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

Form 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 March 31, 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 316,058,540 common units outstanding as of April 23, 2012.

Williams Partners L.P.

Index


	Page
Part I. Financial Information

Item 1. Financial Statements

Consolidated Statement of Comprehensive Income — Three Months Ended March 31, 2012 and 2011		4

Consolidated Balance Sheet — March 31, 2012 and December 31, 2011		5

Consolidated Statement of Changes in Equity — Three Months Ended March 31, 2012		6

Consolidated Statement of Cash Flows — Three Months Ended March 31, 2012 and 2011		7

Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

Item 3. Quantitative and Qualitative Disclosures About Market Risk		36

Item 4. Controls and Procedures		38

Part II. Other Information		38

Item 1. Legal Proceedings		38

Item 1A. Risk Factors		39

Item 6. Exhibits		40

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

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

•

Amounts and nature of future capital expenditures;

•

Expansion and growth of our business and operations;

•

Financial condition and liquidity;

•

Business strategy;

•

Cash flow from operations or results of operations;

•

The levels of cash distributions to unitholders;

•

Seasonality of certain business 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 March 31,
	2012			2011
	(Millions, except per-unit amounts)

Revenues:
Gas Pipeline	$	422		$	416
Midstream Gas & Liquids		1,263			1,163

Total revenues		1,685			1,579
Segment costs and expenses:
Costs and operating expenses		1,134			1,105
Selling, general, and administrative expenses		88			73
Other (income) expense – net		5			(11	)

Segment costs and expenses		1,227			1,167
General corporate expenses		36			30

Operating income:
Gas Pipeline		163			166
Midstream Gas & Liquids		295			246
General corporate expenses		(36	)		(30	)

Total operating income		422			382
Equity earnings		30			25
Interest accrued		(110	)		(108	)
Interest capitalized		3			2
Interest income		1			1
Other income (expense) – net		2			5

Net income	$	348		$	307


Allocation of net income for calculation of earnings per common unit:
Net income	$	348		$	307
Allocation of net income to general partner		94			71

Allocation of net income to common units	$	254		$	236


Basic and diluted net income per common unit	$	0.85		$	0.81
Weighted average number of common units outstanding (thousands)		299,269			289,845
Cash distributions per common unit	$	0.7775		$	0.7175

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

Other comprehensive income (loss)		(6	)		(2	)

Comprehensive income	$	342		$	305

See accompanying notes.

Williams Partners L.P.

Consolidated Balance Sheet

(Unaudited)


	March 31, 2012			December 31, 2011
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	263		$	163
Accounts and notes receivable:
Trade		477			484
Affiliate		1			9
Inventories		135			148
Regulatory assets		40			40
Other current assets		85			70

Total current assets		1,001			914
Investments		1,410			1,383

Gross property, plant, and equipment		18,169			17,755
Less accumulated depreciation		(6,249	)		(6,128	)

Property, plant, and equipment – net		11,920			11,627
Goodwill and other intangibles		667			43
Regulatory assets, deferred charges, and other		407			413

Total assets	$	15,405		$	14,380


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	523		$	554
Affiliate		79			57
Accrued interest		108			105
Asset retirement obligations		72			66
Other accrued liabilities		157			166
Long-term debt due within one year		325			324

Total current liabilities		1,264			1,272
Long-term debt		6,913			6,913
Asset retirement obligations		499			503
Regulatory liabilities, deferred income, and other		489			464
Contingent liabilities (Note 10)
Equity:
Common units (306,058,540 units outstanding at March 31, 2012 and 290,477,159 units outstanding at December 31, 2011)		7,801			6,810
General partner		(1,553	)		(1,580	)
Accumulated other comprehensive income (loss)		(8	)		(2	)

Total equity		6,240			5,228

Total liabilities and equity	$	15,405		$	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		263			85			—			348
Other comprehensive income (loss)		—			—			(6	)		(6	)
Cash distributions		(227	)		(84	)		—			(311	)
Sale of common units to public		490			—			—			490
Issuance of common units related to acquisition		465			—			—			465
Contributions from general partner		—			26			—			26

Balance – March 31, 2012	$	7,801		$	(1,553	)	$	(8	)	$	6,240

See accompanying notes.

Williams Partners L.P.

Consolidated Statement of Cash Flows

(Unaudited)


	Three months ended March 31,
	2012			2011
	(Millions)

OPERATING ACTIVITIES:
Net income	$	348		$	307
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization		156			150
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		9			13
Inventories		13			22
Other assets and deferred charges		11			13
Accounts payable		(65	)		65
Accrued liabilities		(13	)		12
Affiliate accounts receivable and payable – net		30			(64	)
Other, including changes in noncurrent assets and liabilities		24			(7	)

Net cash provided by operating activities		513			511


FINANCING ACTIVITIES:
Proceeds from sales of common units		490			—
General partner contributions		26			—
Distributions to limited partners and general partner		(311	)		(268	)
Other – net		(2	)		(1	)

Net cash provided (used) by financing activities		203			(269	)


INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(256	)		(156	)
Net proceeds from dispositions		9			(8	)
Purchases of business and investments		(373	)		(36	)
Other – net		4			3

Net cash used by investing activities		(616	)		(197	)

Increase (decrease) in cash and cash equivalents		100			45
Cash and cash equivalents at beginning of period		163			187

Cash and cash equivalents at end of period	$	263		$	232

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 March 31, 2012, Williams owns an approximate 70 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 49 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream).

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

Comprehensive Income

In January 2012, we adopted Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5) and Accounting Standards Update No. 2011-12, “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12). ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. ASU 2011-5 also requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income. The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. ASU 2011-12 defers

Notes (Continued)

the effective date for only the presentation requirements related to reclassifications in ASU 2011-5. During this deferral period, ASU 2011-12 provides that we should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12. Net income and other comprehensive income (loss) are now presented in a single continuous statement.

Note 2. Acquisition

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 $465 million (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. The acquisition was accounted for as a business combination which, among other things, requires 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.

The amounts recognized in the financial statements are preliminary because our valuation work has not been completed. We are awaiting further information for valuing the property, plant and equipment, intangible assets, assets held for sale, environmental and 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 major classes of the assets acquired, which are presented in the Midstream segment:


Assets held for sale	$	20
Other current assets		3
Property, plant and equipment		158
Intangible assets		329
Goodwill		297
Other current liabilities		(17	)

Total	$	790

Intangible assets recognized in the acquisition are primarily related to gas gathering agreements with customers. Those intangible assets are being amortized on a straight-line basis over a 30-year period during which the customer contracts are expected to contribute to our cash flows. Goodwill recognized in the acquisition 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 at least 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 Acquisition included within the Consolidated Financial Statements are not material. Supplemental pro forma revenue and earnings on a combined basis for the periods presented are also not material as the Laser Gathering System began operations in October 2011.

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 months ended March 31, 2012 and 2011 is as follows:


	Three months ended March 31,
	2012			2011
	(Millions)
Allocation of net income to general partner:
Net income	$	348		$	307
Net reimbursable costs charged directly to general partner		—			(2	)

Income subject to 2% allocation of general partner interest		348			305
General partner’s share of net income		2	%		2	%

General partner’s allocated share of net income before items directly allocable to general partner interest		7			6
Incentive distributions paid to general partner (a)		78			59
Net reimbursable costs charged directly to general partner		—			2

Net income allocated to general partner	$	85		$	67

Net income	$	348		$	307
Net income allocated to general partner		85			67

Net income allocated to common limited partners	$	263		$	240

(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 basic and diluted net income per limited partner unit for the three months ended March 31, 2012 is not expected to be significantly impacted by additional units that may be issued to the seller or sold to Williams in conjunction with the acquisition of ownership interests in Caiman Eastern Midstream, LLC (see Note 12) prior to the record date for the distribution to be paid on May 11, 2012, due to the temporary waiver of IDRs associated with these units.

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 (b)	$	0.7775	$	246	$	7	$	87	$	340

(b)

The Board of Directors of our general partner declared this $0.7775 per unit cash distribution on April 23, 2012, to be paid on May 11, 2012, to unitholders of record at the close of business on May 4, 2012. The amounts to be distributed do not reflect additional units to be issued to the seller or sold to Williams in conjunction with the acquisition of ownership interests in Caiman Eastern Midstream, LLC. (See Note 12). If such units are outstanding on the date of record, the total cash distribution would increase by approximately $23 million.

Notes (Continued)

Note 4. Other Accruals

Other (income) expense — net within segment costs and expenses in 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


	March 31, 2012		December 31, 2011
	(Millions)

Natural gas liquids and natural gas in underground storage	$	69	$	80
Materials, supplies, and other		66		68

	$	135	$	148

Note 6. Debt and Banking Arrangements

Credit Facility

Letter of credit capacity under our $2 billion credit facility is $1.3 billion. At March 31, 2012, no letters of credit have been issued and no loans are outstanding under the credit facility.

Issuances and Retirements

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 proceeds were used to fund capital expenditures and for other partnership purposes.

On February 17, 2012, we closed the acquisition of certain entities from Delphi Midstream Partners, LLC. (See Note 2.) In connection with this transaction, we issued 7,531,381 of our common units valued at $465 million.

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 proceeds were used for general partnership purposes.

Notes (Continued)

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 March 31, 2012:

Recurring basis:
ARO Trust investments	$	24		$	24		$	24		$	—		$	—
Energy derivatives assets not designated as hedging instruments		5			5			1			4			—
Energy derivatives assets designated as hedging instruments		2			2			1			1			—
Energy derivatives liabilities not designated as hedging instruments		(4	)		(4	)		(1	)		(3	)		—
Energy derivatives liabilities designated as hedging instruments		(10	)		(10	)		(7	)		(3	)		—

Additional disclosures:
Notes receivable and other		26			26			16			10			—
Long-term debt, including current portion		(7,238	)		(8,112	)		—			(8,112	)		—

Assets (liabilities) at December 31, 2011:

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 our fair-value disclosures for 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. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

Notes (Continued)

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 12 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 and option pricing models. 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 three months ended March 31, 2012 or 2011.

Additional fair value disclosures

Notes receivable and other: Notes receivable and other disclosed at fair value primarily include margin deposits, which are reported in other current assets in the Consolidated Balance Sheet. The carrying value of our notes receivable are considered to approximate the fair value generally due to the nature of the related interest rates and our assessment of our ability to recover these amounts using an income approach.

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.

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.

Notes (Continued)

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

We sell NGL volumes received as compensation for certain processing services at different locations throughout the United States. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas market prices, we may enter into NGL or natural gas swap agreements, financial or physical forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas. Those designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.

Volumes

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

•

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

•

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

The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of March 31, 2012. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLs are presented in barrels.


Derivative Notional Volumes	Unit of Measure	Central Hub Risk			Basis Risk

Designated as Hedging Instruments
Midstream	Barrels		(2,205,000	)
Midstream	MMBtu		9,503,750			8,101,250

Not Designated as Hedging Instruments
Midstream	Barrels		120,000			345,000

Notes (Continued)

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 March 31,
	2012			2011			Classification
	(Millions)

Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	(9	)	$	(2	)	AOCI

Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	(2	)	$	—		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 less than $1 million in revenues for the three months ended March 31, 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 three months ended March 31, 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 changes in other assets and deferred charges and changes in accrued 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.

As of March 31, 2012, we have collateral totaling $6 million, all of which is in the form of cash, posted to derivative counterparties to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $8 million. The additional collateral that we would be required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions of our derivative contracts was triggered, was $2 million. At December 31, 2011, we did not have any collateral posted, either in the form of cash or letters of credit, to derivative counterparties since we had net derivative asset positions with all our counterparties.

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

Notes (Continued)

period. As of March 31, 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 March 31, 2012, $8 million of net losses will be reclassified into earnings within the next nine months. These recorded values are based on market prices of the commodities as of March 31, 2012. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next nine 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 March 31, 2012, we have accrued liabilities totaling $18 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 March 31, 2012, we have accrued liabilities of $10 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 March 31, 2012, we have accrued liabilities totaling $8 million for these costs.

Rate Matters

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

Notes (Continued)

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.

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 March 31, 2012*
Segment revenues	$	422	$	1,263	$	1,685

Segment profit	$	180	$	308	$	488
Less equity earnings		17		13		30

Segment operating income	$	163	$	295		458

General corporate expenses						(36	)

Total operating income					$	422


*Three months ended March 31, 2011*
Segment revenues	$	416	$	1,163	$	1,579

Segment profit	$	175	$	262	$	437
Less equity earnings		9		16		25

Segment operating income	$	166	$	246		412

General corporate expenses						(30	)

Total operating income					$	382

The following table reflects total assets by reporting segment.


	Total Assets
	March 31, 2012			December 31, 2011
	(Millions)

Gas Pipeline	$	8,441		$	8,348
Midstream		7,681			6,591
Other corporate assets		319			226
Eliminations (1)		(1,036	)		(785	)


Total	$	15,405		$	14,380

(1)	Primarily relates to the elimination of intercompany accounts receivable generated by our cash management program.

Note 12. Subsequent Events

In March 2012, we announced that we had entered into an agreement with Caiman Energy, LLC to acquire 100 percent of the ownership interests in Caiman Eastern Midstream, LLC (Caiman Acquisition), which operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio, for $1.78 billion in cash and approximately 11.8 million of our common units, valued at approximately $720 million in the transaction. The Caiman Acquisition is expected to close during the second quarter of 2012, subject to customary closing conditions.

We had obtained a backup financing commitment for up to a $1.78 billion interim liquidity facility with UBS Investment Bank which would have been available to fund the full cash purchase price for the Caiman Acquisition, if necessary. This commitment has been terminated as it is not expected to be utilized.

Notes (Continued)

In April 2012, we completed an equity issuance of 10 million common units representing limited partner interests at a price of $54.56 per unit. Subsequently, the underwriters exercised their option to purchase approximately 1 million additional common units for $54.56 per unit. The net proceeds will be used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition, together with the proceeds of the expected sale of up to approximately 16.4 million common units to Williams for approximately $1 billion.

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 49 percent interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), which owns an approximate 745-mile pipeline.

•

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.

The Williams Companies, Inc. (Williams) currently holds an approximate 69 percent interest in us, comprised of an approximate 67 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 for $325 million in cash, net of cash acquired in the transaction, and approximately 7.5 million of our common units (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 March 2012, we announced our agreement to acquire 100 percent of the ownership interests in Caiman Eastern Midstream, LLC from Caiman Energy, LLC (Caiman Energy) in exchange for $1.78 billion in cash, subject to certain purchase price adjustments, and approximately 11.8 million of our common units representing limited partner interests valued at $720 million in the transaction (Caiman Acquisition). Caiman Energy has agreed that it will not transfer these units for a period of 18 months after the closing of the transaction without our written consent. The Caiman Acquisition is expected to close during the second quarter of 2012. We plan to fund the cash portion of the transaction with a combination of cash on hand, the expected sale of approximately $1 billion of our common units to Williams, and the incurrence of bank borrowings as needed. (See Results of Operations — Segments, Midstream.)

Distributions

In April 2012 our 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.)

Overview of Three Months Ended March 31, 2012

Net Income for the three months ended March 31, 2012, changed favorably by $41 million compared to the three months ended March 31, 2011, primarily due to increased fee revenues and improved NGL margins partially offset by an increase in selling, general and administrative (SG&A) expenses and the absence of a $10 million first-quarter 2011 reversal of project feasibility costs from expense to capital. (See Results of Operations — Consolidated Overview.)

Our net cash provided by operating activities for the three months ended March 31, 2012, increased $2 million compared to the three months ended March 31, 2011, primarily due to higher operating income and increased distributions from equity-method investees, largely offset by net unfavorable changes in working capital.

Recent Events

•

In February 2012, we announced a new interstate gas pipeline joint venture. 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 expect to own a majority 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 completed an equity issuance of 10 million common units representing limited partner interests in us at a price of $54.56 per unit. Subsequently, the underwriters exercised their option to purchase approximately 1 million additional common units for $54.56 per unit. The proceeds will be used to fund general partnership purposes, including funding of a portion of the previously discussed Caiman Acquisition.

Company Outlook

We believe we are well-positioned to continue to execute on our 2012 business plan and to further realize our growth opportunities. Economic and commodity price indicators for 2012 and beyond reflect continued improvement in the economic environment. However, these measures can be volatile and it is reasonably possible that the economy could worsen and/or commodity prices could decline, negatively impacting our future operating results.

Our business plan for 2012 includes planned capital investments of approximately $5.9 billion, including equity issued or expected to be issued in association with the previously discussed acquisitions. We expect to fund a significant portion of these activities through debt and equity issuances. Our structure is designed to drive lower capital costs, enhance reliable access to capital markets, and create a greater ability 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 gathering and processing and interstate natural gas pipeline systems;

•

Retaining the flexibility to adjust, to some extent, our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

Management’s Discussion and Analysis (Continued)

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

•

Availability of capital;

•

General economic, financial markets, or industry downturn;

•

Lower than anticipated energy commodity margins;

•

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’ spin-off of its former exploration and production business, which was completed on December 31, 2011.

Critical Accounting Estimate

In February 2012, we completed the Laser Acquisition, which includes a gathering system 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. As a result of the acquisition, we have recorded $297 million of goodwill as of March 31, 2012. (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 at least 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 months ended March 31, 2012, compared to the three months ended March 31, 2011. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Three months ended March 31,
	2012			2011			$ Change*		% Change*
	(Millions)

Revenues	$	1,685		$	1,579			+106		+7	%
Costs and expenses:
Costs and operating expenses		1,134			1,105			-29		-3	%
Selling, general and administrative expenses		88			73			-15		-21	%
Other (income) expense – net		5			(11	)		-16		NM
General corporate expenses		36			30			-6		-20	%

Total costs and expenses		1,263			1,197
Operating income		422			382
Equity earnings		30			25			+5		+20	%
Interest accrued – net		(107	)		(106	)		-1		-1	%
Interest income		1			1			—		—
Other income (expense) – net		2			5			-3		-60	%

Net income	$	348		$	307			+41		+13	%

*	+ = 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 March 31, 2012 vs. three months ended March 31, 2011

The increase in revenues is primarily due to higher marketing revenues at Midstream resulting from higher volumes, partially offset by lower average NGL prices. Additionally, fee revenues increased at Midstream primarily due to higher gathering and processing fee revenues primarily resulting from higher volumes on our gathering assets in the Marcellus Shale, in the western deepwater Gulf of Mexico and our onshore assets in the West. Gas Pipeline transportation revenues increased primarily due to expansion projects placed into service in 2011.

The increase in costs and operating expenses is primarily due to increased marketing purchases at Midstream primarily resulting from higher volumes, partially offset by lower average NGL prices. This increase is partially offset by decreased costs at Midstream associated with production of NGLs reflecting lower average natural gas prices.

The increase in selling, general and administrative expenses (SG&A) is primarily due to a $10 million increase at Midstream reflecting higher information technology and employee-related expenses driven by general growth within Midstream’s business operations.

Other (income) expense — net within operating income in 2011 includes a $10 million reversal of project feasibility costs from expense to capital at Gas Pipeline.

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 increase in operating income generally reflects increased fee revenues and increased NGL margins due to favorable energy commodity price changes in 2012 compared to 2011, partially offset by unfavorable changes in SG&A and other (income) expense — net as previously discussed.

Management’s Discussion and Analysis (Continued)

Results of Operations — Segments

Gas Pipeline

Overview of Three Months Ended March 31, 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

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 thousand dekatherms per day (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.

Eminence Storage Field Leak

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

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. We estimate the total abandonment costs, which will be capital in nature, will be approximately $76 million, which

Management’s Discussion and Analysis (Continued)

is expected to be spent through the first half of 2013. As of March 31, 2012, we have incurred approximately $44 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 March 31,
	2012		2011
	(Millions)

Segment revenues	$	422	$	416

Segment profit	$	180	$	175

Three months ended March 31, 2012 vs. three months ended March 31, 2011

Segment revenues increased $6 million, or 1 percent, primarily due to an $18 million increase in transportation revenues associated with expansion projects placed in service in 2011. This increase is partially offset by $12 million lower system management gas sales (offset in costs and operating expenses).

Costs and operating expenses decreased $14 million, or 6 percent, primarily due to $12 million lower system management gas costs (offset in segment revenues).

Other income (expense) — net changed unfavorably by $18 million primarily due to 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. Also contributing to the variance is an increase in project feasibility costs incurred in 2012.

Segment profit increased primarily due to the previously described changes.

Midstream Gas & Liquids

Overview of Three Months Ended March 31, 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.

Management’s Discussion and Analysis (Continued)

Significant events during 2012 include the following:

Caiman Acquisition

In March 2012, we announced an agreement to acquire Caiman Energy’s wholly owned subsidiary, Caiman Eastern Midstream LLC (Caiman), for approximately $2.5 billion. We expect to complete the acquisition in the second quarter of 2012, subject to customary closing conditions. (See Note 12 of Notes to Consolidated Financial Statements.)

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. Caiman’s existing physical assets include a gathering system, two processing facilities and a fractionator located in northern West Virginia and eastern Ohio. In addition to the acquisition cost, we are committing a large portion of our planned 2012 capital expenditures for expansions to the gathering, processing and fractionation facilities, 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.

We also intend to participate in a new joint venture with Caiman Energy and its investors and management to develop midstream infrastructure in the NGL- and oil-rich areas of the Utica Shale in Ohio.

Susquehanna Supply Hub

Our Susquehanna Supply Hub is an integrated gathering infrastructure in the Marcellus Shale area of northeastern Pennsylvania including gathering assets acquired in December 2010, various compression and dehydration expansion projects, additional gathering and take away facilities acquired in February 2012, and our newly constructed Springville pipeline.

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 approximately 7.5 million of our common units valued at $465 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, providing new take-away capacity and allowing full use of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvania’s Marcellus Shale. In conjunction with a long-term agreement with a significant producer, we are operating the 33-mile, 24-inch diameter natural gas gathering pipeline and plan to increase the capacity in 2012.

As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a gas take away capacity of 3 billion cubic feet per day (Bcf/d) by 2015.

Volatile commodity prices

Average per-unit NGL margins in the first quarter of 2012 were 11 percent higher than in the same period of 2011, benefiting from lower natural gas prices driven by abundant natural gas supplies, partially offset by weaker NGL prices, primarily ethane.

NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

Management’s Discussion and Analysis (Continued)

LOGO

Outlook for Remainder of 2012

The following factors could impact our business in 2012.

Commodity price changes

•

We expect our average per-unit NGL margins in 2012 to be comparable to 2011 and higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets.

•

As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of approximately 10 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink gas requirements for the remainder of 2012. The combined impact of these energy commodity derivatives will provide a margin on the hedged volumes of $169 million. The following table presents our energy commodity hedging instruments as of April 20, 2012.

Management’s Discussion and Analysis (Continued)


	Period		Volumes Hedged		Weighted Average Hedge Price
					(per gallon)
Designated as hedging instruments:
NGL sales – propane (million gallons)		Apr - Dec 2012		24.6	$	1.31
NGL sales – isobutane (million gallons)		Apr - Dec 2012		18.9	$	1.94
NGL sales – normal butane (million gallons)		Apr - Dec 2012		18.7	$	1.80
NGL sales – natural gasoline (million gallons)		Apr - Dec 2012		40.5	$	2.32
					(per MMbtu)
Natural gas purchases (Tbtu)		Apr - Dec 2012		10.7	$	2.63

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 gas gathering volumes as our infrastructure grows to support drilling activities in northeast Pennsylvania. We anticipate slight increases in gas gathering volumes in the Piceance basin and no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. We anticipate equity NGL volumes in 2012 to be comparable to 2011, as we expect little change in the volume of gas processed in the western onshore businesses. Sustained low 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. Our customers’ drilling activities are primarily focused on crude oil economics, rather than natural gas and we have not experienced, and do not anticipate, an overall significant decline in volumes due to reduced drilling activities.

•

The operator of the third-party fractionator serving our NGL production transported on Overland Pass Pipeline Company LLC (OPPL) has notified us of an expected 20- to 25-day outage in the second quarter of 2012 to accommodate their expansion efforts. We have taken steps to mitigate the impact and expect the outage will result in a minimal reduction to our equity volumes.

•

We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in northeast Pennsylvania, Piceance basin, and western Gulf of Mexico.

Expansion Projects

We expect to invest total capital of $5.0 billion to $5.2 billion in 2012, including equity consideration of $465 million for the Laser Acquisition and $720 million for the Caiman Acquisition. 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 and assuming closing of the Caiman Acquisition, expansions currently under construction to the gas gathering system, processing facilities and fractionator, which we’ve agreed to acquire from Caiman Energy.

Management’s Discussion and Analysis (Continued)

•

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 million cubic feet per day (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 thousand barrels per day (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.

•

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

•

Our equity investee, Discovery Producer Services LLC (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 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 OPPL, we plan to participate 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 March 31,
	2012		2011
	(Millions)

Segment revenues	$	1,263	$	1,163

Segment profit	$	308	$	262

Three months ended March 31, 2012 vs. three months ended March 31, 2011

The increase in segment revenues includes:

•

A $44 million increase in marketing revenues primarily due to higher volumes, partially offset by lower average NGL prices. These changes are more than offset by similar changes in marketing purchases.

•

A $41 million increase in fee revenues primarily due to higher gathering and processing fee revenues primarily associated with higher volumes on our Susquehanna Supply Hub gathering assets in the Marcellus Shale in northeastern Pennsylvania and on our Perdido Norte 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 gas.

Management’s Discussion and Analysis (Continued)

•

A $7 million increase in revenues from our equity NGLs reflecting an increase of $12 million associated with a 7 percent increase in equity NGL volumes, partially offset by decrease of $5 million associated with an overall decrease in average NGL per-unit sales prices. Average ethane per-unit prices decreased by 11 percent, partially offset by a 3 percent increase in non-ethane prices.

Segment costs and expenses increased $51 million, or 6 percent, including:

•

A $67 million increase in marketing purchases primarily due to higher volumes, partially offset by lower average NGL prices. These changes are largely offset by similar changes in marketing revenues.

•

A $10 million increase in general and administrative expenses reflecting increases in information technology and employee-related expenses driven by general growth within our business operations.

•

A $28 million decrease in costs associated with our equity NGLs primarily due to a 25 percent decrease in average natural gas prices.

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

The increase in Midstream’s segment profit includes:

•

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

•

A $35 million increase in NGL margins reflecting a $19 million increase from favorable commodity price changes primarily due to a 25 percent decrease in average natural gas prices, partially offset by an 11 percent decline in ethane prices. NGL equity volumes sold are 7 percent higher primarily due to the return to normal production from the first quarter of 2011 when severe winter weather conditions prevented producers from delivering gas and the plants experienced more downtime for maintenance.

•

A $23 million decrease in margins related to the marketing of NGLs.

•

A $10 million increase in general and administrative expenses as previously discussed.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

For 2012, we expect continued strong operating results and cash flows due to the combination of continued strong energy commodity margins and the start-up of certain expansion capital projects. However, energy commodity prices are volatile and difficult to predict. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, as follows:

•

Firm demand and capacity reservation transportation revenues under long-term contracts at Gas Pipeline;

•

Fee-based revenues from certain gathering and processing services at Midstream.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following for 2012:

•

We increased our per-unit quarterly distribution with respect to the first quarter of 2012 from $0.7625 to $0.7775. We expect to increase quarterly limited partner cash distributions by approximately 6 percent to 10 percent annually.

•

As of March 31, 2012, we have $325 million of current debt maturities. We anticipate funding these maturities with new debt issuances.

•

We expect to fund capital and investment expenditures, debt service payments, distributions to unitholders and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or long-term debt issuances and utilization of our revolving credit facility as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.85 billion and $2.35 billion in 2012.

•

In March 2012, we agreed to acquire Caiman Eastern Midstream, LLC in exchange for aggregate consideration of $1.78 billion cash and approximately 11.8 million of our limited partner units. We expect to fund the cash portion of the transaction with a combination of equity, debt, and available cash. We anticipate completing the acquisition during the second quarter of 2012.

•

In connection with the Caiman Acquisition, we expect to issue up to approximately 16.4 million common units to Williams for approximately $1 billion. Williams has agreed to temporarily waive its incentive distribution rights related to the units issued to Williams and the seller of Caiman Eastern Midstream, LLC, in connection with the Caiman Acquisition, which we estimate would be approximately $26 million in 2012.

•

During 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, the underwriters exercised their option to purchase approximately 1 million additional common units for $54.56 per unit. The net proceeds of approximately $581 million will be used for general partnership purposes, including the funding of a portion of the purchase price of the Caiman Acquisition.

Management’s Discussion and Analysis (Continued)

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:

•

The Caiman Acquisition;

•

Maintenance and expansion capital expenditures;

•

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

•

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

•

Interest on our long-term debt;

•

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


	March 31, 2012
	(Millions)

Cash and cash equivalents	$	263
Capacity available under our $2 billion five-year senior unsecured revolving credit facility (expires June 3, 2016) (1)		2,000

	$	2,263

(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 March 31, 2012, we are in compliance with the financial covenants associated with this credit facility agreement.

Management’s Discussion and Analysis (Continued)

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 Liquid Products LP, Discovery Producer Services LLC, Gulfstream, Laurel Mountain Midstream, LLC, and Overland Pass Pipeline Company LLC.

Equity Offerings

In January 2012, we completed an equity issuance of 7 million common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, the underwriters exercised their option to purchase an additional 1.05 million common units for $62.81 per unit. The net proceeds of approximately $490 million were used to fund capital expenditures and for general partnership purposes.

Acquisition

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 approximately 7.5 million 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.

Management’s Discussion and Analysis (Continued)

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 March 31, 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.

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 purchase of business and investments for 2012. These amounts reflect total increases to our balance sheet as a result of these activities. The amounts presented for the 2012 Estimate of Expansion do not include equity issued in association with the Laser Acquisition of approximately $465 million or equity expected to be issued in association with the Caiman Acquisition of approximately $720 million. 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		Three Months Ended March 31, 2012		2012 Estimate		Three Months Ended March 31, 2012		2012 Estimate		Three Months Ended March 31, 2012
	(Millions)
Gas Pipeline	$	330-380	$	40	$	270-320	$	62	$	600-700	$	102
Midstream		115-135		23		3,850-4,030		530		3,965-4,165		553

Total	$	445-515	$	63	$	4,120-4,350	$	592	$	4,565-4,865	$	655

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 $0.7625 to $0.7775 per unit, which is expected to result in a first-quarter 2012 distribution of approximately $340 million that will be paid on May 11, 2012, to the general and limited partners of record at the close of business on May 4, 2012. (See Note 3 of Notes to Consolidated Financial Statements).

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash


	Three months ended March 31,
	2012			2011
	(Millions)
Net cash provided (used) by:
Operating activities	$	513		$	511
Financing activities		203			(269	)
Investing activities		(616	)		(197	)

Increase (decrease) in cash and cash equivalents	$	100		$	45

Operating activities

Net cash provided by operating activities for the three months ended March 31, 2012, is consistent with the same period in 2011.

Financing activities

Significant transactions include:

•

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

•

$311 million and $268 million related to quarterly cash distributions paid to limited partner unitholders and our general partner in 2012 and 2011, respectively.

Investing activities

Significant transactions include:

•

$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.

•

Capital expenditures in 2012 and 2011 totaled $256 million and $156 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 three 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 $1 million at March 31, 2012. The value-at-risk for contracts held for trading purposes was less than $0.1 million at March 31, 2012 and 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 liability of $8 million at March 31, 2012 and a net asset of $1 million at December 31, 2011.

The value-at-risk for derivative contracts held for nontrading purposes was $2.3 million at March 31, 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 liability value of $8 million as of March 31, 2012. 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.

First-Quarter 2012 Changes in Internal Controls

There have been no changes during the first 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.

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 expect to issue 11,779,296 additional common units to Caiman Energy in connection with the Caiman Acquisition, which will be 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, and 7 (filed on February 21, 2011 as Exhibit 3.3 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference.

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

Exhibit 4.1	—	Registration Rights Agreement dated as of February 17, 2012, by and among Delphi Midstream Partners LLC and Williams Partners L.P. (filed on March 2, 2012 as Exhibit 4.5 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-179883)) and incorporated herein by reference.

*Exhibit 10.1	—	Contribution Agreement, dated as of March 19, 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)

April 26, 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 and 7 (filed on February 24, 2011 as Exhibit 3.3 to Williams Partners L.P.’s annual report on Form 10-K (File No. (File No. 001-32599)) and incorporated herein by reference.

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

Exhibit 4.1	—	Registration Rights Agreement dated as of February 17, 2012, by and among Delphi Midstream Partners LLC and Williams Partners L.P. (filed on March 2, 2012 as Exhibit 4.5 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-179883)) and incorporated herein by reference.

*Exhibit 10.1		Contribution Agreement, dated as of March 19, 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 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase


Exhibit No.		Description

**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.