payment for our September 2010 acquisition of an increased interest in OPPL;

•

$3.4 billion related to the cash consideration paid to Williams related to the Dropdown in February 2010;

•

Capital expenditures in 2011 and 2010 totaled $598 million and $587 million, respectively.

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

We have various other guarantees and commitments which are disclosed in Notes 7 and 8 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.

Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first nine months of 2011.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as well as other market factors, such as market volatility and commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets and our long-term energy-related contracts. We manage a portion of the risks associated with these market fluctuations using various derivative contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. (See Note 7 of Notes to Consolidated Financial Statements.)

We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolio will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints. Our derivative contracts are contracts held for nontrading purposes and hedge a portion of our commodity price risk exposure from NGL sales and natural gas purchases.

The value at risk was less than $1 million at September 30, 2011 and zero at December 31, 2010.

Substantially all of the derivative contracts included in our value-at-risk calculation are accounted for as cash flow hedges. Any change in the fair value of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

Item 4

Controls and Procedures

Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal controls over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Williams Partners L.P. have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Third-Quarter 2011 Changes in Internal Controls

There have been no changes during the third quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

In September 2007, the EPA requested, and our Transcontinental Gas Pipe Line Company, LLC (Transco) subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of Transco’s compliance with the Clean Air Act. On March 28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland.

In March 2008, the Environmental Protection Agency (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. Under a settlement reached with the EPA in September 2011, we agreed to pay $50,000 and undertake enhanced leak detection and repair monitoring at the gas plant.

In July 2011, the New Mexico Environmental Department proposed a $900,000 settlement for alleged violations of the New Mexico Air Quality Act at five separate facilities that we own or operate. We are discussing settlement with the agency.

In September 2011, the Colorado Department of Public Health and Environment proposed a penalty of $301,000 for alleged violations of the Colorado Clean Water Act related to excavation work being done for our Crawford Trail Pipeline. We are discussing settlement with the agency.

Other

The additional information called for by this item is provided in Note 8 of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, includes certain risk factors that could materially affect our business, financial condition or future results. Those Risk Factors have not materially changed, except as set forth below:

Our costs of testing, maintaining or repairing our facilities may exceed our expectations and the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.

We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by regulatory authorities to test or undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the costs of testing, maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service. For example, in response to a recent third-party pipeline rupture, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records could result in reduction of allowable operating pressures, which would reduce available capacity on our pipelines.

Cost reimbursements due to our general partner and its affiliates will reduce cash available to pay distributions to unitholders.

We will reimburse our general partner and its affiliates, including Williams, for various general and administrative services they provide for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us. Our general partner determines the amount of these reimbursements in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distributions to unitholders. Furthermore, Williams, which owns our general partner, recently announced a plan to separate its exploration and production business into a newly formed separate publicly-traded corporation. While Williams retains the discretion to determine whether and when to complete this reorganization plan, the spin-off of Williams’ exploration and production business could significantly increase the costs of the general and administrative services provided to us. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Item 6. Exhibits


Exhibit No.		Description

Exhibit 3.1	—	Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.

Exhibit 3.2	—	Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.

Exhibit 3.3	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6, and 7 (filed on February 21, 2011 as Exhibit 3.3 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference.

Exhibit 3.4	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

Exhibit 4.1	—	Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.

Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.(1)

Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1)

Exhibit 31.2	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1)

Exhibit 32	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(2)

Exhibit 101.INS	—	XBRL Instance Document.(2)

Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.(2)

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.(2)

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.(2)

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.(2)


Exhibit No.		Description

Exhibit 101.PRE	—	XBRLTaxonomy Extension Presentation Linkbase.(2)

(1)	Filed herewith.

(2)	Furnished herewith.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

WILLIAMS PARTNERS L.P.

(Registrant)

By:

Williams Partners GP LLC, its general partner

/s/ Ted T. Timmermans

Ted T. Timmermans

Controller (Duly Authorized Officer and Principal

Accounting Officer)

November 2, 2011

EXHIBIT INDEX


Exhibit No.		Description

Exhibit 3.1	—	Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.

Exhibit 3.2	—	Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.

Exhibit 3.3	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6, and 7 (filed on February 21, 2011 as Exhibit 3.3 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference.

Exhibit 3.4	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

Exhibit 4.1	—	Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.

Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.(1)

Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1)

Exhibit 31.2	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(1)

Exhibit 32	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(2)

Exhibit 101.INS	—	XBRL Instance Document.(2)

Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.(2)

Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.(2)

Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.(2)

Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.(2)


Exhibit No.		Description

Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.(2)

(1)	Filed herewith.

(2)	Furnished herewith.