UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2008

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

For the transition period from                      to                     

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)

(918) 573-2000
(Registrant’s telephone number, including area code)

NO CHANGE

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

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

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

Large accelerated filer þ                      Accelerated filer o                      Non-accelerated filer o                      Smaller reporting company o

                                             (Do not check if a smaller reporting company)

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

     The registrant had 52,774,728 common units outstanding as of April 30, 2008.

 

 

WILLIAMS PARTNERS L.P.
INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statements of Income — Three Months Ended March 31, 2008 and 2007			3
Consolidated Balance Sheets — March 31, 2008 and December 31, 2007			4
Consolidated Statements of Cash Flows — Three Months Ended March 31, 2008 and 2007			5
Consolidated Statement of Partners’ Capital from January 1, 2008 to March 31, 2008			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 3. Quantitative and Qualitative Disclosures About Market Risk			35
Item 4. Controls and Procedures			36
Part II. Other Information
Item 1. Legal Proceedings			37
Item 1A. Risk Factors			37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			37
Item 6. Exhibits			39
Amended and Restated Agreement
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer

FORWARD-LOOKING STATEMENTS

     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 statements discuss our expected future results based on current and pending business operations.

     All statements, other than statements of historical facts, included in this report which 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,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

	•		amounts and nature of future capital expenditures;
	•		expansion and growth of our business and operations;
	•		business strategy;
	•		cash flow from operations;
	•		seasonality of certain business segments; and
	•		natural gas liquids and gas 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 document. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

•

We may not have sufficient cash from operations to enable us to pay the minimum distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

	•		Because of the natural decline in production from existing wells and competitive factors, the success of our gathering and transportation businesses depends on our ability to connect new sources of natural gas supply, which is dependent on factors beyond our control. Any decrease in supplies of natural gas could adversely affect our business and operating results.
	•		Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.
	•		Our processing, fractionation and storage businesses could be affected by any decrease in natural gas liquids (NGL) prices or a change in NGL prices relative to the price of natural gas.
	•		We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.
	•		If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.
	•		We do not own all of the interests in Wamsutter, the Conway fractionator or Discovery, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.
	•		Our results of storage and fractionation operations are dependent upon the demand for propane and other NGLs. A substantial decrease in this demand could adversely affect our business and operation results.
	•		Discovery and Wamsutter may reduce their cash distributions to us in some situations.
	•		Discovery’s interstate tariff rates and terms and conditions are subject to review and possible adjustment by federal regulators, and are subject to changes in policy by federal regulators which could have a material adverse effect on our business and operating results.
	•		Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
	•		We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.
	•		Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
	•		Williams’ public indentures and our credit facility contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.
	•		Our future financial and operating flexibility may be adversely affected by restrictions in our debt agreements and by our leverage.
	•		We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make payments on our debt obligations and distributions on our common units.
	•		Common units held by Williams eligible for future sale may have adverse effects on the price of our common units.
	•		Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interests with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.
	•		Even if unitholders are dissatisfied, they currently have little ability to remove our general partner without its consent.

     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.

     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, 2007, and Part II, Item 1A. Risk Factors of this quarterly report on Form 10-Q.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

WILLIAMS PARTNERS L.P.

		Three Months Ended
		March 31,
		2008				2007*
Revenues:
Product sales:
Affiliate		$	78,122			$	56,552
Third-party			4,221				6,313
Gathering and processing:
Affiliate			8,790				9,491
Third-party			46,210				51,103
Storage			7,333				6,410
Fractionation			3,292				1,917
Other			2,394				2,029
Total revenues			150,362				133,815
Costs and expenses:
Product cost and shrink replacement:
Affiliate			22,033				21,725
Third-party			30,065				20,470
Operating and maintenance expense (excluding depreciation):
Affiliate			23,133				14,328
Third-party			23,951				28,185
Depreciation, amortization and accretion			11,226				13,178
General and administrative expense:
Affiliate			9,876				9,406
Third-party			928				664
Taxes other than income			2,505				2,114
Other expense — net			333				460
Total costs and expenses			124,050				110,530
Operating income			26,312				23,285
Equity earnings-Wamsutter			21,194				11,328
Equity earnings-Discovery Producer Services			13,621				3,931
Interest expense:
Affiliate			(25	)			(15	)
Third-party			(17,711	)			(14,375	)
Interest income			238				983
Net income		$	43,629			$	25,137
Allocation of net income for calculation of earnings per unit:
Net income		$	43,629			$	25,137
Allocation of net income to general partner			8,911				12,912
Allocation of net income to limited partners		$	34,718			$	12,225
Basic and diluted net income per limited partner unit:
Common units		$	0.66			$	0.31
Subordinated units		$	0.66			$	0.31
Weighted average number of units outstanding:
Common units			49,005,497				32,358,798
Subordinated units			3,769,231				7,000,000

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		March 31,				December 31,
		2008				2007
		(Unaudited)
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	34,555			$	36,197
Accounts receivable:
Trade			19,129				12,860
Affiliate			33,036				20,402
Other			3,852				2,543
Product imbalance			15,600				20,660
Prepaid expense			3,588				4,056
Derivative assets — affiliate			1,488				231
Reimbursable projects			3,555				8,989
Assets held for sale			11,296				11,519
Other current assets			3,727				3,574
Total current assets			129,826				121,031
Investment in Wamsutter			283,163				284,650
Investment in Discovery Producer Services			211,783				214,526
Property, plant and equipment, net			631,908				630,770
Other noncurrent assets			30,426				32,500
Total assets		$	1,287,106			$	1,283,477
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable:
Trade		$	36,208			$	35,947
Affiliate			27,329				17,676
Product imbalance			15,578				21,473
Deferred revenue			1,266				4,569
Derivative liabilities — affiliate			1,521				2,718
Accrued interest			12,043				19,500
Other accrued liabilities			8,872				8,243
Total current liabilities			102,817				110,126
Long-term debt			1,000,000				1,000,000
Environmental remediation liabilities			2,321				2,599
Other noncurrent liabilities			9,383				9,265
Commitments and contingent liabilities (Note 9)
Partners’ capital			172,585				161,487
Total liabilities and partners’ capital		$	1,287,106			$	1,283,477

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		Three Months Ended
		March 31,
		2008				2007*
		(In thousands)
OPERATING ACTIVITIES:
Net income		$	43,629			$	25,137
Adjustments to reconcile to cash provided by operations:
Depreciation, amortization and accretion			11,226				13,178
Amortization of gas purchase contract — affiliate			—				1,188
Equity earnings of Wamsutter			(21,194	)			(11,328	)
Equity earnings of Discovery Producer Services			(13,621	)			(3,931	)
Distributions related to equity earnings of Wamsutter			22,703				—
Distributions related to equity earnings of Discovery Producer Services			13,621				2,620
Cash provided (used) by changes in assets and liabilities:
Accounts receivable			(20,212	)			(1,436	)
Prepaid expense			467				1,188
Other current assets			5,282				(335	)
Accounts payable			9,914				11,055
Product imbalance			(835	)			(183	)
Accrued liabilities			(7,214	)			15,460
Deferred revenue			(3,364	)			(3,012	)
Other, including changes in non-current liabilities			1,120				215
Net cash provided by operating activities			41,522				49,816
INVESTING ACTIVITIES:
Capital expenditures			(11,556	)			(9,766	)
Cumulative distributions in excess of equity earnings of Discovery Producer Services			3,179				980
Change in accrued liabilities-capital expenditures			108				(1,430	)
Contributions to Wamsutter			(22	)			—
Contributions to Discovery Producer Services			(437	)			—
Net cash used by investing activities			(8,728	)			(10,216	)
FINANCING ACTIVITIES:
Distributions to unitholders			(35,283	)			(19,491	)
Proceeds from sale of common units			28,992				—
Redemption of common units from general partner			(28,992	)			—
Contributions per omnibus agreement			771				842
Other			76				—
Net cash used by financing activities			(34,436	)			(18,649	)
Increase (decrease) in cash and cash equivalents			(1,642	)			20,951
Cash and cash equivalents at beginning of period			36,197				57,541
Cash and cash equivalents at end of period		$	34,555			$	78,492

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		Limited Partners												Accumulated Other				Total
										General				Comprehensive				Partners’
		Common				Subordinated				Partner				Loss				Capital
		(In thousands)
Balance — January 1, 2008		$	1,473,814			$	109,542			$	(1,419,382	)		$	(2,487	)		$	161,487
Net income			37,359				1,556				4,714				—				43,629
Other comprehensive income (loss):
Net unrealized gains on cash flow hedges			—				—				—				2,459				2,459
Reclassification into earnings of derivative instrument gains			—				—				—				(5	)			(5	)
Total other comprehensive income																			2,454
Total comprehensive income																			46,083
Cash distributions			(26,321	)			(4,025	)			(4,937	)			—				(35,283	)
Conversion of subordinated units into common			107,073				(107,073	)			—				—				—
Contributions pursuant to the omnibus agreement			—				—				771				—				771
Issuance of units to public			28,992				—				—				—				28,992
Repurchase of units from Williams			(28,992	)			—				—				—				(28,992	)
Other			(473	)			—				—				—				(473	)
Balance — March 31, 2008		$	1,591,452			$	—			$	(1,418,834	)		$	(33	)		$	172,585

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

Note 1. Organization and Basis of Presentation

     Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of Wamsutter LLC (Wamsutter) and Discovery Producer Services LLC (Discovery) in which we own interests accounted for as equity investments that are not consolidated in our financial statements. When we refer to Wamsutter or Discovery by name, we are referring exclusively to their businesses and operations.

     We are principally engaged in the business of gathering, transporting, processing and treating natural gas and fractionating and storing natural gas liquids (NGL). Operations of our businesses are located in the United States and are organized into three reporting segments: (1) Gathering and Processing — West, (2) Gathering and Processing — Gulf and (3) NGL Services. Our Gathering and Processing — West segment includes the Four Corners gathering and processing operations and our equity investment in Wamsutter. Our Gathering and Processing — Gulf segment includes the Carbonate Trend gathering pipeline and our equity investment in Discovery. Our NGL Services segment includes the Conway fractionation and storage operations.

     On June 28, 2007, we closed on the acquisition of an additional 20% interest in Discovery from Williams Energy, L.L.C. and Williams Energy Services, LLC, bringing our total ownership of Discovery to 60%. This transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was purchased from an affiliate of The Williams Companies, Inc. (Williams), the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly our consolidated financial statements and notes reflect the combined historical results of our investment in Discovery throughout the periods presented. The effect of recasting our financial statements to account for this common control exchange increased net income $1.3 million for the first quarter of 2007. The acquisition had no impact on earnings per unit as pre-acquisition earnings were allocated to the general partner.

     On December 11, 2007, we acquired certain ownership interests in Wamsutter, consisting of 100% of the Class A limited liability company interests and 20 Class C units representing 50% of the initial Class C ownership interests (collectively the Wamsutter Ownership Interests) Because the Wamsutter Ownership Interests were purchased from an affiliate of Williams, the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes reflect the combined historical results of our investment in Wamsutter throughout the periods presented. The effect of recasting our financial statements to account for this common control exchange increased net income $11.3 million for the first quarter of 2007. This acquisition does not impact earnings per unit as pre-acquisition earnings were allocated to our general partner.

     The accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K, filed February 26, 2008, for the year ended December 31, 2007. The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at March 31, 2008, and results of operations for the three months ended March 31, 2008 and 2007 and cash flows for the three months ended March 31, 2008 and 2007. All intercompany transactions have been eliminated. Certain amounts have been reclassified to conform to the current classifications.

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

Note 2. Recent Accounting Standards

     In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” currently establishes the disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 amends and expands the disclosure requirements of Statement 133 with

enhanced quantitative, qualitative and credit risk disclosures. The Statement requires quantitative disclosure in a tabular format about the fair values of derivative instruments in the statement of financial position, gains and losses on derivative instruments in the statement of financial performance and information about where these items are reported in the financial statements. Also required in the tabular presentation is a separation of hedging and non-hedging activities. Qualitative disclosures include outlining objectives and strategies for using derivative instruments in terms of underlying risk exposures, use of derivatives for risk management and other purposes and accounting designation, and an understanding of the volume and purpose of derivative activity. Credit risk disclosures provide information about credit risk related contingent features included in derivative agreements. SFAS No. 161 also amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to clarify that disclosures about concentrations of credit risk should include derivative instruments. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We plan to apply this Statement beginning in 2009. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We will assess the application of this Statement on our disclosures in our consolidated financial statements.

     In March 2008, the FASB ratified the decisions reached by the Emerging Issues Task Force (EITF) with respect to EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” EITF Issue No. 07-4 states, among other things, that the calculation of earnings per unit should not reflect an allocation of undistributed earnings to the incentive distribution right (IDR) holders beyond amounts distributable to IDR holders under the terms of the partnership agreement. As described in Note 3, under current generally accepted accounting principles, we calculate earnings per unit as if all the earnings for the period had been distributed, which results in an additional allocation of income to the general partner (the IDR holder) in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeds the actual incentive distribution. Following the adoption of the guidance in EITF Issue No. 07-4, we will no longer calculate assumed incentive distributions. The final consensus is effective beginning with the first interim period of the fiscal year beginning after December 15, 2008, and must be retrospectively applied to all periods presented. Early application is prohibited. Retrospective application of this guidance will result in a decrease in the income allocated to the general partner and an increase in the income allocated to limited partners for the amount that any assumed incentive distribution exceeded the actual incentive distribution paid during that period. Certain of our historical periods’ earnings per unit will be revised as a result of this change. Adoption of this new standard only impacts the allocation of earnings for purposes of calculating our earnings per limited partner unit and will have no impact on our results of operations or distributions of available cash to unitholders and our general partner.

Note 3. Allocation of Net Income and Distributions

     The allocation of net income between our general partner and limited partners, as reflected in the Consolidated Statement of Partners’ Capital, is as follows (in thousands):

		Three months ended
		March 31,
		2008				2007
Allocation to general partner:
Net income		$	43,629			$	25,137
Net income applicable to pre-partnership operations allocated to general partner			—				(12,639	)
Reimbursable general and administrative costs charged directly to general partner			398				592
Income subject to 2% allocation of general partner interest			44,027				13,090
General partner’s share of net income			2.0	%			2.0	%
General partner’s allocated share of net income before items directly allocable to general partner interest			881				262
Incentive distributions paid to general partner*			4,231				603
Direct charges to general partner			(398	)			(592	)
Pre-partnership net income allocated to general partner			—				12,639
Net income allocated to general partner		$	4,714			$	12,912
Net income		$	43,629			$	25,137
Net income allocated to general partner			4,714				12,912
Net income allocated to limited partners		$	38,915			$	12,225

     Common and subordinated unitholders have always shared equally, on a per-unit basis, in the net income allocated to limited partners.

     We paid or have authorized payment of the following cash distributions during 2007 and 2008 (in thousands, except for per unit amounts):

																		General Partner
																						Incentive
		Per Unit				Common				Subordinated				Class B								Distribution				Total Cash
Payment Date		Distribution				Units				Units				Units				2%				Rights				Distribution
2/14/2007		$	0.4700			$	12,010			$	3,290			$	3,198			$	390			$	603			$	19,491
5/15/2007		$	0.5000			$	12,777			$	3,500			$	3,403			$	421			$	965			$	21,066
8/14/2007		$	0.5250			$	16,989			$	3,675				—			$	447			$	1,267			$	22,378
11/14/2007		$	0.5500			$	17,799			$	3,850				—			$	487			$	2,211			$	24,347
2/14/2008		$	0.5750			$	26,321			$	4,025				—			$	706			$	4,231			$	35,283
5/15/2008(a)		$	0.6000			$	31,665				—				—			$	758			$	5,498			$	37,921

Note 4. Assets Held for Sale

     Our right of way agreement with the Jicarilla Apache Nation (JAN), which covered certain gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006. We currently operate our gathering assets on the JAN lands pursuant to a special business license granted by the JAN which expires on August 31, 2008, and are negotiating with the JAN to sell them these gathering assets. The special business license requires the execution of a purchase and sale agreement for these gathering assets on or before May 31. It is anticipated that this sale will be completed during the third or fourth quarter of 2008. As a result of the maturation of negotiations during the first quarter of 2008, these assets have been classified as held for sale on the consolidated balance sheet and include property, plant and equipment. Our management believes the expected proceeds from the sale of these assets will substantially exceed their carrying value of $11.3 million. The gathering system assets being sold are part of the Gathering and Processing — West segment.

Note 5. Equity Investments

     We are allocated net income (equity earnings) from Wamsutter based upon the allocation, distribution, and liquidation provisions of its limited liability company agreement applied as though liquidation occurs at book value. In general, the agreement allocates income in a manner that will maintain capital account balances reflective of the amounts each ownership interest would receive if Wamsutter were dissolved and liquidated at carrying value. The income allocation for the quarterly periods during a year reflects the preferential rights of the Class A interest to any distributions made to the Class C interest until the Class A interest has received $70.0 million in distributions for the year. The Class B interest receives no income or loss allocation. As the owner of 100% of the Class A ownership interest, we will receive 100% of Wamsutter’s net income up to $70.0 million. Income in excess of $70.0 million will be shared between the Class A interest and Class C interest, of which we currently own 50%. For annual periods in which Wamsutter’s net income exceeds $70.0 million, this will result in a higher allocation of equity earnings early in the year and a lower allocation of equity earnings later in the year. As such, equity earnings in the first quarter may not be representative of the remaining quarters of the year. Wamsutter’s net income allocations do not affect the amount of available cash it distributes for any quarter.

     The summarized financial position and results of operations for 100% of Wamsutter are presented below (in thousands):

Wamsutter

		March 31,				December 31,
		2008				2007
		(Unaudited)
Current assets		$	35,405			$	27,114
Property, plant and equipment, net			273,563				275,163
Non-current assets			175				191
Current liabilities			(22,906	)			(12,944	)
Non-current liabilities			(2,867	)			(2,812	)
Members’ capital		$	283,370			$	286,712

		Three Months Ended
		March 31,
		2008				2007
		(Unaudited)
Revenues:
Affiliate		$	50,050			$	22,279
Third-party			17,575				17,894
Costs and expenses:
Affiliate			33,214				16,174
Third-party			13,217				12,671
Net income		$	21,194			$	11,328

     The summarized financial position and results of operations for 100% of Discovery are presented below (in thousands):

Discovery

		March 31,				December 31,
		2008				2007
		(Unaudited)
Current assets		$	75,773			$	78,035
Non-current restricted cash and cash equivalents			3,641				6,222
Property, plant and equipment, net			363,889				368,228
Current liabilities			(27,375	)			(33,820	)
Non-current liabilities			(12,450	)			(12,216	)
Members’ capital		$	403,478			$	406,449

		Three Months Ended
		March 31,
		2008				2007
		(Unaudited)
Revenues:
Affiliate		$	78,006			$	44,533
Third-party			9,150				7,948
Costs and expenses:
Affiliate			38,246				23,155
Third-party			26,620				24,120
Interest income			(264	)			(661	)
Gain on sale of operating assets			—				(468	)
Foreign exchange gain			(147	)			(216	)
Net income		$	22,701			$	6,551

Note 6. Long-Term Debt and Credit Facilities

     Long-Term Debt

     Long-term debt at March 31, 2008 and December 31, 2007 is as follows:

		Interest				March 31,				December 31,
		Rate				2008				2007
		(In millions)
Credit agreement term loan, adjustable rate, due 2012			(a	)		$	250			$	250
Senior unsecured notes, fixed rate, due 2017			7.25	%			600				600
Senior unsecured notes, fixed rate, due 2011			7.50	%			150				150
Total Long-term debt						$	1,000			$	1,000

     Credit Facilities

     We have a $450.0 million senior unsecured credit agreement with Citibank, N.A. as administrative agent, comprised initially of a $200.0 million revolving credit facility available for borrowings and letters of credit and a $250.0 million term loan. Under certain conditions, the revolving credit facility may be increased up to an additional $100.0 million. Borrowings under this agreement must be repaid by December 11, 2012. At March 31, 2008, we had a $250.0 million term loan outstanding under the term loan provisions and no amounts outstanding under the revolving credit facility.

     We also have a $20.0 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the credit facility will mature on June 20, 2009. We are required to reduce all borrowings under this facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility. As of March 31, 2008, we had no outstanding borrowings under the working capital credit facility.

Note 7. Partners’ Capital

     On January 9, 2008, we sold an additional 800,000 common units to the underwriters upon the underwriters’ partial exercise of their option to purchase additional common units pursuant to our common unit offering in December 2007 used to finance our acquisition of the Wamsutter Ownership Interests. We used the net proceeds from the partial exercise of the underwriters’ option to redeem 800,000 common units from an affiliate of Williams at a price per common unit of $36.24 ($37.75, net of underwriter discount).

     On January 28, 2008, our general partner’s board of directors confirmed that the financial test contained in our partnership agreement required for conversion of all of our outstanding subordinated units into common units had been satisfied. Accordingly, our 7,000,000 subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis on February 19, 2008.

Note 8. Fair Value Measurements

Adoption of SFAS No.157

     SFAS No. 157, “Fair Value Measurements” (1) establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, (2) provides guidance on the methods used to estimate fair value and (3) expands disclosures about fair value measurements. On January 1, 2008, we adopted SFAS No. 157 for our assets and liabilities, which are measured at fair value on a recurring basis, primarily our energy commodity derivatives. Upon applying SFAS No. 157, we changed our valuation methodology to consider our non-performance risk in estimating the fair value of our liabilities. The initial adoption of SFAS No. 157 had no material impact on our consolidated financial statements. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2 permitting entities to delay application of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, we will apply SFAS No. 157 fair value requirements to

nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. SFAS No. 157 requires two distinct transition approaches; (i) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (ii) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable for all other instruments. Upon adopting SFAS No. 157, we applied a prospective transition as we did not have financial instrument transactions that required a cumulative-effect adjustment to beginning retained earnings.

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

     SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

	•		Level 1 — Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	•		Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured.
	•		Level 3 — Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

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

     At March 31, 2008 all of our derivative assets and liabilities which are valued at fair value are included in Level 3 and include $1.5 million of energy commodity derivative assets and $1.5 million of energy commodity derivative liabilities. These derivatives include commodity based financial swap contracts.

     The determination of fair value also incorporates factors such as including the credit standing of the counterparties involved, our nonperformance risk on our liabilities, the impact of credit enhancements (such as cash deposits and letters of credit) and the time value of money.

     The following table sets forth a reconciliation of changes in the fair value of net derivatives classified as Level 3 in the fair value hierarchy for the period January 1, 2008 through March 31, 2008.

Fair Value Measurements Using Significant Unobservable Inputs
(Level 3)
(In thousands)

		Net Derivative
		Asset (Liability)
Balance as of January 1, 2008		$	(2,487	)
Realized and unrealized gains (losses):			—
Included in net income			—
Included in other comprehensive income			2,459
Purchases, issuances, and settlements			(5	)
Transfers in/(out) of Level 3			—
Balance as of March 31, 2008		$	(33	)
Unrealized gains (losses) included in net income relating to instruments still held at March 31, 2008		$	—

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

Note 9. Commitments and Contingencies

     Environmental Matters-Four Corners. Current federal regulations require that certain unlined liquid containment pits located near named rivers and catchment areas be taken out of use, and current state regulations require all unlined, earthen pits to be either permitted or closed by December 31, 2005. Operating under a New Mexico Oil Conservation Division-approved work plan, we have physically closed all of our pits that were slated for closure under those regulations. We are presently awaiting agency approval of the closures for 40 to 50 of those pits.

     We are also a participant in certain hydrocarbon removal and groundwater monitoring activities associated with certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at seven and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and sustain closure criteria levels and state regulator approval is received, the sites will be properly abandoned. We expect the remaining sites will be closed within four to eight years.

     In April 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued a Notice of Violation (NOV) to Four Corners that alleges various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. The NMED proposed a penalty of approximately $3 million. We are discussing the basis for and the scope of the proposed penalty with the NMED.

     In March 2008, the U.S. Environmental Protection Agency (EPA) proposed a penalty of $370 thousand for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant and for alleged permit violations at our Ute “E” compressor station. We met with the EPA and are exchanging information in order to resolve the issues.

     We have accrued liabilities totaling $1.5 million at March 31, 2008 for these environmental activities. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by governmental authorities, negotiations with the applicable agencies, and other factors.

     We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any material noncompliance under the various applicable environmental laws and regulations.

     Environmental Matters-Conway. We are a participant in certain environmental remediation activities associated with soil and groundwater contamination at our Conway storage facilities. These activities relate to four projects that are in various remediation stages including assessment studies, cleanups and/or remedial operations and monitoring. We continue to coordinate with the Kansas Department of Health and Environment (KDHE) to develop screening, sampling, cleanup and monitoring programs. The costs of such activities will depend upon the program scope ultimately agreed to by the KDHE and are expected to be paid over the next two to nine years.

     In 2004, we purchased an insurance policy that covers up to $5.0 million of remediation costs until an active remediation system is in place or April 30, 2008, whichever is earlier, excluding operation and maintenance costs and ongoing monitoring costs for these projects to the extent such costs exceed a $4.2 million deductible, of which $3.1 million has been incurred to date from the onset of the policy. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25.0 million. We do not expect to submit any claims under this insurance policy prior to its expected expiration date on April 30, 2008. In addition, under an omnibus agreement with Williams entered into at the closing of our IPO, Williams agreed to indemnify us for the $4.2 million deductible not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring. There is a $14.0 million cap on the total amount of indemnity coverage under the omnibus agreement. There is also a three-year time limitation from the August 23, 2005 IPO closing date. The benefit of this indemnification is accounted for as a capital contribution to us by Williams as the costs are reimbursed. At March 31, 2008, we had accrued liabilities totaling $3.2 million for these costs. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by KDHE and other governmental authorities and other factors.

     Will Price. In 2001, we were named, along with other subsidiaries of Williams, as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The defendants have opposed class certification and a hearing on the plaintiffs’ second motion to certify the class was held on April 1, 2005. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.

     Grynberg. In 1998, the Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries, and us. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg has also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the Department of Justice announced that it was declining to intervene in any of the Grynberg cases, including the action filed in federal court in Colorado against us. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remain pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against certain Williams’ subsidiaries, including us, be dismissed. On October 20, 2006, the court dismissed all claims against us. In November 2006, Grynberg filed his notice of appeals with the Tenth Circuit Court of Appeals. The amount of any possible liability cannot be reasonably estimated at this time.

     GE Litigation. General Electric International, Inc. (GEII) worked on turbines at our Ignacio, New Mexico plant. We disagree with GEII on the quality of GEII’s work and the appropriate compensation. GEII asserts that it is entitled to additional extra work charges under the agreement, which we deny are due. In 2006 we filed suit in federal court in Tulsa, Oklahoma against GEII, General Energy Services, Inc., and Qualified Contractors, Inc.; alleged, among other claims, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation; and sought unspecified damages. In 2007, the defendants and GEII filed counterclaims against us that alleged breach of contract and breach of the duty of good faith and fair dealing. Trial has been set for October 20, 2008. We are unable to quantify or estimate the possible liability.

     Mid-America Pipeline Company. On April 28, 2008, Mid-America Pipeline Company, LLC (MAPL) filed suit in the District Court of Harris County, Texas seeking a declaration that NGLs from Wamsutter LLC's Echo Springs Plant must be delivered to MAPL for transportation through the life of the plant. An unfavorable ruling in this matter could result in higher, future transportation costs for Wamsutter LLC. The purported obligation arises under a Connection Agreement between Williams and MAPL, which allows Williams to terminate the Agreement upon proper notice. Williams has given MAPL notice of termination that will be effective May 5, 2008 and therefore denies any continuing obligation under the Connection Agreement.

     Other. We are not currently a party to any other legal proceedings but are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.

     Summary. Litigation, arbitration, regulatory matters and environmental matters are subject to inherent uncertainties. Were an

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

Note 10. 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 industry knowledge, technology and marketing strategies.

						Gathering &
		Gathering &				Processing -				NGL
		Processing - West				Gulf				Services				Total
		(In thousands)
Three Months Ended March 31, 2008:
Segment revenues		$	132,333			$	567			$	17,462			$	150,362
Product cost and shrink replacement			47,446				—				4,652				52,098
Operating and maintenance expense			40,893				524				5,667				47,084
Depreciation, amortization and accretion			10,299				153				774				11,226
Direct general and administrative expense			1,930				—				544				2,474
Other, net			2,554				—				284				2,838
Segment operating income (loss)			29,211				(110	)			5,541				34,642
Equity earnings			21,194				13,621				—				34,815
Segment profit		$	50,405			$	13,511			$	5,541			$	69,457
Reconciliation to the Consolidated Statements of Income:
Segment operating income														$	34,642
General and administrative expenses:
Allocated-affiliate															(7,662	)
Third party-direct															(668	)
Combined operating income														$	26,312
Three Months Ended March 31, 2007:
Segment revenues		$	120,428			$	561			$	12,826			$	133,815
Product cost and shrink replacement			39,675				—				2,520				42,195
Operating and maintenance expense			33,097				550				8,866				42,513
Depreciation, amortization and accretion			12,175				304				699				13,178
Direct general and administrative expense			1,821				—				498				2,319
Other, net			2,384				—				190				2,574
Segment operating income (loss)			31,276				(293	)			53				31,036
Equity earnings			11,328				3,931				—				15,259
Segment profit		$	42,604			$	3,638			$	53			$	46,295
Reconciliation to the Consolidated Statements of Income:
Segment operating income														$	31,036
General and administrative expenses:
Allocated-affiliate															(7,224	)
Third party-direct															(527	)
Combined operating income														$	23,285

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

     Please read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial statements included in Item 1 of Part I of this quarterly report.

Overview

     We are principally engaged in the business of gathering, transporting, processing and treating natural gas and fractionating and storing NGLs. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into three business segments:

	•		Gathering and Processing — West. Our West segment includes Four Corners and ownership interests in Wamsutter, consisting of (i) 100% of the Class A limited liability company membership interests and (ii) 50% of the initial Class C limited liability company membership interests (together, the Wamsutter Ownership Interests). We account for the Wamsutter Ownership Interests as an equity investment.
	•		Gathering and Processing — Gulf. Our Gulf segment includes (1) our 60% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline off the coast of Alabama. We account for our ownership interest in Discovery as an equity investment.
	•		NGL Services. Our NGL Services segment includes three integrated NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas.

Executive Summary

     Our results for the first quarter of 2008 reflect record per-unit commodity margins at Four Corners, which more than offset the negative impacts of severe winter weather, continued downtime related to the November 2007 fire at the Ignacio plant and increased system losses. The severe weather reduced gathered volumes and limited our ability to connect new wells during much of the first quarter. Our two equity method investments, Wamsutter and Discovery, also generated improved results over the prior year. Wamsutter also faced severe winter weather challenges, but distributed $22.7 million in cash distributions during the first full quarter following the acquisition of our ownership interests. Discovery was able to significantly increase its quarterly cash distribution to a record $16.8 million. Based on this combined performance, we continued our record of consecutive unitholder distribution increases since our initial public offering (IPO) with our first-quarter 2008 distribution of $0.60 per unit, which is 20% higher than the first-quarter 2007 distribution.

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, 2008, compared to the three months ended March 31, 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion. All information in the following discussion and analysis of results of operations has been recast to reflect the combined historical results of our investments in Discovery and Wamsutter throughout the periods presented following our acquisition of the additional 20% interest in Discovery and the Wamsutter Ownership Interests in June and December 2007, respectively.

		Three months ended
		March 31,								% Change from
		2008				2007				2007(1)
		(Thousands)
Revenues		$	150,362			$	133,815				+12	%
Costs and expenses:
Product cost and shrink replacement			52,098				42,195				-23	%
Operating and maintenance expense			47,084				42,513				-11	%
Depreciation, amortization and accretion			11,226				13,178				+15	%
General and administrative expense			10,804				10,070				-7	%
Taxes other than income			2,505				2,114				-18	%
Other expense			333				460				+28	%
Total costs and expenses			124,050				110,530				-12	%
Operating income			26,312				23,285				+13	%
Equity earnings — Wamsutter			21,194				11,328				+87	%
Equity earnings — Discovery			13,621				3,931			NM
Interest expense			(17,736	)			(14,390	)			-23	%
Interest income			238				983				-76	%
Net income		$	43,629			$	25,137				+74	%

Three months ended March 31, 2008 vs. three months ended March 31, 2007

     Revenues increased $16.5 million, or 12%, due primarily to higher revenues in our Gathering and Processing — West segment and our NGL Services segment. Revenues in our Gathering and Processing — West segment increased due primarily to higher product sales resulting from significantly higher average NGL sales prices and higher sales of NGLs on behalf of third party producers, partially offset by lower NGL sales volumes and lower gathering and processing volumes. Revenues in our NGL Services segment increased due primarily to higher product sales, fractionation and storage revenues. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

     Product cost and shrink replacement increased $9.9 million, or 23%, due primarily to increases in both our Gathering and Processing — West segment and our NGL Services segment. Product cost and shrink replacement in our Gathering and Processing — West segment increased due primarily to increased purchases of NGLs from third party producers who elected to have us sell their NGLs and higher average natural gas prices, partially offset by lower shrink requirements due to lower processing volumes. Product cost and shrink replacement in our NGL Services segment increased due primarily to the higher sales volumes. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

     Operating and maintenance expense increased $4.6 million, or 11%, due primarily to higher system losses and revaluation of product imbalances in our Gathering and Processing — West segment, partially offset by a favorable change in gains and losses on product imbalances in our NGL Services segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

     The $2.0 million, or 15%, decrease in Depreciation, amortization and accretion reflects $2.0 million of first-quarter 2007 adjustments in our Gathering and Processing — West segment. This fluctuation is discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.

     Operating income increased $3.0 million, or 13%, due primarily to higher per-unit NGL sales margins in our Gathering and Processing — West segment and increased fractionation and storage revenues and lower operating and maintenance costs in our NGL Services segment. These increases were substantially offset by higher operating and maintenance expense and lower fee-based gathering and processing revenue in our Gathering and Processing — West segment.

     Equity earnings from Wamsutter increased $9.9 million, or 87%, due primarily to higher per-unit NGL sales margins on higher NGL sales volumes and is discussed in detail in the “— Results of Operations — Gathering and Processing — West” section. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements, for a discussion of how Wamsutter allocates its net income between its member owners including us.

     Equity earnings from Discovery increased $9.7 million, also due primarily to higher per-unit NGL sales margins on higher NGL sales volumes. This increase is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

     Interest expense increased $3.3 million, or 23%, due to interest on our $250.0 million term loan issued in December 2007 to finance a portion of our acquisition of Wamsutter Ownership Interests.

Results of operations — Gathering and Processing — West

     The Gathering and Processing — West segment includes our Four Corners natural gas gathering, processing and treating assets and our Wamsutter Ownership Interests.

		Three months ended
		March 31,
		2008				2007
		(Thousands)
Revenues		$	132,333			$	120,428
Costs and expenses, including interest:
Product cost and shrink replacement			47,446				39,675
Operating and maintenance expense			40,893				33,097
Depreciation, amortization and accretion			10,299				12,175
General and administrative expense — direct			1,930				1,821
Taxes other than income			2,221				1,924
Other expense, net			333				460
Total costs and expenses, including interest			103,122				89,152
Segment operating income			29,211				31,276
Equity earnings — Wamsutter			21,194				11,328
Segment profit		$	50,405			$	42,604

Four Corners

Three months ended March 31, 2008 vs. three months ended March 31, 2007

     Revenues increased $11.9 million, or 10% percent, due primarily to $17.6 million higher product sales partially offset by $5.6 million lower gathering and processing revenue.

     Product sales revenues increased due primarily to:

	•		$16.6 million related to a 59% increase in average NGL sales prices realized on sales of NGLs which we received under keep-whole and percent-of-liquids processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods;
	•		$7.5 million higher sales of NGLs on behalf of third party producers for whom we purchase their NGLs for a fee under their contracts. Under these arrangements, we purchase the NGLs from the third party producers and sell them to an affiliate. This increase is offset by higher associated product costs of $7.5 million discussed below; and
	•		$1.0 million higher condensate and LNG sales.

     These product sales increases were partially offset by $7.6 million lower revenues related to a 21% decrease in NGL volumes that Four Corners received under keep-whole and percent-of-liquids processing contracts. The decreased NGL volumes were due primarily to lower processing volumes caused by prolonged, severe winter weather during January and February of 2008 and the impact of the fire at the Ignacio gas processing plant in November 2007. The plant was shut down until January 18, 2008.

     Fee-based gathering and processing revenues decreased $5.6 million, or 9%, due primarily to $4.8 million lower revenue from an 8% decrease in gathered and processed volumes and an $0.8 million decrease from 2007 billings of back charges on a customer contract for 2005 and 2006. The decreased gathered and processed volumes were also caused by the weather and fire-related impacts discussed previously.

     Product cost and shrink replacement increased $7.8 million, or 20%, due primarily to:

•

$7.5 million increase from third party producers who elected to have us purchase their NGLs, which was

offset by the corresponding increase in product sales discussed above; and

•

$3.3 million increase from 22% higher average natural gas prices.

     These increases were partially offset by a $2.4 million decrease from 14% lower volumetric shrink requirements associated with the decreased NGL volumes received under Four Corners’ keep-whole processing contracts discussed above.

     Operating and maintenance expense increased $7.8 million, or 24%, due primarily to $7.1 million higher non-shrink natural gas purchases caused primarily by $5.0 million higher system losses.  During the first quarter of 2008 our volumetric loss, as a percentage of total volume received, was higher than in 2007.  While our system losses are generally an unpredictable component of our operating costs, they can be higher during periods of prolonged, severe winter weather, such as those we experienced during January and February of 2008.  Additionally, operational inefficiencies caused by the fire at the Ignacio plant impacted our system losses.  In 2008 we also had $2.5 million of higher expense related to the revaluation of product imbalances with our producer customers and gathering fuel expense.  Product imbalance revaluations fluctuate with changes in the underlying price of natural gas and with changes in imbalance levels. Gathering fuel expense was unfavorably impacted by the weather and operational inefficiencies caused by the fire at the Ignacio gas processing plant previously mentioned.

     The $1.9 million, or 15%, decrease in depreciation, amortization and accretion expense is due primarily to the $2.0 million of first-quarter 2007 right-of-way amortization and asset retirement obligations corrections.

     Segment operating income decreased $2.1 million, or 7%, due primarily to $7.8 million higher operating and maintenance expense and $5.6 million lower fee-based gathering and processing revenue. These were substantially offset by $9.8 million higher product sales margins resulting primarily from sharply increased per-unit margins on lower NGL sales volumes and $1.9 million lower depreciation, amortization and accretion expense.

Outlook

	•		We anticipated that growth capital investments we completed in 2007 to support ConocoPhillips’ and other producer customers’ drilling activity, expansion opportunities and production enhancement activities would be sufficient to offset the historical decline and slightly increase 2008 average gathering and processing volumes above 2007 levels. However, first-quarter 2008 volumes were significantly impacted by severe weather conditions that inhibited both our and our customers’ ability to access facilities and maintain production. We currently expect average gathering and processing volumes in the second through fourth quarters of 2008 will be slightly higher as compared with the same quarters of 2007 although full-year 2008 gathering and processing volumes will be slightly lower as compared to 2007.
	•		We have realized above average net liquids margins at our gas processing plants in recent years due primarily to increasing prices for NGLs. Based on first-quarter 2008 prices for NGLs and natural gas combined with the hedging program described below, per-unit margins in 2008 could meet or exceed record levels realized in 2007. However, the prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are impossible to control and, in particular, NGL pricing is typically impacted negatively by recessionary economic conditions.
	•		Throughout the remainder of 2008, we may experience periodic restrictions in the volume of NGLs we can deliver to third-party pipelines. These restrictions happen for a variety of reasons including a lack of capacity. If alternative delivery options are unavailable, such restrictions could impact our ability to recover and sell NGLs, which might otherwise have been available from our Four Corners processing plants.
	•		We currently have financial swap contracts to hedge 5.4 million gallons of our monthly forecasted NGL sales and fixed price natural gas purchase contracts to hedge the price of our natural gas shrink replacement associated with these NGL sales for April through December 2008. The 5.4 million gallons per month represents approximately 40% of our 2007 NGL sales for these same months. On an aggregate basis, as of March 31, 2008, there remains a hedged margin of $25.0 million or an average of $0.51 per gallon on these NGL sales in 2008. The primary purpose of these hedges is to mitigate risk associated with ethane sales derived from keep-

			whole processing arrangements. Of the 5.4 million gallons, 4.2 million are ethane sales. The average hedged margin on these forecasted keep-whole NGL sales exceeds the average margin realized on keep-whole NGL sales for 2007.
	•		We anticipate that operating costs, excluding compression, gathering fuel and system gains and losses, will remain stable as compared to 2007. Compression cost increases are dependent upon the extent and amount of additional compression needed to meet the needs of our customers and the cost at which compression can be purchased, leased and operated. System gains and losses are an unpredictable component of our operating costs.
	•		Our right of way agreement with the Jicarilla Apache Nation (JAN) which covered certain gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006. We currently operate our gathering assets on the JAN lands pursuant to a special business license granted by the JAN which expires August 31, 2008, and are negotiating with the JAN to sell them these gathering assets. The current special business license requires the execution of a purchase and sale agreement for these gathering assets on or before May 31. It is anticipated that this sale will be completed during the third or fourth quarter of 2008. As a result of the maturation of negotiations during the first quarter of 2008, these assets have been classified as held for sale on the consolidated balance sheet and include property, plant and equipment. Current expectations are that the final terms of the sale will allow us to maintain partial revenues associated with gathering and processing services for gas produced from the JAN lands and continued operations of the gathering assets on the JAN lands through at least 2009. We believe the expected proceeds from the sale of these assets will substantially exceed their carrying value. Based on current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the JAN lands represents approximately $20 to $30 million of Four Corners’ annual gathering and processing revenue less related product costs.

Wamsutter

     Wamsutter is accounted for using the equity method of accounting. As such, our interest in Wamsutter’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Wamsutter. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements for a discussion of how Wamsutter allocates its net income between its member owners including us.

		Three months ended
		March 31,
		2008				2007
		(Thousands)
Revenues		$	67,625			$	40,173
Costs and expenses, including interest:
Product cost and shrink replacement			26,030				14,298
Operating and maintenance expense			11,637				7,047
Depreciation and accretion			5,228				4,258
General and administrative expense			3,219				2,820
Taxes other than income			484				422
Other income, net			(167	)			—
Total costs and expenses			46,431				28,845
Net income		$	21,194			$	11,328
Williams Partners’ interest – equity earnings per our Consolidated Statements of Income		$	21,194			$	11,328

Three months ended March 31, 2008 vs. three months ended March 31, 2007

     Revenues increased $27.5 million, or 68%, due primarily to $28.7 million higher product sales slightly offset by $0.9 million lower gathering and processing revenue.

     Product sales revenues increased $28.7 million, or 138%, due primarily to:

•

$16.2 million related to a 54% increase in average NGL sales prices realized on sales of NGLs which Wamsutter received under keep-whole processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods.

•

$9.4 million related to a 45% increase in NGL volumes that Wamsutter received under keep-whole processing contracts. Severe winter weather conditions in 2008 lowered volumes received under some of Wamsutter’s larger fee-based processing agreements. This allowed Wamsutter to process greater volumes under keep-whole processing arrangements.

•

$3.1 million related to favorable adjustments to the margin sharing provisions of one of Wamsutter’s significant contracts.

     These product sales increases were partially offset by $1.0 million lower sales of NGLs on behalf of third party producers who sell their NGLs to Wamsutter under their contracts. Under these arrangements, Wamsutter purchases NGLs from the third party producers and sells them to an affiliate. This decrease is offset by lower associated product costs of $1.0 million discussed below.

     Gathering and processing revenues decreased $0.9 million, or 5%, due primarily to $2.3 million related to a 15% decrease in the average volumes, partially offset by $1.5 million related to an 11% increase in the average fee received for these services. The decrease in average volumes was due primarily to production problems caused by severe winter weather conditions. The average fee increased as a result of fixed annual percentage or inflation-sensitive contractual escalation clauses and incremental fee revenues from completed gathering system expansion projects.

     Product cost and shrink replacement increased $11.7 million, or 82%, due primarily to:

•

$6.8 million increase from 36% higher average natural gas prices; and

•

$5.9 million increase from 45% higher volumetric shrink requirements due to higher volumes processed under Wamsutter’s keep-whole processing contracts;

     These increases were partially offset by $1.0 million lower product cost related to lower sales of NGLs on behalf of third party producers who sell their NGLs to Wamsutter under their contracts as discussed above.

     Operating and maintenance expense increased $4.6 million, or 65%, due primarily to $3.7 million higher gathering fuel costs caused by higher average natural gas prices and weather related operational problems.

     Depreciation and accretion expense increased $1.0 million, or 23%, due primarily to new assets placed into service.

     Net income increased $9.9 million, or 87%, due primarily to $14.0 million higher product sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes and $3.1 million higher product sales resulting from charges recovered on one of Wamsutter’s contracts. Partially offsetting these increases were $4.6 million higher operating and maintenance expenses, $1.2 million lower fee-based gathering and processing revenues and $1.0 million higher depreciation and accretion expense.

Outlook

•

Compared to 2007, Wamsutter anticipated that sustained drilling activity, expansion opportunities and production enhancement activities by producers would have been sufficient to offset the historical production decline and to increase Wamsutter’s average gathering volumes. However, first-quarter 2008 volumes were significantly impacted by severe weather conditions that inhibited both Wamsutter’s and their customers’ ability to access facilities and maintain production, resulting in lower than expected volumes. We currently expect average gathering and processing volumes in the second through fourth quarters of 2008 will be slightly higher as compared with these same quarters of 2007 and that full-year 2008 gathering and processing volumes will be flat as compared to 2007.

•

Total gas available for processing has increased in recent years; however, due to limited plant capacity, not all of this increased volume could be processed resulting in gas being bypassed around the Echo Springs plant. Under normal operating conditions, this results in lower NGL volumes received under keep-whole processing contracts.  In 2008, we anticipate that an agreement providing us with third party propanes, butanes and natural gasoline processing for Wamsutter bypassed gas at Colorado Interstate Gas Company’s (CIG) Rawlins natural gas processing plant will increase the processing capacity available to Wamsutter by 80 million cubic feet per day (MMcf/d) or approximately 20%.  We anticipate that this third party processing will result in an increase in NGL volumes sold by Wamsutter.   Due to operational problems caused by severe winter weather in the first quarter of 2008, processing volumes have not been sufficient to fully utilize Echo Springs’ plant capacity; therefore, minimal volumes have been processed by CIG.  We do anticipate the volumes to increase for the remainder of the year allowing us to realize increased NGL volumes through the third-party processing agreement.

•

In 2007, Wamsutter realized record high net liquids margins at its Echo Springs plant. The 2007 net liquids margins were significantly impacted by very low local shrink replacement natural gas costs as compared with other natural gas markets.  Natural gas prices have returned to more comparable levels in 2008 and we

do not expect them to return to 2007 levels.  Accordingly, we expect per-unit margins in 2008 will remain higher in relation to five-year historical averages, but below the record levels realized in 2007.

•

Throughout the remainder of 2008, we may experience periodic restrictions in the volume of NGLs we can deliver to third-party pipelines. These restrictions happen for a variety of reasons including a lack of capacity. If alternative delivery options are unavailable, such restrictions could impact our ability to recover and sell NGLs, which might otherwise have been available from our Echo Springs processing plant.

•

Operating costs, excluding system gains and losses and new third-party processing fees at the CIG’s Rawlins plant, are expected to approximate those in 2007.  System gains and losses are an unpredictable component of our operating costs.  Additionally, the new third-party processing arrangement at CIG’s Rawlins plant mentioned above requires that we pay a fee per million British thermal units (MMbtu) processed that will add approximately $4.0 million in operating costs.

Results of Operations – Gathering and Processing — Gulf

     The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership interest in Discovery.

		Three months ended
		March 31,
		2008				2007
		(Thousands)
Segment revenues		$	567			$	561
Costs and expenses:
Operating and maintenance expense			524				550
Depreciation			153				304
Total costs and expenses			677				854
Segment operating loss			(110	)			(293	)
Equity earnings — Discovery			13,621				3,931
Segment profit		$	13,511			$	3,638

Carbonate Trend

     Segment operating loss decreased $0.2 million, or 62%, due primarily to lower depreciation following the property impairment recognized in the fourth quarter of 2007.

Discovery

     Discovery is accounted for using the equity method of accounting. As such, our interest in Discovery’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Discovery.

		Three months ended
		March 31,
		2008				2007
		(Thousands)
Revenues		$	87,156			$	52,481
Costs and expenses, including interest:
Product cost and shrink replacement			52,240				33,518
Operating and maintenance expense			7,008				6,415
Depreciation and accretion			6,983				6,483
General and administrative expense			1,750				544
Interest income			(264	)			(661	)
Other income, net			(3,262	)			(369	)
Total costs and expenses, including interest			64,455				45,930
Net income		$	22,701			$	6,551
Williams Partners’ 60 percent interest – Equity earnings per our Consolidated Statements of Income		$	13,621			$	3,931

Three months ended March 31, 2008 vs. three months ended March 31, 2007

     Revenues increased $34.7 million, or 66%, due primarily to $33.6 million higher product sales resulting from:

	•		$20.3 million from 105% higher NGL volumes due primarily to an increase in volumes processed under keep-whole processing arrangements;
	•		$11.7 million related to a 29% increase in average NGL sales prices realized on sales of NGLs which Discovery received under certain processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods; and
	•		$3.7 million higher sales of NGLs on behalf of third party producers for whom Discovery purchases their NGLs for a fee under their contracts. This increase is offset by higher associated product costs of $3.7 million discussed below.

     These increases were partially offset by $2.0 million lower sales of excess fuel and shrink replacement gas. The lower sales on excess fuel and shrink replacement gas is offset by lower excess shrinkage cost and is described below.

     Product cost and shrink replacement increased $18.7 million, or 56%, due primarily to:

	•		$12.3 million higher volumetric natural gas requirements from increased keep-whole processing activity;
	•		$3.7 million higher product purchase cost for the processing customers who elected to have Discovery purchase their NGLs;
	•		$2.6 million increase in payments for gas processing rights from third-party processors; and

•

$2.4 million increase from higher average natural gas prices.

     These increases were partially offset by a $2.0 million decrease in cost associated with the sales of excess fuel and shrink replacement gas mentioned above.

     General and administrative expense increased $1.2 million due primarily to a proposed increase in Discovery’s management fee charged by Williams. The management fee is in the process of being re-negotiated effective January 1, 2008 as discussed below.

     Other income, net increased $2.9 million due primarily to $3.5 million from the reversal of amounts previously reserved from 1998 through 2003 for system fuel and lost and unaccounted for gas in connection with the recently approved FERC settlement filing.

     Net income increased $16.2 million due primarily to $14.9 million higher product sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes and $2.9 million for higher other income, net, partially offset by $1.2 million higher general and administrative expense.

Outlook

     Discovery

     Throughput volumes on Discovery’s pipeline system are an important component of maximizing its profitability. Pipeline throughput volumes from existing wells connected to its pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas plant and fractionator, Discovery must continually obtain new supplies of natural gas.

	•		With the current oil and natural gas price environment, drilling activity across the shelf and the deepwater of the Gulf of Mexico has been robust. However, the limited availability of specialized rigs necessary to drill in the deepwater areas, such as those in and around Discovery’s gathering areas, limits the ability of producers to bring identified reserves to market quickly. This will prolong the timeframe over which these reserves will be developed. We expect Discovery to be successful in competing for a portion of these new volumes.
	•		Discovery’s Tahiti pipeline lateral was installed on the sea bed in February 2007. Chevron has recently moved the production facility to location indicating their ongoing progress toward first production. Chevron announced that it expects first production by the third quarter of 2009. Discovery’s revenues from the Tahiti project are dependent on receiving throughput from Chevron. Therefore, delays Chevron experiences in bringing their production online impact the initial timing of revenues for Discovery.
	•		The Texas Eastern Transmission Company (TETCO) agreement was recently extended through May 2008 after which time we expect no further volumes under this agreement. Current flowing volumes are approximately 170 billion British thermal units per day (BBtu/d).
	•		Gross processing margins have been at record high levels due to commodity prices for NGLs and natural gas, Discovery’s mix of processing contract types and its operation and optimization activities. We expect that 2008 gross processing margins will remain favorable to historical averages. However, the prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are impossible to control and, in particular, NGL pricing is typically impacted negatively by recessionary economic conditions.

•

Discovery’s Larose gas processing plant has been operating at near capacity. We expect that additional processing volumes from the Tennessee Gas Pipeline (TGP) system in 2008 will replace some of the processing volumes previously coming from the TETCO system; and therefore, the Larose plant will continue to remain at near capacity throughout 2008.

•

Discovery receives a significant amount of the processing volumes from TGP via a very large third-party owned natural gas platform. The platform was recently shut down after a leak was discovered on a

			pipeline near the platform. Processing volumes received from TGP will be impacted during the ongoing shut down while repairs are being made and could reduce Discovery’s 2008 operating profit by approximately $4.0 million to $5.0 million.
	•		In February 2008, Discovery executed agreements with LLOG Exploration Company to provide production handling, transportation, processing and fractionation services for their MC 705 and 707 production. At this time, Discovery began receiving minimum payments of approximately $0.2 million per month under this agreement and expects an increase when production begins in early summer 2008.
	•		We expect Discovery’s 2008 results will be favorably impacted by approximately $3.0 million due to its recently approved FERC rate filing pertaining to the regulated portion of its business.
	•		Discovery has recently received an additional dedication in four blocks for an estimated 60 trillion British thermal units of new natural gas reserves with ATP Oil and Gas Corporation (ATP) around its Gomez facility. Discovery also recently contracted three blocks in the Mirage, Morgas and Telemark areas with capital requirements to connect to Discovery’s facilities to be funded entirely by ATP.
	•		Discovery is currently renegotiating the management fee it is charged by Williams for providing senior management guidance, legal, marketing, financial analysis, information technology, accounting and other management services to Discovery.  Discovery expects an increase of approximately $1.0 million per quarter and the increase has been recognized as part of Discovery’s first-quarter results.

Results of Operations – NGL Services

     The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our undivided 50 percent interest in the Conway fractionator.

		Three months ended
		March 31,
		2008				2007
		(Thousands)
Segment revenues		$	17,462			$	12,826
Costs and expenses:
Product cost			4,652				2,520
Operating and maintenance expense			5,667				8,866
Depreciation and accretion			774				699
General and administrative expense — direct			544				498
Other expense, net			284				190
Total costs and expenses			11,921				12,773
Segment profit		$	5,541			$	53

Three months ended March 31, 2008 vs. three months ended March 31, 2007

     Segment revenues increased $4.6 million, or 36%, due primarily to higher product sales, fractionation and storage revenues. The significant components of the revenue fluctuations are addressed more fully below.

•

Product sales increased $1.9 million due to higher sales volumes of ethane and normal butane. The increase in sales volumes was more than offset by the related increase in product cost discussed below.

•

Fractionation revenues increased $1.4 million due primarily to the expiration of a fractionation contract with a cap on the per-unit fee, which limited our ability to pass through increases in fractionation fuel expense to this customer.

•

Storage revenues increased $0.9 million due primarily to higher average storage revenues from additional storage leases.

     Product cost increased $2.1 million, or 85%, due to the higher product sales volumes discussed above. This resulted in a net margin loss of $0.2 million.

     Operating and maintenance expense decreased $3.2 million, or 36%, due primarily to a $1.4 million first- quarter 2007 product imbalance valuation adjustment and a $1.4 million improvement in gains and losses on storage and fractionation product imbalances.

     Segment profit increased $5.5 million due primarily to higher fractionation and storage revenues and lower operating and maintenance costs.

Outlook

•

We expect 2008 storage revenues will be consistent with 2007 due to continued strong demand for propane and butane storage as well as higher priced specialty storage services.

•

We continue to perform a large number of storage cavern workovers and wellhead modifications to comply with KDHE regulatory requirements. We expect outside service costs to continue at current levels throughout 2008 to ensure that we meet the regulatory compliance requirements.