Edgar Filing: Williams Partners L.P.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

¨	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 x 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 x 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):

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

The registrant had 345,409,387 common units outstanding as of August 1, 2012.

Williams Partners L.P.

Index


	Page
Part I. Financial Information

Item 1. Financial Statements

Consolidated Statement of Comprehensive Income—Three and Six Months Ended June 30, 2012 and 2011		4

Consolidated Balance Sheet—June 30, 2012 and December 31, 2011		5

Consolidated Statement of Changes in Equity—Six Months Ended June 30, 2012		6

Consolidated Statement of Cash Flows—Six Months Ended June 30, 2012 and 2011		7

Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3. Quantitative and Qualitative Disclosures About Market Risk		41

Item 4. Controls and Procedures		42

Part II. Other Information		42

Item 1. Legal Proceedings		42

Item 1A. Risk Factors		43

Item 6. Exhibits		44

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,” “guidance,” “in service date” 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 components;

•

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 pay current and expected levels of cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner;

•

Availability of supplies, 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;

•

Ability to acquire new businesses and assets and integrate those operations and assets into our existing businesses, as well as expand our facilities;

•

Development of alternative energy sources;

•

The impact of operational and development hazards;

•

Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), 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 and counterparties;

•

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, including cybersecurity threats and related disruptions;

•

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, 2011, and Part II, Item 1A. Risk Factors of this Form 10-Q.

PART I – FINANCIAL INFORMATION

Williams Partners L.P.

Consolidated Statement of Comprehensive Income

(Unaudited)


	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
	(Millions, except per-unit amounts)
Revenues:
Gas Pipeline	$	399		$	407		$	821		$	823
Midstream Gas & Liquids		1,184			1,264			2,447			2,427

Total revenues		1,583			1,671			3,268			3,250
Segment costs and expenses:
Costs and operating expenses		1,163			1,167			2,300			2,274
Selling, general, and administrative expenses		95			70			180			141
Other (income) expense—net		13			(1	)		18			(12	)

Total segment costs and expenses		1,271			1,236			2,498			2,403
General corporate expenses		46			27			82			57

Operating income:
Gas Pipeline		131			138			294			304
Midstream Gas & Liquids		181			297			476			543
General corporate expenses		(46	)		(27	)		(82	)		(57	)

Total operating income		266			408			688			790
Equity earnings		27			36			57			61
Interest accrued		(110	)		(107	)		(220	)		(215	)
Interest capitalized		5			3			8			5
Interest income		—			—			1			1
Other income (expense)—net		5			(2	)		7			3

Net income	$	193		$	338		$	541		$	645

Allocation of net income for calculation of earnings per common unit:
Net income	$	193		$	338		$	541		$	645
Allocation of net income to general partner		96			74			190			145

Allocation of net income to common units	$	97		$	264		$	351		$	500

Basic and diluted net income per common unit	$	0.29		$	0.91		$	1.11		$	1.72
Weighted average number of common units outstanding (thousands)		335,920			290,213			317,594			290,030
Cash distributions per common unit	$	0.7925		$	0.7325		$	1.5700		$	1.4500

Other comprehensive income (loss):
Net unrealized gain (loss) from derivative instruments	$	53		$	(2	)	$	45		$	(4	)
Reclassifications into earnings of net derivative instruments (gain) loss		(8	)		4			(6	)		4

Other comprehensive income (loss)		45			2			39			—

Comprehensive income	$	238		$	340		$	580		$	645

See accompanying notes.

Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)


	June 30, 2012			December 31, 2011
ASSETS	(Millions)
Current assets:
Cash and cash equivalents	$	34		$	163
Accounts and notes receivable:
Trade		471			484
Affiliate		4			9
Inventories		126			148
Regulatory assets		41			40
Other current assets		117			70

Total current assets		793			914
Investments		1,532			1,383

Property, plant, and equipment, at cost		19,316			17,755
Accumulated depreciation		(6,386	)		(6,128	)

Property, plant, and equipment—net		12,930			11,627
Goodwill		724			—
Other intangibles		1,660			43
Regulatory assets, deferred charges, and other		401			413

Total assets	$	18,040		$	14,380

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	602		$	554
Affiliate		140			57
Accrued interest		105			105
Asset retirement obligations		60			66
Other accrued liabilities		217			166
Long-term debt due within one year		—			324

Total current liabilities		1,124			1,272
Long-term debt		7,583			6,913
Asset retirement obligations		513			503
Regulatory liabilities, deferred income, and other		488			464
Contingent liabilities (Note 10)
Equity:
Common units (345,409,387 units outstanding at June 30, 2012 and 290,477,159 units outstanding at December 31, 2011)		9,804			6,810
General partner		(1,509	)		(1,580	)
Accumulated other comprehensive income (loss)		37			(2	)

Total equity		8,332			5,228

Total liabilities and equity	$	18,040		$	14,380

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Changes in Equity

(Unaudited)


	Common Units			General Partner			Accumulated Other Comprehensive Income (Loss)			Total Equity
	(Millions)
Balance—December 31, 2011	$	6,810		$	(1,580	)	$	(2	)	$	5,228
Net income		366			175			—			541
Other comprehensive income (loss)		—			—			39			39
Cash distributions		(495	)		(178	)		—			(673	)
Sale of common units		2,071			—			—			2,071
Issuance of common units related to acquisitions		1,051			—			—			1,051
Contributions from general partner		—			74			—			74
Other		1			—			—			1

Balance—June 30, 2012	$	9,804		$	(1,509	)	$	37		$	8,332

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)


	Six months ended June 30,
	2012			2011
	(Millions)
OPERATING ACTIVITIES:
Net income	$	541		$	645
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization		324			304
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		26			(21	)
Inventories		22			13
Other assets and deferred charges		29			(20	)
Accounts payable		(122	)		64
Accrued liabilities		8			43
Affiliate accounts receivable and payable—net		88			(28	)
Other, including changes in noncurrent assets and liabilities		52			(17	)

Net cash provided by operating activities	$	968		$	983

FINANCING ACTIVITIES:
Proceeds from long-term debt		500			350
Payments of long-term debt		(155	)		(150	)
Payment of debt issuance costs		—			(8	)
Proceeds from sales of common units		2,071			—
General partner contributions		74			—
Distributions to limited partners and general partner		(673	)		(544	)
Excess of purchase price over contributed basis of investment		—			(123	)
Other—net		7			7

Net cash provided (used) by financing activities	$	1,824		$	(468	)

INVESTING ACTIVITIES:
Purchases of investments from affiliates		—			(174	)
Property, plant and equipment:
Capital expenditures		(741	)		(309	)
Net proceeds from dispositions		22			(3	)
Purchases of businesses		(2,049	)		—
Contributions to equity method investments		(184	)		(101	)
Other—net		31			(3	)

Net cash used by investing activities	$	(2,921	)	$	(590	)

Increase (decrease) in cash and cash equivalents		(129	)		(75	)
Cash and cash equivalents at beginning of period		163			187

Cash and cash equivalents at end of period	$	34		$	112

See accompanying notes.

Williams Partners L.P.

Notes to Consolidated Financial Statements

(Unaudited)

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

General

Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto in our Form 10-K/A Amendment No.1, filed April 9, 2012. The accompanying unaudited financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our interim financial statements.

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.

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.

Description of Business

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 June 30, 2012, Williams owns an approximate 66 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, an operating limited liability company (wholly owned by us).

Our operations are located in the United States and are organized into the Gas Pipeline and Midstream Gas & Liquids (Midstream) reporting segments.

Gas Pipeline includes 100 percent of Transcontinental Gas Pipe Line Company, LLC (Transco), 100 percent of Northwest Pipeline GP (Northwest Pipeline), and 50 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream). Our ownership interest in Gulfstream has increased by 1 percent, a result of a second-quarter 2012 acquisition from a subsidiary of Williams (see Note 2).

Midstream is comprised primarily of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and natural gas liquid (NGL) fractionation and transportation assets. Midstream’s assets also include substantial operations and investments in the Four Corners region, the Piceance basin, as well as an NGL fractionator and storage facilities near Conway, Kansas.

Basis of Presentation

Variable interest entity

Gulfstar One (Gulfstar) is a consolidated wholly-owned subsidiary that, due to certain risk sharing provisions in its customer contracts, is a variable interest entity. We, as construction agent for Gulfstar, will design, construct, and install a proprietary floating-production system, Gulfstar FPS^TM, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. Construction is underway and the project is expected to be in service in 2014. We, in combination with certain advance payments from the producer customers, are currently financing the asset construction. As of June 30, 2012, our Consolidated Balance Sheet includes $305 million of Gulfstar construction work in process

Notes (Continued)

representing costs incurred to date, included in property, plant, and equipment, at cost and $110 million of deferred revenue, included in regulatory liabilities, deferred income, and other associated with the customer advance payments. We are committed to the producer customers to construct this system and we currently estimate the remaining construction cost to be less than $650 million. If the producer customers do not develop the offshore oil and gas fields to be connected to Gulfstar, they will be responsible for the firm price of building the facilities.

Note 2. Acquisitions

On February 17, 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC, in exchange for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 of our common units valued at $441 million (Laser Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York.

On April 27, 2012, we completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC (Caiman Acquisition) in exchange for $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 of our common units valued at $603 million. The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. Acquisition transaction costs of $16 million were incurred related to the Caiman Acquisition and are reported in selling, general and administrative expenses at Midstream in the Consolidated Statement of Comprehensive Income.

These acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was allocated to goodwill within the Midstream segment.

The amounts recognized in the financial statements are preliminary because our valuation work has not been completed. For the Laser Acquisition, we are awaiting further information for valuing intangible assets, contingent liabilities and asset retirement obligations. For the Caiman Acquisition, we are awaiting further information for valuing the working capital components, property, plant and equipment, intangible assets, contingent liabilities and asset retirement obligations. In addition, we are still in the process of identifying all the assets acquired and liabilities assumed.

The following table presents a preliminary allocation of the acquisition-date fair value of the major classes of the net assets, which are presented in the Midstream segment:


	Laser			Caiman
Assets held for sale	$	18		$	—
Other current assets		3			13
Property, plant and equipment		158			665
Intangible assets		318			1,313
Current liabilities		(21	)		(98	)

Identifiable net assets acquired		476			1,893
Goodwill		290			434

	$	766		$	2,327

Notes (Continued)

Identifiable intangible assets recognized to date in the acquisitions are primarily related to gas gathering, processing and fractionation agreements and relationships with customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired customer contracts and relationships, which are offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. Those intangible assets are being amortized on a straight-line basis over an initial 30-year period during which the customer contracts and relationships are expected to contribute to our cash flows. We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation agreements with customers.

We will evaluate these intangible assets for both changes in the expected remaining useful lives and impairment when events or changes in circumstances indicate, in our management’s judgment, that the estimated useful lives have changed or the carrying value of such assets may not be recoverable. Changes in an estimated remaining useful life would be reflected prospectively through amortization over the revised remaining useful life. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the intangible assets to the carrying value of the assets to determine whether an impairment has occurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the area. We are currently evaluating the appropriate reporting unit for the allocation of the goodwill within the Midstream segment. The goodwill is not subject to amortization but will be evaluated annually for impairment or more frequently if impairment indicators are present. Our evaluation will include a qualitative assessment of events or circumstances to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If so, we will further compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss will be recognized in the amount of the excess.

Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Comprehensive Income since the respective acquisition dates are not material. Supplemental pro forma revenue and earnings reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Comprehensive Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.

On June 14, 2012, we acquired a 1 percent interest in Gulfstream from a subsidiary of Williams in exchange for 238,050 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.

Notes (Continued)

Note 3. Allocation of Net Income and Distributions

The allocation of net income between our general partner and limited partners for the three and six months ended June 30, 2012 and 2011 is as follows:


	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
	(Millions)
Allocation of net income to general partner:
Net income	$	193		$	338		$	541		$	645
Net reimbursable costs charged directly to general partner		—			—			—			(2	)

Income subject to 2% allocation of general partner interest		193			338			541			643
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		4			7			11			13
Incentive distributions paid to general partner (a)		86			63			164			122
Net reimbursable costs charged directly to general partner		—			—			—			2

Net income allocated to general partner	$	90		$	70		$	175		$	137

Net income	$	193		$	338		$	541		$	645
Net income allocated to general partner		90			70			175			137

Net income allocated to common limited partners	$	103		$	268		$	366		$	508

(a)

The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. 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 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.

We paid or have authorized payment of the following partnership cash distributions during 2011 and 2012 (in millions, except for per unit amounts):


					General Partner
Payment Date	Per Unit Distribution		Common Units		2%		Incentive Distribution Rights		Total Cash Distribution
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	$	0.7475	$	217	$	6	$	71	$	294
2/10/2012	$	0.7625	$	227	$	6	$	78	$	311
5/11/2012	$	0.7775	$	268	$	8	$	86	$	362
8/10/2012 (b)	$	0.7925	$	274	$	7	$	92	$	373

(b)	The Board of Directors of our general partner declared this $0.7925 per unit cash distribution on July 23, 2012, to be paid on August 10, 2012, to unitholders of record at the close of business on August 3, 2012.

The 2012 cash distributions to our general partner in the table above have been reduced by $16 million resulting from the temporary waiver of IDRs associated with the Caiman Acquisition.

Notes (Continued)

Note 4. Other Accruals

Other (income) expense – net within segment costs and expenses in the six months ended June 30, 2011 includes $10 million related to the reversal of project feasibility costs from expense to capital at Gas Pipeline, associated with a natural gas pipeline expansion project. This reversal was made upon determining that the related project was probable of development. These costs are now included in the capital costs of the project, which we believe are probable of recovery through the project rates.

Note 5. Inventories


	June 30, 2012		December 31, 2011
	(Millions)
Natural gas liquids and natural gas in underground storage	$	56	$	80
Materials, supplies, and other		70		68

	$	126	$	148

Note 6. Debt and Banking Arrangements

Credit Facility

Letter of credit capacity under our $2 billion credit facility is $1.3 billion. At June 30, 2012, no letters of credit have been issued and $345 million of loans are outstanding under the credit facility.

Issuances and Retirements

In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transco’s $325 million 8.875 percent senior unsecured notes that matured on July 15, 2012. As a result of this transaction, we presented the $325 million notes as long-term debt at June 30, 2012. 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 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.

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in February 2012 and completed in March 2012.

Note 7. Partners’ Capital

On January 30, 2012, we completed an equity issuance of 7,000,000 common units representing limited partner interests in us at a price of $62.81 per unit. The net proceeds were used to fund capital expenditures and for other partnership purposes.

Notes (Continued)

On February 17, 2012, we closed the acquisition of certain entities from Delphi Midstream Partners, LLC. In connection with this transaction, we issued 7,531,381 of our common units. (See Note 2.)

On February 28, 2012, we sold an additional 1,050,000 common units, at a price of $62.81 per unit, to the underwriters upon the underwriters’ exercise of their option to purchase additional common units pursuant to our common unit offering in January 2012. The net proceeds were used for general partnership purposes.

On April 10, 2012, we completed an equity issuance of 10,000,000 common units representing limited partner interests at a price of $54.56 per unit. On April 26, 2012, we sold an additional 973,368 common units at a price of $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition. (See Note 2.) We also used $1 billion in proceeds from the April 27, 2012, sale of 16,360,133 common units to Williams to fund the Caiman Acquisition.

On April 27, 2012, we closed the acquisition of Caiman Eastern Midstream, LLC, from Caiman Energy, LLC. In connection with this transaction, we issued 11,779,296 of our common units. (See Note 2.)

On June 14, 2012, we closed the acquisition of a 1 percent interest in Gulfstream Natural Gas System, L.L.C. from a subsidiary of Williams. In connection with this transaction, we issued 238,050 of our common units. (See Note 2.)

Note 8. Fair Value Measurements

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.


							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at June 30, 2012:
Measured on a recurring basis:
ARO Trust investments	$	25		$	25		$	25		$	—		$	—
Energy derivatives assets not designated as hedging instruments		5			5			2			3			—
Energy derivatives assets designated as hedging instruments		41			41			29			12			—
Energy derivatives liabilities not designated as hedging instruments		(5	)		(5	)		(3	)		(2	)		—
Additional disclosures:
Notes receivable and other		15			15			6			9			—
Long-term debt, including current portion		(7,583	)		(8,555	)		—			(8,555	)		—
Customer margin deposits payable		(32	)		(32	)		(32	)		—			—

Notes (Continued)


Assets (liabilities) at December 31, 2011:
Measured on a recurring basis:
ARO Trust investments	$	25		$	25		$	25	$	—	$	—
Energy derivatives assets not designated as hedging instruments		1			1			1		—		—
Additional disclosures:
Notes receivable and other		10			10			N/A		N/A		N/A
Long-term debt, including current portion		(7,237	)		(8,170	)		N/A		N/A		N/A

Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets and liabilities measured at fair value on a recurring basis

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

Energy derivatives: Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist solely of swaps that are measured at fair value on a recurring basis. The tenure of our energy derivatives portfolio is relatively short with all of our energy derivatives expiring in the next nine months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives are reported in other current assets and other accrued liabilities in the Consolidated Balance Sheet.

Energy derivatives considered Level 1 measurements consist of New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets.

Energy derivatives included in our Level 2 measurements consist solely of OTC 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.

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 transfers between Level 1 and Level 2 occurred during the six months ended June 30, 2012 or 2011.

Additional fair value disclosures

Notes receivable and other: The disclosed fair value of our notes receivable is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion of the notes is reported in accounts and notes receivable and the noncurrent portion of the notes is reported in regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.

Long-term debt: The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Notes (Continued)

Customer margin deposits payable: The disclosed fair value of our customer margin deposits payable is considered to approximate the carrying value generally due to the short-term nature of these items and are reported in other accrued liabilities in the Consolidated Balance Sheet.

Guarantees

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain 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.

Note 9. Derivative Instruments

Energy Commodity Derivatives

Risk management activities

We are exposed to market risk from changes in energy commodity prices within our operations. We 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 June 30, 2012. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLs are presented in barrels.

Notes (Continued)

Derivative Notional Volumes

Unit of
Measure

Central Hub
Risk

Basis Risk

Designated as Hedging Instruments

Midstream

Barrels

(1,770,000

)

Midstream

MMBtu

7,810,800

6,504,400

Not Designated as Hedging Instruments

Midstream

Barrels

115,000

255,000

Gains (losses)

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


	Three months ended June 30,					Six months ended June 30,
	2012		2011			2012		2011			Classification
	(Millions)
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	55	$	(4	)	$	46	$	(6	)	AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	8	$	(4	)	$	6	$	(4	)	Revenues or Costs and Operating Expenses

There were no gains or losses recognized in income as a result of hedge ineffectiveness, as a result of reclassifications to earnings following the discontinuance of any cash flow hedges, or as a result of excluding amounts from the assessment of hedge effectiveness.

We recognized gains of $1 million and losses of $1 million in revenues for the six months ended June 30, 2012 and 2011, respectively, on our energy commodity derivatives not designated as hedging instruments. We also recognized gains and losses of less than $1 million in revenues for the three months ended June 30, 2012 and 2011, respectively, on our energy commodity derivatives not designated as hedging instruments. In addition, we recognized gains of less than $1 million in costs and operating expenses for the six months ended June 30, 2012, 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 other, including changes in noncurrent assets and liabilities.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.

At both June 30, 2012, and December 31, 2011, we did not have any collateral posted, either in the form of cash or letters of credit, to derivative counterparties.

Notes (Continued)

Cash flow hedges

Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of June 30, 2012, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales through the end of 2012. Based on recorded values at June 30, 2012, $40 million of net gains will be reclassified into earnings within the next six months. These recorded values are based on market prices of the commodities as of June 30, 2012. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next six months will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

Note 10. 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. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of June 30, 2012, we have accrued liabilities totaling $17 million for these matters, as discussed below. Our accrual reflects 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. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent 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 June 30, 2012, we have accrued liabilities of $9 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 June 30, 2012, we have accrued liabilities totaling $8 million for these costs.

Notes (Continued)

Rate Matters

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

The one issue reserved for litigation or further settlement relates to Transco’s proposal to change the design of the rates for service under one of its storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one party filed an appeal in the U.S. Court of Appeals for the D.C. Circuit challenging the FERC’s orders approving our rate design proposal.

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.

Note 11. 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.

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

•

Gas Pipeline—depreciation and operation and maintenance expenses;

•

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

Notes (Continued)

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


	Gas Pipeline		Midstream		Total
	(Millions)
*Three months ended June 30, 2012*
Segment revenues	$	399	$	1,184	$	1,583

Segment profit	$	147	$	192	$	339
Less equity earnings		16		11		27

Segment operating income	$	131	$	181		312

General corporate expenses						(46	)

Total operating income					$	266

*Three months ended June 30, 2011*
Segment revenues	$	407	$	1,264	$	1,671

Segment profit	$	152	$	319	$	471
Less equity earnings		14		22		36

Segment operating income	$	138	$	297		435

General corporate expenses						(27	)

Total operating income					$	408

*Six months ended June 30, 2012*
Segment revenues	$	821	$	2,447	$	3,268

Segment profit	$	327	$	500	$	827
Less equity earnings		33		24		57

Segment operating income	$	294	$	476		770

General corporate expenses						(82	)

Total operating income					$	688

*Six months ended June 30, 2011*
Segment revenues	$	823	$	2,427	$	3,250

Segment profit	$	327	$	581	$	908
Less equity earnings		23		38		61

Segment operating income	$	304	$	543		847

General corporate expenses						(57	)

Total operating income					$	790

The following table reflects total assets by reporting segment.


	Total Assets
	June 30, 2012			December 31, 2011
	(Millions)
Gas Pipeline	$	8,506		$	8,348
Midstream (1)		10,321			6,591
Other corporate assets		82			226
Eliminations (2)		(869	)		(785	)

Total	$	18,040		$	14,380

Notes (Continued)

(1)	The increase in Midstream’s total assets as compared to the prior year-end is substantially due to the Laser and Caiman Acquisitions. (See Note 2.)

(2)	Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and natural gas liquids (NGLs). 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 13,700 miles of pipelines. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), which owns an approximate 745-mile pipeline. Our ownership interest in Gulfstream has increased by 1 percent, a result of a second-quarter 2012 acquisition from a subsidiary of The Williams Companies, Inc. (Williams).

•

Midstream is comprised primarily of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and NGL fractionation and transportation assets. Midstream’s assets also include substantial operations and investments in the Four Corners region, the Piceance basin, as well as an NGL fractionator and storage facilities near Conway, Kansas.

Williams currently holds an approximate 68 percent interest in us, comprised of an approximate 66 percent limited partner interest and all of our 2 percent general partner interest.

Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10-Q and Amendment No. 1 to our 2011 Annual Report on Form 10-K/A, filed April 9, 2012.

Acquisitions

In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. This acquisition represents a strategic platform to enhance our expansion in the Marcellus Shale by providing our customers with both operational flow assurance and marketing flexibility. (See Results of Operations—Segments, Midstream.)

In April 2012, we completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition). The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. We believe the acquisition will provide us with a significant footprint and growth potential in the natural gas liquids-rich portion of the Marcellus Shale. (See Results of Operations—Segments, Midstream.)

Distributions

In July 2012 our general partner’s Board of Directors approved a 2 percent increase to our quarterly distribution to unitholders. (See Management’s Discussion and Analysis of Financial Condition and Liquidity.)

Management’s Discussion and Analysis (Continued)

Overview of Six Months Ended June 30, 2012

Net Income for the six months ended June 30, 2012, changed unfavorably by $104 million compared to the six months ended June 30, 2011, primarily due to lower NGL marketing and production margins that were significantly impacted by a sharp decline in NGL prices during the second quarter of 2012. (See Results of Operations—Segments, Midstream.)

Our net cash provided by operating activities for the six months ended June 30, 2012, decreased $15 million compared to the six months ended June 30, 2011, primarily due to lower operating income partially offset by increased distributions received from equity-method investees.

Recent Events

•

In February 2012, we announced a new interstate gas pipeline project. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We currently own 75 percent of Constitution Pipeline. This project, along with the newly acquired Laser Gathering System and our Springville pipeline are key steps in our strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania. In April 2012, we began the Federal Energy Regulatory Commission (FERC) pre-filing process for this project and expect to file a FERC application in January 2013.

•

In April 2012, we completed an equity issuance of 10 million common units representing limited partner interests in us at a price of $54.56 per unit. Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. We also sold 16,360,133 common units to Williams for $1 billion. The net proceeds of these transactions were used for general partnership purposes, including funding a portion of the cash purchase price of the Caiman Acquisition.

•

In July 2012, we announced a new project to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. The parties anticipate investing approximately $800 million in potential development over the next several years, of which we expect to fund approximately $380 million.

•

Following Williams’ spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of the growth plans of the ongoing business, Williams has initiated an effort to better align resources to support our business strategy in 2012 and beyond. This initiative is designed to enhance capabilities and determine the right organization – throughout the business areas and shared-services functions—to execute that strategy. Williams has engaged a consulting firm to assist with this project and expects to implement changes later this year through early 2013. It is likely that the recommendations arising from this effort will result in changes in our current organizational structure that will impact how our businesses are managed and thus could result in changes to our future segment reporting structure beginning in 2013.

•

In July 2012, we announced our intent to pursue an agreement to acquire Williams’ 83.3 percent interest and operatorship of an olefins-production facility located in Geismar, Louisiana. We expect to fund the transaction largely with the issuance of limited-partner units to Williams. The transaction is subject to execution of an agreement, review and recommendation by the conflicts committee of our general partner, and approval of both our and Williams’ board of directors.

Management’s Discussion and Analysis (Continued)

Company Outlook

As previously discussed, NGL margins declined sharply during the second quarter of 2012, largely attributable to a record-warm winter, a slowing global economy, and growing NGL supplies. We expect NGL margins to remain depressed in the near-term, with some anticipated recovery by the end of the year. However, economic and commodity price indicators can be volatile and it is reasonably possible that the global economy could worsen and/or energy commodity margins could further decline, negatively impacting our future operating results. Over the next few years, we expect the influence of NGL margins on our operating results to diminish as we transition to an overall business mix that is increasingly fee-based.

Our business plan for the remainder of 2012 continues to reflect both growth in distributions, as previously mentioned, and significant capital investments. Our planned capital investments total approximately $5.885 billion, including equity issued in association with the previously discussed acquisitions. We expect to fund a significant portion of these activities through debt and equity issuances. We expect to maintain an attractive cost of capital and reliable access to capital markets, both of which will allow us to pursue development projects and acquisitions. We expect to realize our growth opportunities through these continued investments in our businesses in a way that meets customer needs and enhances our competitive position by:

•

Continuing to invest in and grow our midstream businesses 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:

•

General economic, financial markets, or industry downturn;

•

Lower than anticipated energy commodity margins;

•

Availability of capital;

•

Lower than expected levels of cash flow from operations;

•

Counterparty credit and performance risk;

•

Decreased volumes from third parties served by our midstream business;

•

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 disciplined investment strategies, commodity hedging strategies, and maintaining ample liquidity from cash and cash equivalents and unused revolving credit facility capacity.

Williams incurs certain corporate general and administrative costs which are charged to its business segments, including us. We expect an increase in our proportionate share of these costs in 2012, due in part to Williams’ December 2011 spin-off of WPX, its former exploration and production business.

Critical Accounting Estimate

We completed the Laser Acquisition in February 2012 and the Caiman Acquisition in April 2012. Based on the preliminary fair value measurements, our June 30, 2012, Consolidated Balance Sheet includes $724 million of goodwill related to these acquisitions. (See Note 2 of Notes to Consolidated Financial Statements.) We are currently evaluating the appropriate reporting unit for the allocation of the goodwill within the Midstream segment. We are required to evaluate the goodwill for impairment annually or more frequently if impairment indicators are present. Our evaluation will include a qualitative assessment of events or circumstances to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If so, we will further compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss will be recognized in the amount of the excess.

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2012, compared to the three and six months ended June 30, 2011. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three months ended June 30,											Six months ended June 30,
	2012			2011			$ Change*		% Change*			2012			2011			$ Change*		% Change*
	(Millions)											(Millions)
Revenues	$	1,583		$	1,671			-88		-5	%	$	3,268		$	3,250			+18		+1	%
Costs and expenses:
Costs and operating expenses		1,163			1,167			+4		—			2,300			2,274			- 26		-1	%
Selling, general, and administrative expenses		95			70			- 25		-36	%		180			141			- 39		-28	%
Other (income) expense—net		13			(1	)		- 14		NM			18			(12	)		- 30		NM
General corporate expenses		46			27			- 19		-70	%		82			57			- 25		-44	%

Total costs and expenses		1,317			1,263								2,580			2,460
Operating income		266			408								688			790
Equity earnings		27			36			- 9		-25	%		57			61			- 4		-7	%
Interest accrued—net		(105	)		(104	)		- 1		-1	%		(212	)		(210	)		- 2		-1	%
Interest income		—			—			—		—			1			1			—		—
Other income (expense)—net		5			(2	)		+7		NM			7			3			+4		+133	%

Net income	$	193		$	338			- 145		-43	%	$	541		$	645			- 104		-16	%

*	+ = 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 June 30, 2012 vs. three months ended June 30, 2011

The decrease in revenues is primarily due to lower natural gas liquid (NGL) production revenues at Midstream reflecting an overall significant decrease in average NGL per-unit sales prices in the second quarter of 2012. This decrease is partially offset by Midstream’s increased fee revenues primarily due to higher gathering and processing fee revenues resulting from new volumes on our recently acquired natural gas gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses of the Marcellus Shale and higher volumes on our gathering assets in the western deepwater Gulf of Mexico. Additionally, Gas Pipeline transportation revenues increased primarily due to expansion projects placed into service in 2011.

The decrease in costs and operating expenses is primarily due to decreased costs at Midstream associated with production of NGLs reflecting lower average natural gas prices. This decrease is partially offset by Midstream’s increased marketing purchases primarily due to higher volumes, partially offset by significantly lower average NGL prices as well as Midstream’s higher operating costs resulting from our acquisition transactions in 2012 and increased maintenance expenses, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

The increase in selling, general, and administrative expenses (SG&A) is primarily due to an increase at Midstream reflecting acquisition and transition-related costs as well as higher information technology and employee-related expenses driven by general growth within Midstream’s business operations.

Other (income) expense—net within operating income in 2012 includes $9 million project feasibility costs at Gas Pipeline.

Management’s Discussion and Analysis (Continued)

The increase in general corporate expenses is primarily due to an increase in our proportionate share of these costs as a result of Williams’ spin-off of its former exploration and production business, which was completed on December 31, 2011.

The decrease in operating income generally reflects lower NGL production margins due to unfavorable energy commodity price changes in 2012 as compared to 2011, a decrease in margins related to the marketing of NGLs and higher operating costs and SG&A, partially offset by increased fee revenues as previously discussed.

Equity earnings decreased primarily due to lower Laurel Mountain Midstream, LLC (Laurel Mountain) and Discovery Producer Services LLC (Discovery) equity earnings at Midstream primarily due to lower operating results.

Six months ended June 30, 2012 vs. six months ended June 30, 2011

The increase in revenues is primarily due to higher fee revenues at Midstream resulting from increased gathering and processing fee revenues from new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses of the Marcellus Shale and higher volumes on our gathering assets in the western deepwater Gulf of Mexico and our onshore assets in the West. In addition, marketing revenues at Midstream increased due to higher volumes, partially offset by lower average NGL prices primarily in the second quarter of 2012. Gas Pipeline transportation revenues increased primarily due to expansion projects placed into service in 2011. Partially offsetting these increases is Midstream’s lower NGL production revenue reflecting an overall decrease in average NGL per-unit sales prices, driven by a sharp decline in the second quarter of 2012.

The increase in costs and operating expenses is primarily due to increased marketing purchases at Midstream primarily due to higher volumes, partially offset by lower average NGL prices. In addition, operating costs at Midstream increased resulting from our acquisition transactions in 2012 and higher maintenance expenses, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations. These increases are partially offset by decreased costs at Midstream associated with production of NGLs reflecting a decrease in average natural gas prices.

The increase in SG&A is primarily due to an increase at Midstream reflecting acquisition and transition-related costs as well as higher information technology and employee-related expenses driven by general growth within Midstream’s business operations.

The unfavorable change in other (income) expense – net within operating income primarily reflects a $13 million increase in project feasibility costs and the absence of a $10 million reversal of project feasibility costs from expense to capital in 2011 at Gas Pipeline.

The decrease in operating income generally reflects a decrease in margins related to the marketing of NGLs, lower NGL production margins due to unfavorable energy commodity price changes in the second quarter of 2012 as compared to 2011, and higher SG&A and operating costs, partially offset by increased fee revenues as previously discussed.

Equity earnings decreased primarily due to lower Laurel Mountain, Aux Sable Liquid Products LP (Aux Sable), and Discovery equity earnings at Midstream primarily reflecting lower operating results, partially offset by an increase in equity earnings at Gas Pipeline primarily resulting from the acquisition of an additional 24.5 percent interest in Gulfstream in May 2011.

Management’s Discussion and Analysis (Continued)

Results of Operations—Segments

Gas Pipeline

Overview of Six Months Ended June 30, 2012

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.

Outlook for the Remainder of 2012

Expansion projects

Constitution Pipeline

In April 2012, we began the FERC pre-filing process for a new interstate gas pipeline project. We currently own a 75 percent interest in the project and will be the operator. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the project is estimated to be $748 million. We plan to place the project into service in March 2015, with an expected capacity of 650 thousand dekatherms per day (Mdth/d). The pipeline is fully subscribed with two shippers. We expect to file a FERC application in January 2013.

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 expected increase in capacity of 225 Mdth/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 is expected to increase capacity by 142 Mdth/d. We plan to place the project into service in November 2012.

Northeast Supply Link

In December 2011, we filed an application with the FERC to expand our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The cost of the project is estimated to be $341 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in November 2013.

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 $90 million, which is expected to be spent through the first half of 2013. As of June 30, 2012, we have incurred approximately $57 million in cumulative abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. 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 8 of Notes to Consolidated Financial Statements.)

Filing of Rate Cases

Pursuant to the terms of Transco’s most recent rate settlement agreement, Transco must file a new rate case no later than August 31, 2012.

During the first quarter of 2012, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for an increase in their rates. Northwest Pipeline received FERC approval during the second quarter of 2012. The new rates, which as filed are 7.4 percent higher than current rates, will become effective January 1, 2013.

Period-Over-Period Operating Results


	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(Millions)				(Millions)
Segment revenues	$	399	$	407	$	821	$	823

Segment profit	$	147	$	152	$	327	$	327

Three months ended June 30, 2012 vs. three months ended June 30, 2011

Segment revenues decreased $8 million, or 2 percent, primarily due to $15 million lower system management gas sales (offset in costs and operating expenses). This decrease is partially offset by an $8 million increase in transportation revenues associated with expansion projects placed in service in 2011.

Costs and operating expenses decreased $11 million, or 5 percent, primarily due to $15 million lower system management gas costs (offset in segment revenues).

Other income (expense)—net changed unfavorably by $11 million primarily due to an $8 million increase in project feasibility costs incurred in 2012.

Segment profit decreased primarily due to the previously described changes.

Six months ended June 30, 2012 vs. six months ended June 30, 2011

Management’s Discussion and Analysis (Continued)

Segment revenues decreased $2 million primarily due to $28 million lower system management gas sales (offset in costs and operating expenses). The decrease is partially offset by a $26 million increase in transportation revenues associated with expansion projects placed in service in 2011.

Costs and operating expenses decreased $24 million, or 5 percent, primarily due to $28 million lower system management gas costs (offset in segment revenues) and $6 million lower operations and maintenance expense related to the Eminence Storage Field Leak. These decreases are partially offset by a $5 million increase in employee related expenses.

Equity earnings improved $10 million primarily due to the acquisition of an additional 24.5 percent interest in Gulfstream in May 2011.

Other income (expense) – net changed unfavorably by $29 million primarily due to a $13 million increase in project feasibility costs and the absence of a $10 million first-quarter 2011 reversal of project feasibility costs from expense to capital, associated with an expansion project, upon determining that the related project was probable of development.

Segment profit remained consistent primarily due to the previously described changes.

Midstream Gas & Liquids

Overview of Six Months Ended June 30, 2012

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 2012 include the following:

Caiman Acquisition

In April 2012, we completed the Caiman Acquisition for consideration valued at approximately $2.3 billion. The transition of operations is under way.

The acquisition will provide us with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. The existing physical assets that we acquired include a gathering system, two processing facilities, and a fractionator located in northern West Virginia and establish our new Ohio Valley Midstream business. In addition to the acquisition cost, we are committing a large portion of our planned 2012 capital expenditures for expansions to the gathering system, processing facilities, and fractionator, which are currently under construction. NGL pipelines are also planned. The assets are anchored by long-term contracted commitments, including 236,000 dedicated gathering acres from 10 producers in West Virginia, Ohio, and Pennsylvania.

The Fort Beeler plant complex has 320 million cubic feet per day (MMcf/d) of cryogenic processing capacity currently available with another 200 MMcf/d expected to be in service at the end of 2012. The Moundsville fractionator is expected to be in service by the end of the year with approximately 13 thousand barrels per day (Mbbls/d) of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator, is in the final stages of completion.

Utica Shale Infrastructure Project

We completed an agreement with Caiman Energy, LLC and others to develop midstream infrastructure serving oil and natural gas producers in the Utica Shale, primarily in Ohio and northwest Pennsylvania. The parties anticipate investing approximately $800 million, over the next several years, to develop natural gas gathering and processing and the associated liquids infrastructure, of which our share is expected to be approximately $380 million.

Management’s Discussion and Analysis (Continued)

Susquehanna Supply Hub, northeastern Pennsylvania

In February 2012, we completed the Laser Acquisition for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 of our common units valued at $441 million. The gathering system is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments.

Our Springville pipeline was placed into service in January 2012, allowing us to deliver approximately 300 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 650 MMcf/d of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvania’s Marcellus Shale which we acquired at the end of 2010. In conjunction with a long-term agreement with a significant producer, we are operating the 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline. Expansions to the Springville compression facilities in 2012 are expected to increase the capacity to approximately 625 MMcf/d.

As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 billion cubic feet per day (Bcf/d) by 2015, including capacity contributions from the Constitution Pipeline associated with our Gas Pipeline segment.

Volatile commodity prices

Average per-unit NGL margins declined sharply in the second quarter of 2012 and were approximately 7 percent lower in the first half of 2012 than in the same period of 2011. Key factors in the NGL market weakness have been high propane inventories caused by the extremely warm winter and the effect of the propane oversupply on ethane inventories and pricing. Lower natural gas prices driven by abundant natural gas supplies partially offset the weaker NGL prices.

NGL margins are defined as NGL revenues less any applicable British thermal unit (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 2012

The following factors could impact our business in 2012.

Commodity price changes

•

We expect our average per-unit NGL margins to be slightly lower than the second quarter of 2012 with some recovery later in the year, with the full year 2012 lower than 2011 and comparable to 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 11 percent to 14 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink natural gas requirements for the remainder of 2012. The combined impact of these energy commodity derivatives, designated as cash flow hedges will provide a margin on the hedged volumes of $122 million. The following table presents our energy commodity hedging instruments as of June 30, 2012.

Management’s Discussion and Analysis (Continued)


	Period		Volumes Hedged		Weighted Average Hedge Price
Designated as hedging instruments:						(per gallon	)
NGL sales—propane (million gallons)		Jul—Dec 2012		16.4	$	1.31
NGL sales—isobutane (million gallons)		Jul—Dec 2012		15.1	$	1.95
NGL sales—normal butane (million gallons)		Jul—Dec 2012		15.1	$	1.82
NGL sales—natural gasoline (million gallons)		Jul—Dec 2012		27.7	$	2.32
						(per MMbtu	)
Natural gas purchases (Tbtu)		Jul—Dec 2012		7.8	$	2.62

Gathering, processing, and NGL sales volumes

•

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

•

In our onshore businesses, we anticipate significant growth in our natural gas gathering volumes as our infrastructure grows to support drilling activities in our Ohio Valley Midstream and Susquehanna Supply Hub businesses in the Marcellus Shale region. We anticipate equity NGL volumes in 2012 to be comparable to 2011. Sustained low natural gas prices could discourage producer drilling activities in our onshore areas and unfavorably impact the supply of natural gas available to gather and process in the long term.

•

In our Gulf Coast businesses, we expect higher gas gathering, processing, and crude transportation volumes compared to the latter half of 2011, as production flowing through our Perdido Norte pipelines becomes consistent 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. In the Gulf Coast, our customers’ drilling activities are primarily focused on crude oil economics, rather than natural gas. We have not experienced, and do not anticipate an overall significant decline in volumes due to reduced drilling activities.

•

We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in the Marcellus Shale area, Piceance basin, and western Gulf of Mexico.

Expansion Projects

We expect to invest total capital of $5.2 billion to $5.4 billion in 2012. We plan to pursue expansion and growth opportunities in the Marcellus Shale region, Gulf of Mexico, and Piceance basin.

Our ongoing major expansion projects include the following:

•

Expansion of our Susquehanna Supply Hub in northeastern Pennsylvania, as previously discussed.

•

As previously discussed, expansions currently under construction to our natural gas gathering system, processing facilities and fractionator in our Ohio Valley Midstream business of the Marcellus Shale.

•

Expansions to our gathering system through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region. The Shamrock compressor station, currently providing 60 MMcf/d of capacity, is expandable to 350 MMcf/d and will likely be the largest central delivery point out of the Laurel Mountain system. Our equity investee is progressing on further expansions to the Shamrock compressor station and other additions to the gathering infrastructure in 2012.

•

We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach 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. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014.

Management’s Discussion and Analysis (Continued)

•

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

•

Our equity investee which we operate, Discovery, plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon Block in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from those fields. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery’s existing 30-inch offshore natural gas transmission system. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. Pre-construction activities have begun, the pipeline is expected to be laid in 2013, and is planned to be in-service in mid-2014.

•

Through our equity investment in Overland Pass Pipeline Company LLC, we are participating in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, 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.

Period-Over-Period Operating Results


	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
			(Millions)
Segment revenues	$	1,184	$	1,264	$	2,447	$	2,427

Segment profit	$	192	$	319	$	500	$	581

Three months ended June 30, 2012 vs. three months ended June 30, 2011

The decrease in segment revenues includes:

•

A $118 million decrease in revenues from our equity NGLs reflecting a decrease of $99 million associated with an overall 30 percent decrease in average NGL per-unit sales prices, driven by a sharp decline in the second quarter of 2012. Average ethane and non-ethane per-unit prices decreased by 50 percent and 18 percent, respectively.

•

A $41 million increase in fee revenues primarily due to new volumes on our recently acquired natural gas gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses of the Marcellus Shale and higher volumes on our Perdido Norte natural gas and oil pipelines in the western deepwater Gulf of Mexico.

Segment costs and expenses increased $36 million, or 4 percent, including:

•

A $36 million increase in marketing purchases primarily due to higher NGL volumes, partially offset by significantly lower average NGL prices.

•

A $32 million increase in operating costs including new depreciation and maintenance costs associated with assets acquired in early 2012 and higher turbine and engine maintenance expenses, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

Management’s Discussion and Analysis (Continued)

•

A $26 million increase in general and administrative expenses including $18 million of Caiman and Laser acquisition and transition-related costs, and increases in information technology and employee-related expenses driven by general growth within our business operations.

•

A $54 million decrease in costs associated with our equity NGLs primarily due to a 48 percent decrease in average natural gas prices.

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

The decrease in Midstream’s segment profit includes:

•

A $64 million decrease in NGL margins reflecting a $99 million decrease related to significantly lower NGL prices, partially offset by a $49 million decrease in shrink costs due to significantly lower natural gas prices.

•

A $32 million increase in operating costs as previously discussed.

•

A $32 million decrease in margins related to the marketing of NGLs, primarily due to the impact of a significant and rapid decline in NGL prices while product was in transit during the second quarter of 2012 compared to periods of increasing prices during the second quarter of 2011.

•

A $26 million increase in general and administrative expenses as previously discussed.

•

An $11 million decrease in equity earnings primarily due to lower equity earnings of $7 million for Laurel Mountain and $5 million for Discovery. The decrease at Laurel Mountain is driven by higher operating costs including depreciation and lower gathering rates indexed to natural gas prices, partially offset by higher gathered volumes. The decrease at Discovery is primarily due to lower NGL margins.

•

A $41 million increase in fee revenues as previously discussed.

Six months ended June 30, 2012 vs. six months ended June 30, 2011

The increase in segment revenues includes:

•

An $82 million increase in fee revenues primarily due to new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses of the Marcellus Shale and higher volumes on our Perdido Norte natural gas and oil pipelines in the western deepwater Gulf of Mexico. In addition, gathering volumes are higher in our onshore assets in the West due primarily to the absence of severe winter weather conditions in the first quarter of 2011 which limited producers’ ability to deliver natural gas and higher volumes in the Piceance basin.

•

A $53 million increase in marketing revenues primarily due to higher NGL volumes, partially offset by lower average NGL prices, primarily in the second quarter of 2012. The changes in NGL marketing revenues are more than offset by similar changes in NGL marketing purchases.

•

A $111 million decrease in revenues from our equity NGLs reflecting a decrease of $105 million associated with an overall 18 percent decrease in average NGL per-unit sales prices, driven by a sharp decline in the second quarter of 2012. Average ethane and non-ethane per-unit prices decreased by 32 percent and 8 percent, respectively.

Management’s Discussion and Analysis (Continued)

Segment costs and expenses increased $87 million, or 5 percent, including:

•

A $103 million increase in marketing purchases primarily due to higher NGL volumes, partially offset by lower average NGL prices.

•

A $36 million increase in general and administrative expenses including $19 million of Caiman and Laser acquisition and transition-related costs, and increases in information technology and employee-related expenses driven by general growth within our business operations.

•

A $31 million increase in operating costs including new depreciation and maintenance costs associated with assets acquired in early 2012 and higher turbine and engine maintenance expenses, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

•

An $82 million decrease in costs associated with our equity NGLs primarily due to a 37 percent decrease in average natural gas prices.

The decrease in Midstream’s segment profit includes:

•

A $50 million decrease in margins related to the marketing of NGLs, primarily due to the impact of a significant and rapid decline in NGL prices during the second quarter of 2012 while product was in transit compared to periods of increasing prices during 2011.

•

A $36 million increase in general and administrative expenses as previously discussed.

•

A $31 million increase in operating costs as previously discussed.

•

A $29 million decrease in NGL margins driven primarily by commodity price changes including a $105 million decrease related to lower NGL prices, partially offset by a $73 million increase related to lower natural gas prices.

•

A $14 million decrease in equity earnings primarily due to lower equity earnings of $10 million for Laurel Mountain, $3 million for Aux Sable, and $3 million for Discovery. The decrease at Laurel Mountain is driven by higher operating costs including depreciation and lower gathering rates indexed to natural gas prices, partially offset by higher gathered volumes.

•

An $82 million increase in fee revenues as previously discussed.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

The sharp decline in NGL margins during the second quarter of 2012 and our related expectation of depressed near-term NGL margins has reduced the expected level of operating cash flows from certain of our businesses in 2012. Although our cash flows are impacted by fluctuations in energy commodity prices, further reduction in expected energy commodity prices would be 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.

Over the longer-term, we expect the influence of short-term changes in commodity prices on our cash flows to diminish as we transition to an overall business mix that is increasingly fee-based.

We continue to 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 2012:

•

We increased our per-unit quarterly distribution with respect to the second quarter of 2012 from $0.7775 to $0.7925. We expect to increase quarterly limited partner cash distributions by approximately 8 percent in 2012.

•

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 $1.725 billion and $1.925 billion in 2012.

•

In July 2012, Transco received net proceeds of $395 million from the issuance of $400 million of 4.45 percent senior unsecured notes due in 2042. The expected use of proceeds included repayment of Transco’s $325 million 8.875 percent notes upon their maturity on July 15, 2012, and general corporate purposes, including capital expenditures.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2012. 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;

•

Use of our credit facility, as needed and available.

We anticipate our more significant uses of cash to be:

•

Maintenance and expansion capital expenditures;

Management’s Discussion and Analysis (Continued)

•

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;

•

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 2012 levels;

•

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


Available Liquidity	June 30, 2012
	(Millions)
Cash and cash equivalents	$	34
Capacity available under our $2 billion five-year senior unsecured revolving credit facility (expires June 3, 2016) (1)		1,655

	$	1,689

(1)

The full amount of the 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 June 30, 2012, we are in compliance with the financial covenants associated with this credit facility agreement.

Shelf Registration

In February 2012, 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, Discovery, Gulfstream, Laurel Mountain, and Overland Pass Pipeline Company LLC.

Equity Offerings

In April 2012, we completed an equity issuance of 10,000,000 common units representing limited partner interests in us at a price of $54.56 per unit. Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition.

Management’s Discussion and Analysis (Continued)

In April 2012, in connection with the Caiman Acquisition, we also issued 16,360,133 common units to Williams for $1 billion, which was used to fund a portion of the cash purchase price.

In January 2012, we completed an equity issuance of 7,000,000 common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, we sold an additional 1,050,000 common units for $62.81 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $490 million were used to fund capital expenditures and for general partnership purposes.

Additionally, we issued equity to the sellers for acquisitions as discussed below.

Acquisitions

In April 2012, we completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC in exchange for aggregate consideration of $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 of our common units.

In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of our common units.

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	March 5, 2012	Stable	BBB
Moody’s Investors Service	February 27, 2012	Stable	Baa2
Fitch Ratings	February 9, 2012	Positive	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 June 30, 2012, we estimate that a downgrade to a rating below investment grade could require us to post up to $199 million in additional collateral with third parties.

Management’s Discussion and Analysis (Continued)

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.

The following table provides summary information related to our actual and expected capital expenditures and purchases of businesses and investments for 2012. The amounts presented for expansion do not include equity issued in association with the Laser and Caiman Acquisitions of approximately $1 billion. Included are gross increases to our property, plant, and equipment, including changes related to accounts payable and accrued liabilities:


	Maintenance				Expansion				Total
Segment	2012 Estimate		Six Months Ended June 30, 2012		2012 Estimate		Six Months Ended June 30, 2012		2012 Estimate		Six Months Ended June 30, 2012
	(Millions)
Gas Pipeline	$	315—365	$	120	$	270— 320	$	147	$	585— 685	$	267
Midstream		90—110		54		3,875—4,055		2,716		3,965—4,165		2,770

Total	$	405—475	$	174	$	4,145—4,375	$	2,863	$	4,550—4,850	$	3,037

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. We have increased our quarterly distribution from $0.7775 to $0.7925 per unit, which resulted in a second-quarter 2012 distribution of approximately $373 million that will be paid on August 10, 2012, to the general and limited partners of record at the close of business on August 3, 2012. (See Note 3 of Notes to Consolidated Financial Statements).

Williams has agreed to temporarily waive its incentive distribution rights related to the common units issued to Williams and the seller of Caiman Eastern Midstream, LLC, in connection with our acquisition of that entity, which we estimate would be approximately $24 million in 2012.

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash


	Six months ended June 30,
	2012			2011
	(Millions)
Net cash provided (used) by:
Operating activities	$	968		$	983
Financing activities		1,824			(468	)
Investing activities		(2,921	)		(590	)

Increase (decrease) in cash and cash equivalents	$	(129	)	$	(75	)

Operating activities

Net cash provided by operating activities for the six months ended June 30, 2012, decreased $15 million compared to the six months ended June 30, 2011, due primarily to lower operating income, partially offset by increased distributions received from our equity-method investees.

Financing activities

Significant transactions include:

•

$581 million received from our second-quarter 2012 equity offering used for general partnership purposes, including the funding of a portion of the cash purchase price of the acquisition of Caiman Eastern Midstream, LLC;

•

$1 billion received from Williams for common units issued, used for the funding of a portion of the cash purchase price of the acquisition of Caiman Eastern Midstream, LLC;

•

$490 million received from our first-quarter 2012 equity offering used to fund capital expenditures and for general partnership purposes;

•

$500 million received in revolver borrowings from our $2 billion unsecured credit facility for capital expenditures and general partnership purposes in May 2012;

•

$155 million of revolver borrowings paid during second quarter 2012;

•

$673 million and $544 million related to quarterly cash distributions paid to limited partner unitholders and our general partner in 2012 and 2011, respectively;

•

$300 million received in revolver borrowings from our previous $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011. This obligation was transferred to our $2 billion credit facility at its inception 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.

Investing activities

Significant transactions include:

•

$1.72 billion paid, net of purchase price adjustments, for the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC from Caiman Energy, LLC in April 2012;

•

$325 million paid, net of cash acquired in the transaction, for the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC in March 2012;

Management’s Discussion and Analysis (Continued)

•

$174 million related to our acquisition of a 24.5 percent interest in Gulfstream from Williams in May 2011;

•

Capital expenditures in 2012 and 2011 totaled $741 million and $309 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 8 and 10 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 six months of 2012.

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 energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets and our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining a conservative capital structure and significant liquidity, as well as using various derivatives and non derivative energy-related 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 9 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.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value-at-risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value-at-risk.

Trading

Our limited trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net asset of less than $0.1 million at June 30, 2012 and December 31, 2011. The value-at-risk for contracts held for trading purposes was zero at June 30, 2012 and less than $0.1 million at December 31, 2011.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from natural gas purchase and NGL sale activities. The fair value of our nontrading derivatives was a net asset of $41 million at June 30, 2012 and a net asset of $1 million at December 31, 2011. The value-at-risk for derivative contracts held for nontrading purposes was $2 million at June 30, 2012, and zero at December 31, 2011.

Certain of the derivative contracts held for nontrading purposes are accounted for as cash flow hedges. Of the total fair value of nontrading derivatives, cash flow hedges had a net asset value of $41 million at June 30, 2012 and a net asset value of zero at December 31, 2011. Though these contracts are included in our value-at-risk calculation, any changes in the fair value of the effective portion 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.

Second-Quarter 2012 Changes in Internal Controls

There have been no changes during the second quarter of 2012 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 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 September 2011, the Colorado Department of Public Health and Environment issued a Notice of Violation for alleged violations of the Colorado Clean Water Act related to excavation work being done for our Crawford Trail Pipeline. In June 2012, we agreed to a settlement in principle with the agency for $275,000.

Other

The additional information called for by this item is provided in Note 10 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, 2011, 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:

The existence and potential sale of common units issued to third parties in our acquisitions may adversely affect the price of our common units.

We have issued 7,531,381 additional common units to Delphi Midstream Partners, LLC in connection with the Laser Acquisition, which are subject to certain trading restrictions that expire over time beginning April 17, 2012. We have issued 11,779,296 additional common units to Caiman Energy, LLC in connection with the Caiman Acquisition, which are subject to restriction on transfer for a period of 18 months without our consent. We may also issue additional common units to other unaffiliated third parties in connection with future acquisitions. Sales of substantial amounts of common units by third parties, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.

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, 7, and 8.

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 July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.

Exhibit 4.2	—	Registration Rights Agreement, dated July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on July 16, 2012 as Exhibit 10.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.

*Exhibit 10.1	—	First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P.

*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.

*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.

**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.

**Exhibit 101.INS	—	XBRL Instance Document.

**Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.

**Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.

**Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.

**Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.

**Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

*	Filed herewith.

**	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

Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

August 2, 2012

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, 7, and 8.

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 July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.

Exhibit 4.2	—	Registration Rights Agreement, dated July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on July 16, 2012 as Exhibit 10.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.

*Exhibit 10.1		First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P.

*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges

*Exhibit 31.1	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

*Exhibit 31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

**Exhibit 32	—	Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.

**Exhibit 101.INS	—	XBRL Instance Document

**Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema


Exhibit No.		Description

**Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase

**Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase

**Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase

**Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase

*	Filed herewith.

**	Furnished herewith.