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, 2007

OR

o		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)

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

NO CHANGE

     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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o       Accelerated filer þ       Non-accelerated filer o

     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 25,553,306 common units, 6,805,492 Class B units and 7,000,000 subordinated units outstanding as of May 2, 2007.

 

 

WILLIAMS PARTNERS L.P.
INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statements of Income — Three Months Ended March 31, 2007 and 2006			3
Consolidated Balance Sheets — March 31, 2007 and December 31, 2006			4
Consolidated Statements of Cash Flows — Three Months Ended March 31, 2007 and 2006			5
Consolidated Statement of Partners’ Capital from January 1, 2007 to March 31, 2007			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
Item 3. Quantitative and Qualitative Disclosures About Market Risk			27
Item 4. Controls and Procedures			28
Part II. Other Information
Item 1. Legal Proceedings			28
Item 1A. Risk Factors			28
Item 6. Exhibits			29
Rule 13a-14(a)/15d-14(a) Certification of CEO
Rule 13a-14(a)/15d-14(a) Certification of CFO
Section 1350 Certifications of CEO and CFO

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 quarterly 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.

•

Our processing, fractionation and storage businesses could be affected by any decrease in the price of natural gas liquids or a change in the price of natural gas liquids relative to the price of natural gas.

•

Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.

•

We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and natural gas liquids. 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 natural gas liquids or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

•

Our future financial and operating flexibility may be adversely affected by restrictions in our indentures and by our leverage.

•

Williams’ revolving credit facility and Williams’ public indentures 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 general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to 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.

•

Unitholders may be required to pay taxes on their share of our income even if unitholders do not receive any cash distributions from us.

•

Our operations are subject to operational hazards and unforeseen interruptions for which we may or may not be adequately insured.

     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 IA “Risk Factors” in our Form 10-K for the year ended December 31, 2006.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

WILLIAMS PARTNERS L.P.

		Three Months Ended
		March 31,
		2007				2006*
Revenues:
Product sales:
Affiliate		$	56,552			$	58,396
Third-party			6,313				2,792
Gathering and processing:
Affiliate			9,491				9,933
Third-party			51,103				51,376
Storage			6,410				5,105
Fractionation			1,917				3,953
Other			2,029				1,180
Total revenues			133,815				132,735
Costs and expenses:
Product cost and shrink replacement:
Affiliate			21,725				21,380
Third-party			20,470				22,620
Operating and maintenance expense (excluding depreciation):
Affiliate			14,328				15,686
Third-party			28,185				21,100
Depreciation, amortization and accretion			13,178				10,714
General and administrative expense:
Affiliate			9,406				7,281
Third-party			664				1,305
Taxes other than income			2,114				2,283
Other (income) expense — net			460				(3,643	)
Total costs and expenses			110,530				98,726
Operating income			23,285				34,009
Equity earnings-Discovery Producer Services			2,620				3,781
Interest expense:
Affiliate			(15	)			(15	)
Third-party			(14,375	)			(221	)
Interest income			983				70
Net income		$	12,498			$	37,624
Allocation of net income for calculation of earnings per unit:
Net income			12,498				37,624
Net income applicable to pre-partnership operations allocated to general partner			—				(33,415	)
Net income applicable to partnership operations			12,498				4,209
Allocation of net income (loss) to general partner			273				(689	)
Allocation of net income to limited partners		$	12,225			$	4,898
Basic and diluted net income per limited partner unit:
Common units		$	0.31			$	0.35
Class B units		$	0.31				N/A
Subordinated units		$	0.31			$	0.35
Weighted average number of units outstanding:
Common units			25,553,306				7,006,146
Class B units			6,805,492				N/A
Subordinated units			7,000,000				7,000,000

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		March 31,				December 31,
		2007				2006
		(Unaudited)
		(Thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	78,492			$	57,541
Accounts receivable:
Trade			18,472				18,320
Affiliate			6,205				12,420
Other			3,814				3,991
Gas purchase contract — affiliate			3,565				4,754
Prepaid expense			2,499				3,765
Other current assets			2,869				2,534
Total current assets			115,916				103,325
Investment in Discovery Producer Services			146,514				147,493
Property, plant and equipment, net			648,692				647,578
Other			32,800				34,752
Total assets		$	943,922			$	933,148
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable — trade		$	23,205			$	19,827
Product imbalance			468				651
Deferred revenue			370				3,382
Accrued interest			16,483				2,796
Other accrued liabilities			13,721				13,377
Total current liabilities			54,247				40,033
Long-term debt			750,000				750,000
Environmental remediation liabilities			3,964				3,964
Other noncurrent liabilities			6,440				3,749
Commitments and contingent liabilities (Note 7)
Partners’ capital			129,271				135,402
Total liabilities and partners’ capital		$	943,922			$	933,148

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		Three Months Ended
		March 31,
		2007				2006*
		(Thousands)
OPERATING ACTIVITIES:
Net income		$	12,498			$	37,624
Adjustments to reconcile to cash provided by operations:
Depreciation, amortization and accretion			13,178				10,714
Gain on sale of property, plant and equipment			—				(3,319	)
Amortization of gas purchase contract — affiliate			1,188				1,353
Distributions in excess of equity earnings of Discovery Producer Services			980				619
Cash provided (used) by changes in assets and liabilities:
Accounts receivable			6,241				481
Prepaid expense			1,188				(833	)
Other current assets			(335	)			—
Accounts payable			3,378				(10,753	)
Product imbalance			(183	)			(1,912	)
Accrued liabilities			15,460				389
Deferred revenue			(3,012	)			(3,330	)
Other, including changes in non-current liabilities			215				826
Net cash provided by operating activities			50,796				31,859
INVESTING ACTIVITIES:
Capital expenditures			(9,766	)			(9,615	)
Change in accrued liabilities-capital expenditures			(1,430	)			—
Proceeds from sales of property, plant and equipment			—				7,200
Net cash used by investing activities			(11,196	)			(2,415	)
FINANCING ACTIVITIES:
Distributions to unitholders			(19,491	)			(5,002	)
Distributions to The Williams Companies, Inc.			—				(28,214	)
Contributions per omnibus agreement			842				1,248
Net cash used by financing activities			(18,649	)			(31,968	)
Increase (decrease) in cash and cash equivalents			20,951				(2,524	)
Cash and cash equivalents at beginning of period			57,541				6,839
Cash and cash equivalents at end of period		$	78,492			$	4,315

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		Limited Partners												General				Total Partners’
		Common				Class B				Subordinated				Partner				Capital
		(Thousands)
Balance — January 1, 2007		$	733,878			$	241,923			$	108,862			$	(949,261	)		$	135,402
Net income			7,937				2,114				2,174				273				12,498
Cash distributions			(12,010	)			(3,198	)			(3,290	)			(993	)			(19,491	)
Contributions pursuant to the omnibus agreement			—				—				—				842				842
Other			20				—				—				—				20
Balance — March 31, 2007		$	729,825			$	240,839			$	107,746			$	(949,139	)		$	129,271

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, including the operations of Discovery Producer Services LLC (“Discovery”) in which we own a 40% interest. When we refer to Discovery by name, we are referring exclusively to its businesses and operations.

     We are a Delaware limited partnership that was formed in February 2005, to acquire and own (1) a 40% interest in Discovery; (2) the Carbonate Trend gathering pipeline off the coast of Alabama; (3) three integrated natural gas liquids (“NGL”) product storage facilities near Conway, Kansas; and (4) a 50% undivided ownership interest in a fractionator near Conway, Kansas. Our initial public offering (the “IPO”) closed in August 2005. Williams Partners GP LLC, a Delaware limited liability company, was also formed in February 2005 to serve as our general partner. In addition, we formed Williams Partners Operating LLC (“OLLC”), an operating limited liability company (wholly owned by us), through which all our activities are conducted.

     During 2006, we acquired Williams Four Corners LLC (“Four Corners”) pursuant to two agreements with Williams Energy Services, LLC (“WES”), Williams Field Services Group LLC (“WFSG”), Williams Field Services Company, LLC (“WFSC”) and OLLC. Because Four Corners was an affiliate of Williams at the time of the acquisition, the transactions were accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities of Four Corners were combined with Williams Partners L.P. at their historical amounts. Accordingly, the comparative March 31, 2006 financial statements and notes have been restated to reflect the combined results, increasing net income by $33.4 million. The restatement does not impact historical 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 28, 2007, for the year ended December 31, 2006. 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, 2007, and results of operations and cash flows for the three months ended March 31, 2007 and 2006. All intercompany transactions have been eliminated.

     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 February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 establishes a fair value option permitting entities to elect the option to measure eligible financial instruments and certain other items at fair value on specified election dates. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, with a few exceptions, is irrevocable and is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007 and should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted for early adoption. We will not adopt SFAS No. 159 prior to January 1, 2008. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. We continue to assess whether to apply the provisions of SFAS No. 159 to eligible financial instruments in place on the adoption date and the related impact on our Consolidated Financial Statements.

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, for the three months ended March 31, 2007 and 2006 is as follows (in thousands):

		Three months ended
		March 31,
		2007				2006
Allocation to general partner:
Net income		$	12,498			$	37,624
Net income applicable to pre-partnership operations allocated to general partner			—				(33,415	)
Charges direct to general partner:
Reimbursable general and administrative costs			592				789
Income subject to 2% allocation of general partner interest			13,090				4,998
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			262				100
Incentive distributions paid to general partner*			603				—
Direct charges to general partner			(592	)			(789	)
Pre-partnership net income allocated to general partner			—				33,415
Net income allocated to general partner		$	273			$	32,726
Net income		$	12,498			$	37,624
Net income allocated to general partner			273				32,726
Net income allocated to limited partners		$	12,225			$	4,898

     Common and subordinated unitholders share equally, on a per-unit basis, in the net income allocated to limited partners for the three months ended March 31, 2007 and 2006. Class B unitholders share equally, on a per-unit basis, with common and subordinated unitholders in the net income allocated to limited partners for the three months ended March 31, 2007.

     We paid or have authorized payment of the following cash distributions during 2006 and 2007 (in thousands, except for per unit amounts):

		Per Unit				Common				Subordinated				Class B				General				Total Cash
Payment Date		Distribution				Units				Units				Units				Partner				Distribution
2/14/2006		$	0.3500			$	2,452			$	2,450							$	100			$	5,002
5/15/2006		$	0.3800			$	2,662			$	2,660							$	109			$	5,431
8/14/2006 (a)		$	0.4250			$	6,204			$	2,975							$	263			$	9,442
11/14/2006 (b)		$	0.4500			$	6,569			$	3,150							$	401			$	10,120
2/14/2007 (c)		$	0.4700			$	12,010			$	3,290			$	3,198			$	993			$	19,491
5/15/2007 (d)		$	0.5000			$	12,777			$	3,500			$	3,403			$	1,386			$	21,066

Note 4. Out of Period Adjustments

     Out of period adjustments to correct the carrying value of our assets and liabilites reflected in Costs and operating expenses in our Consolidated Statements of Income are summarized in the following table (in thousands):

		Three Months Ended
		March 31,
		2007				2006
		(Unaudited)
Gathering and Processing —West:
Adjust carrying value of prepaid right-of-way asset recorded from 2001 through 2006		$	1,243			$	—
Adjust 2006 incentive compensation accrual			(899	)			—
Adjust the 2005 asset retirement obligation recognition			785				—
Adjust the accounts payable balance recorded in 2005			—				(2,000	)
March 31, 2006 accounts payable adjustment corrected in the second quarter of 2006			—				(1,300	)
NGL Services:
Adjust carrying value of product imbalance liability recorded in prior periods			1,437				—

Note 5. Equity Investments

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

Discovery Producer Services LLC

		March 31,				December 31,
		2007				2006
		(Unaudited)
Current assets		$	67,628			$	73,841
Non-current restricted cash and cash equivalents			19,865				28,773
Property, plant and equipment, net			375,970				355,304
Current liabilities			(46,072	)			(40,559	)
Non-current liabilities			(3,810	)			(3,728	)
Members’ capital		$	413,581			$	413,631

		Three Months Ended
		March 31,
		2007				2006
		(Unaudited)
Revenues:
Affiliate		$	44,533			$	52,786
Third-party			7,948				9,334
Costs and expenses:
Affiliate			23,155				33,671
Third-party			24,120				20,050
Interest income			(661	)			(626	)
Gain on sale of operating assets			(468	)			—
Foreign exchange gain			(216	)			(427	)
Net income		$	6,551			$	9,452

Note 6. Credit Facilities and Long-Term Debt

     Credit Facilities

     We may borrow up to $75.0 million under Williams’ $1.5 billion revolving credit facility, which is available for borrowings and letters of credit. Borrowings under this facility mature on May 1, 2009. Our $75.0 million borrowing limit under Williams’ revolving credit facility is available for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. At March 31, 2007, letters of credit totaling $28.0 million had been issued on behalf of Williams by the participating institutions under this facility and no revolving credit loans were outstanding.

     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 amended and restated facility will mature on June 29, 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, 2007, we had no outstanding borrowings under the working capital credit facility.

     Long-Term Debt

     In connection with the issuances of our $600.0 million of 7.25% senior unsecured notes on December 13, 2006 and $150.0 million of 7.5% senior unsecured notes on June 20, 2006, sold in private debt placements to qualified institutional buyers in accordance with Rule 144A under the Securities Act and outside the United States in accordance with Regulation S under the Securities Act, we entered into registration rights agreements with the initial purchasers of the senior unsecured notes. In those agreements, we agreed to conduct a registered exchange offer of notes in exchange for the senior unsecured notes, or cause to become effective a shelf registration statement providing for resale of the senior unsecured notes. We launched exchange offers for both series on April 10, 2007. If we fail to consummate the exchange offers by May 30, 2007, we will be required to pay liquidated damages in the form of additional cash interest to the holders of the senior unsecured notes. Upon the occurrence of such a failure to comply, the interest rate on the senior unsecured notes shall be increased by 0.25% per annum during the 90-day period immediately following the occurrence of such failure to comply and shall increase by 0.25% per annum 90 days thereafter until all defaults have been cured, but in no event shall such aggregate additional interest exceed 0.50% per annum.

Note 7. 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.

     We have accrued liabilities totaling $0.7 million at March 31, 2007 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 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.

     On April 11, 2007, the New Mexico Environment Department’s Air Quality Bureau (“NMED”) issued a Notice of Violation 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. We are investigating the matter and will respond to the NMED.

     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 $0.8 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. 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 groundwater monitoring required under the cavern and brine pond operation permits. There is a $14.0 million cap on the total amount of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under the environmental insurance policy. There is also a three-year time limitation from the August 23, 2005 IPO closing date. The benefit of this indemnification will be accounted for as a capital contribution to us by Williams as the costs are reimbursed. We estimate that the approximate cost of this project management and soil and groundwater monitoring associated with the four remediation projects at the Conway storage facilities and for which we will not be indemnified will be approximately $0.2 million to $0.4 million per year following the completion of the remediation work. At March 31, 2007, we had accrued liabilities totaling $5.8 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.

     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.

     Vendor Dispute. We are parties to an agreement with a service provider for work on turbines at our Ignacio, New Mexico plant. A dispute has arisen between us as to the quality of the service provider’s work and the appropriate compensation. The service provider claims it is entitled to additional extra work charges under the agreement, which we deny are due.

     Outstanding Registration Rights Agreement. On December 13, 2006, we issued approximately $350 million of common and Class B units in a private equity offering. In connection with these issuances, we entered into a registration rights agreement with the initial purchasers whereby we agreed to file a shelf registration statement providing for the resale of the units. Additionally, the registration rights agreement requires that we also file a shelf registration that provides for the sale of common units that may be converted from Class B units. If the shelf is unavailable for a period that exceeds an aggregate of 30 days in any 90-day period or 105 days in any 365 day period, the purchasers are entitled to receive liquidated damages. Liquidated damages are calculated as 0.25% of the Liquidated Damages Multiplier per 30-day period for the first 60 days following the 90th day, increasing by an additional 0.25% of the Liquidated Damages Multiplier per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the Liquidated Damages Multiplier per 30-day period. The Liquidated Damages Multiplier is (i) the product of $36.59 times the number of common units purchased that have not yet been resold pursuant to the registration statement plus (ii) the product of $35.81 times the number of Class B Units purchased.

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

Note 8. Segment Disclosures

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

		Gathering &				Gathering &
		Processing -				Processing -				NGL
		West				Gulf				Services				Total
		(In thousands)
Three Months Ended March 31, 2007:
Segment revenues		$	120,428			$	561			$	12,826			$	133,815
Operating and maintenance expense			33,097				550				8,866				42,513
Product cost and shrink replacement			39,675				—				2,520				42,195
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-Discovery Producer Services			—				2,620				—				2,620
Segment profit		$	31,276			$	2,327			$	53			$	33,656
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
Three Months Ended March 31, 2006:
Segment revenues		$	115,672			$	733			$	16,330			$	132,735
Operating and maintenance expense			29,095				242				7,449				36,786
Product cost and shrink replacement			38,277				—				5,723				44,000
Depreciation, amortization and accretion			9,814				300				600				10,714
Direct general and administrative expense			3,400				2				301				3,703
Other, net			(1,567	)			—				207				(1,360	)
Segment operating income			36,653				189				2,050				38,892
Equity earnings-Discovery Producer Services			—				3,781				—				3,781
Segment profit		$	36,653			$	3,970			$	2,050			$	42,673
Reconciliation to the Consolidated Statements of Income:
Segment operating income														$	38,892
General and administrative expenses:
Allocated-affiliate															(4,355	)
Third party-direct															(528	)
Combined operating income														$	34,009

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. The Four Corners system gathers and processes or treats approximately 37% of the natural gas produced in the San Juan Basin and connects with the five pipeline systems that transport natural gas to end markets from the basin.

•

Gathering and Processing — Gulf. Our Gulf segment includes (1) our 40% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline off the coast of Alabama. Discovery owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and an NGL fractionator in Louisiana. These assets generate revenues by providing natural gas gathering, transporting and processing services and integrated NGL fractionating services to customers under a range of contractual arrangements. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such.

•

NGL Services. Our NGL Services segment includes three integrated NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas. These assets generate revenues by providing stand-alone NGL fractionation and storage services using various fee-based contractual arrangements where we receive a fee or fees based on actual or contracted volumetric measures.

Executive Summary

     In the first quarter of 2007 we continued to realize strong NGL margins at Four Corners. This favorable condition was offset by lower gathering and processing revenues and higher operating and maintenance expense. However, we continue to anticipate that expansion opportunities at Four Corners will allow us to improve our full-year gathering volumes over 2006 levels. Discovery saw a relatively small decrease in its income from the prior year when one considers the exceptional first quarter 2006 when it was processing volumes from damaged third-party facilities after Hurricanes Katrina and Rita. Discovery also met important deadlines for the on-time completion of its Tahiti lateral expansion project. Year-over-year net income comparisons are significantly impacted by the interest on our $750 million in long-term debt issued to finance a portion of our acquisition of Four Corners. Additionally, our results reflect the impact of certain net unfavorable adjustments in our operating costs and expenses, which are itemized in Note 4 of the Notes to our Consolidated Financial Statements.

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, 2007, compared to the three months ended March 31, 2006. The results of operations by segment are discussed in further detail following this consolidated overview discussion. All prior period information in the following discussion and analysis of results of operations has been restated to reflect our 100% interest acquisition in Four Corners.

		Three months ended								% Change
		March 31,								from
		2007				2006				2006(1)
		(Thousands)
Revenues		$	133,815			$	132,735				+1	%
Costs and expenses:
Product cost and shrink replacement			42,195				44,000				+4	%
Operating and maintenance expense			42,513				36,786				-16	%
Depreciation, amortization and accretion			13,178				10,714				-23	%
General and administrative expense			10,070				8,586				-17	%
Taxes other than income			2,114				2,283				+7	%
Other (income) expense			460				(3,643	)		NM
Total costs and expenses			110,530				98,726				-12	%
Operating income			23,285				34,009				-32	%
Equity earnings — Discovery			2,620				3,781				-31	%
Interest expense			(14,390	)			(236	)		NM
Interest income			983				70			NM
Net income		$	12,498			$	37,624				-67	%

Three months ended March 31, 2007 vs. three months ended March 31, 2006

     Revenues increased $1.1 million, or 1%, due primarily to higher product sales in our Gathering and Processing — West segment largely offset by lower product sales 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.

     Product cost and shrink replacement decreased $1.8 million, or 4%, due to primarily to lower average natural gas prices in our Gathering and Processing — West segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.

     Operating and maintenance expense increased $5.7 million, or 16%, due in large part to the impact of certain adjustments in our Gathering and Processing — West and NGL Services segments. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

     The $2.5 million, or 23%, increase in Depreciation, amortization and accretion includes $2.0 million of first quarter 2007 right-of-way amortization and asset retirement obligation adjustments.

     General and administrative expense increased $1.5 million, or 17%, due primarily to higher Williams incentive program costs, technical support services, and other charges allocated by Williams to us for various administrative support functions.

     Other (income) expense, net changed from $3.6 million income in 2006 to $0.5 million expense in 2007, due primarily to a $3.6 million gain in 2006 on the sale of property in the Gathering and Processing — West segment.

     Operating income declined $10.7 million, or 32%, due primarily to higher operating and maintenance expense, and the absence of the 2006 gain on the sale of property.

     Equity earnings from Discovery decreased $1.2 million. This decrease is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

     Interest expense increased $14.2 million due to interest on our $750.0 million senior unsecured notes issued in June and December 2006 to finance a portion of our acquisition of Four Corners.

Results of operations — Gathering and Processing — West

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

Four Corners

		Three months ended
		March 31,
		2007				2006
		(Thousands)
Revenues		$	120,428			$	115,672
Costs and expenses, including interest:
Product cost and shrink replacement			39,675				38,277
Operating and maintenance expense			33,097				29,095
Depreciation, amortization and accretion			12,175				9,814
General and administrative expense — direct			1,821				3,400
Taxes other than income			1,924				2,076
Other (income) expense, net			460				(3,643	)
Total costs and expenses, including interest			89,152				79,019
Segment profit		$	31,276			$	36,653

Three months ended March 31, 2007 vs. three months ended March 31, 2006

     Revenues increased $4.8 million, or 4% percent, due primarily to $5.1 million higher product sales partially offset by $0.5 million lower gathering and processing revenue.

     Product sales revenues increased due primarily to:

•

$3.3 million related to a 10% increase in NGL volumes that Four Corners received under certain processing contracts. This increase was related primarily to improved ethane processing margins in 2007;

•

$1.1 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 $1.1 million discussed below;

•

$0.4 million related to a slight increase in average NGL sales prices realized on sales of NGLs which we received under certain processing contracts; and

•

$0.3 million related to a slight increase in condensate and LNG sales.

     The $0.5 million decrease in fee-based gathering and processing revenues is due primarily to $1.6 million lower revenue from a 3% decrease in gathering and processing volumes, partially offset by $0.8 million of revenue from billings of back charges on a customer contract for 2005 and 2006.

     Product cost and shrink replacement increased $1.4 million, or 4%, due primarily to:

•

$2.3 million increase from 14% higher volumetric shrink requirements associated with the increased NGL volumes received under Four Corners’ keep-whole processing contracts discussed above; and

•

$1.1 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.

     These increases were partially offset by a $1.7 million decrease from 9% lower average natural gas prices for shrink replacement.

     Operating and maintenance expense increased $4.0 million, or 14%, due primarily to:

•

the absence of $3.3 million of other adjustments that served to increase income in the first quarter of 2006 as noted in Note 4 of the Notes to our Consolidated Financial Statements; and

•

$1.9 million increase in other operating expenses due primarily to higher leased compression costs.

     These increases were partially offset by a $1.2 million decrease in labor expense resulting from a first quarter 2007 incentive compensation adjustment.

     The $2.4 million, or 24%, increase in Depreciation, amortization and accretion expense includes $2.0 million of first quarter 2007 right-of-way amortization and asset retirement obligation adjustments.

     General and administrative expense — direct decreased $1.6 million, or 46%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense results but not in our segment results.

     Other (income) expense, net changed $4.1 million unfavorably due primarily to a $3.6 million gain recognized on the sale of the LaMaquina treating facility in the first quarter of 2006.

     Segment profit decreased $5.4 million, or 15%, due primarily to $4.0 million higher operating and maintenance expense, the absence of the 2006 $3.6 million gain on the sale of the LaMaquina treating facility and $2.4 million higher depreciation, amortization and accretion. These were partially offset by $3.1 million of higher net liquids margins resulting primarily from increased per-unit margins on higher NGL sales volumes and $1.6 million lower general and administrative expense — direct.

Outlook

     Throughput volumes on our Four Corners gathering, processing and treating system are an important component of maximizing its profitability. Throughput volumes from existing wells connected to its pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels we must continually obtain new supplies of natural gas.

•

In 2007, we anticipate that sustained drilling activity, expansion opportunities and production enhancement activities by existing customers should be sufficient to more than offset the historical decline and increase gathered and processed volumes.

•

We have realized above average margins at our gas processing plants in recent years due primarily to increasing prices for NGLs. We expect per-unit margins in 2007 will remain higher in relation to five-year historical averages but below the record levels realized in 2006. Additionally, we anticipate that our contract mix and commodity management activities at Four Corners will continue to allow us to realize greater margins relative to industry benchmark averages.

•

In May 2007, we hedged 8.8 million gallons of May through December 2007 forecasted NGL sales using financial swap contracts with a range of fixed prices of $1.15 to $1.62 per gallon depending on the specific product. We receive the underlying NGL gallons as compensation for processing services provided at Four Corners. We have designated these derivatives as cash flow hedges under Statement of Financial Accounting Standards No. 133.

•

We anticipate that operating costs, excluding compression, will remain stable as compared to 2006. Compression cost increases are dependent upon the extent and amount of additional compression needed to meet the needs of our Four Corners customers and the cost at which compression can be purchased, leased and operated.

•

We continue to operate our assets on the Jicarilla Apache Nation in Northern New Mexico pursuant to a special business license which extends through June 30, 2007 while we conduct further discussions that could result in renewal of our rights of way, sale of the gathering assets which are on, or are isolated by, reservation lands or other options that might be in the mutual interest of both parties. The current right of way agreement, which covers certain gathering system assets in Rio Arriba County, New Mexico, expired on December 31, 2006.

Results of Operations — Gathering and Processing — Gulf

     The Gulf segment includes the Carbonate Trend gathering pipeline and our 40% ownership interest in Discovery.

		Three months ended
		March 31,
		2007				2006
		(Thousands)
Segment revenues		$	561			$	733
Costs and expenses:
Operating and maintenance expense			550				242
Depreciation			304				300
General and administrative expense - direct			—				2
Total costs and expenses			854				544
Segment operating income (loss)			(293	)			189
Equity earnings — Discovery			2,620				3,781
Segment profit		$	2,327			$	3,970

Carbonate Trend

     Segment operating income (loss) for the three months ended March 31, 2007 was $0.5 million unfavorable as compared to the first quarter of 2006, due primarily to higher insurance premiums related to the increased hurricane activity in the Gulf Coast region in recent years. In addition, gathering revenues decreased due to a 25% decline in average daily gathered volumes. These volumetric declines are caused by normal reservoir depletion that was not offset by new sources of throughput.

Discovery Producer Services

		Three months ended
		March 31,
		2007				2006
		(Thousands)
Revenues		$	52,481			$	62,120
Costs and expenses, including interest:
Product cost and shrink replacement			33,518				41,550
Operating and maintenance expense			6,415				4,822
Depreciation and accretion			6,483				6,379
General and administrative expense			544				690
Interest income			(661	)			(626	)
Other (income) expense, net			(369	)			(147	)
Total costs and expenses, including interest			45,930				52,668
Net income		$	6,551			$	9,452
Williams Partners’ 40 percent interest — Equity earnings per our Consolidated Statements of Income
		$	2,620			$	3,781

Three months ended March 31, 2007 vs. three months ended March 31, 2006

     Revenues decreased $9.6 million, or 16%, due primarily to the absence of the 2006 Tennessee Gas Pipeline (“TGP”) and the Texas Eastern Transmission Company (“TETCO”) open season agreements, which began in the last quarter of 2005. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita. TGP’s open season contract came to an end in early 2006. TETCO’s volumes continued throughout 2006, and in October we signed a one-year contract, which is discussed further in the Outlook section. The significant components of the revenue increase are addressed more fully below.

•

Fee-based processing and fractionation revenues decreased $6.0 million due primarily to $5.4 million in reduced fee-based revenues related to processing the TGP and TETCO open seasons volumes discussed above. In 2006 the open season agreements included fee-based processing and fractionation. Our current agreement with TETCO includes processing services based on a percent-of-liquids contract, where the NGLs we take as compensation are reflected in the higher product sales discussed below.

•

Transportation revenues decreased $2.2 million, including $2.5 million in reduced fee-based revenues related to the absence of TGP and TETCO open season agreements discussed above.

•

Product sales decreased $0.8 million. A $14.8 million decrease in NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs under an option in their contracts was offset by a $10.8 million increase in NGL volumes that Discovery received under certain processing contracts, including our current TETCO agreement, and $2.0 million from higher sales of excess fuel and shrink replacement gas. See below for the corresponding changes in product cost and shrink replacement for each of these components.

     Product cost and shrink replacement decreased $8.0 million, or 19%, due primarily to $14.8 million lower product purchase costs for the processing customers who elected to have Discovery purchase their NGLs, partially offset by $3.9 million higher costs from increased processing activity and $2.0 million higher product cost associated with the excess fuel and shrink replacement gas sales discussed above.

     Operating and maintenance expense increased $1.6 million, or 33%, due primarily to $0.8 million higher property insurance premiums related to the increased hurricane activity in the Gulf Coast region in prior years and various other smaller increases.

     Net income decreased $2.9 million, or 31%, due primarily to $7.9 million lower fee-based revenues from the TGP and TETCO open seasons and $1.6 million higher operating and maintenance expense, largely offset by $7.2 million higher net liquids margins from increased per-unit margins on higher NGL sales volumes.

Outlook

Carbonate Trend

     In compliance with applicable permit requirements, we completed a survey of portions of our Carbonate Trend pipeline. As a result of this survey, we have determined that it will be necessary to undertake certain restoration activities to repair the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004 and Hurricane Katrina in August 2005. We are currently assessing, with our customers, the options for completing these repairs. Once the method of repair has been agreed to by our customers and the regulatory authority, we will fund these repairs with cash flows from operations and seek reimbursement from our insurance carriers and/or customers. We expect these restoration activities will be completed in 2007. Additionally, in the omnibus agreement, Williams agreed to reimburse us for the cost of the restoration activities related to Hurricane Ivan to the extent that we are not reimbursed by our insurance carrier and subject to an overall limitation of $14.0 million for all indemnified environmental and related expenditures generally for a period of three years that ends in August 2008.

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.

•

The Tahiti pipeline lateral expansion project is currently on schedule. The pipeline was installed on the sea bed in February. The end connections and commissioning will take place in the fourth quarter of this year, and we anticipate initial throughput will begin in the first half of 2008. We expect this agreement will have a significant favorable impact on Discovery’s revenues.

•

Discovery signed a one-year processing contract with TETCO effective October 2006 for a minimum volume of 100 BBtu/d and a maximum of 300 BBtu/d. The volume flowing under this contract for the first quarter has been 160 BBtu/d and is continuing at this rate. Additionally, we signed several short term processing arrangements from the TETCO system with multiple producers accounting for an additional 25-50BBtu/d.

•

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.

•

ATP Oil & Gas Corporation completed an additional well in its Gomez prospect and the facility is currently flowing approximately 60 BBtu/d. We expect the rate to increase from this level in the third quarter of 2007 after it installs modifications to the facility, which could result in a temporary disruption of service. This disruption could potentially reduce our revenues by approximately $0.9 million.

•

In December 2006 we signed an agreement with Energy Partner’s LTD, which is anticipated to result in at least approximately 10 BBtu/d of throughput beginning in the second quarter of 2007.

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,
		2007				2006
		(Thousands)
Segment revenues		$	12,826			$	16,330
Costs and expenses:
Operating and maintenance expense			8,866				7,449
Product cost			2,520				5,723
Depreciation and accretion			699				600
General and administrative expense — direct			498				301
Other expense, net			190				207
Total costs and expenses			12,773				14,280
Segment profit		$	53			$	2,050

Three months ended March 31, 2007 vs. three months ended March 31, 2006

     Segment revenues decreased $3.5 million, or 21%, due primarily to lower product sales and fractionation revenues slightly offset by higher storage revenues. The significant components of the revenue fluctuations are addressed more fully below.

•

Product sales decreased $3.4 million due to lower sales volumes. This decrease was offset by the related decrease in product cost discussed below.

•

Fractionation revenues decreased $2.0 million due primarily to 32% lower fractionation volumes and 28% lower rates. Fractionation throughput was down during the first quarter of 2007 due to a customer’s decision to fractionate a percentage of their volumes outside of the Mid-Continent region. Such a decision is based on current prices being paid for fractionated products outside of the Mid-Continent region. In March 2007 these volumes were once again being fractionated at our Conway facility. The lower fractionation rate relates to the pass through to customers of decreased fuel and power costs.

•

Storage revenues increased $1.3 million due primarily to higher average storage volumes from additional short-term storage leases.

     Operating and maintenance expense increased $1.4 million, or 19%, due primarily to a first quarter 2007 product imbalance valuation adjustment.

     Product cost decreased $3.2 million, or 56%, due to the lower product sales volumes discussed above, resulting in a net margin loss of $0.2 million.

     Segment profit decreased $2.0 million due primarily to the $1.4 million adjustment discussed above and lower fractionation revenues, partially offset by higher storage revenue.

Outlook

•

Conway’s primary storage lease renewal period closed March 31, 2007. Based on confirmed and historical short-term leases, we expect 2007 to result in similar storage revenue as 2006. Customers are renewing storage leases at similar levels to 2006 based on the expectation of positive forward pricing for products.

•

We are developing a capital project to store refinery grade butane (“RGB”) at Conway Underground East. The estimated capital investment is expected to be between $1.0 million and $1.5 million. Contracted new revenue associated with this project is $1.3 million. Potential contracts may generate an additional $0.6 to $1.2 million. We expect that these additional revenues will begin in the second half of 2007.

•

We continue to execute 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 2007 and 2008 to ensure that we meet the regulatory compliance requirement to complete cavern wellhead modifications before the end of 2008. Our forecast for 2007 is to workover approximately 59 caverns (both complete and partial) compared to 51 cavern workovers (38 complete and 13 partial) in 2006. During the first quarter of 2007 we completed 16 workovers with another 25 caverns out of service for workovers.

Financial Condition and Liquidity

     We believe we have the financial resources and liquidity necessary to meet future requirements for working capital, capital and investment expenditures, debt service and quarterly cash distributions. We anticipate our sources of liquidity for 2007 will include:

•

Cash and cash equivalents on hand;

•

Cash generated from operations, including cash distributions from Discovery;

•

Insurance or other recoveries related to the Carbonate Trend overburden restoration, which should be received, approximately, as costs are incurred;

•

Capital contributions from Williams pursuant to the omnibus agreement; and

•

Credit facilities, as needed.

     We anticipate our more significant capital requirements for the remainder of 2007 to be:

•

Maintenance capital expenditures for our Four Corners and Conway assets;

•

Expansion capital expenditures for our Four Corners assets;

•

Carbonate Trend overburden restoration;

•

Interest on our long-term debt; and

•

Quarterly distributions to our unitholders.

Discovery

     Discovery expects to make quarterly distributions of available cash to its members pursuant to the terms of its limited liability company agreement. Discovery made the following 2007 distributions to its members (all amounts in thousands):

		Total Distribution to
Date of Distribution		Members		Our 40% Share
1/30/07		$  9,000		$3,600
4/30/07		$16,000		$6,400

     In 2005, Discovery’s facilities sustained damages from Hurricane Katrina. The estimated total cost for hurricane-related repairs is approximately $26.0 million, including $24.5 million in potentially reimbursable expenditures in excess of its insurance deductible. Of this amount, $18.1 million has been spent as of March 31, 2007. Discovery is funding these repairs with cash flows from operations and is seeking reimbursement from its insurance carrier. As of March 31, 2007, Discovery has received $4.9 million from the insurance carriers and has an insurance receivable balance of $13.2 million. The insurance carriers have approved an $11.0 million payout which is expected to be received in the second quarter of 2007. We anticipate receiving 40% of the $11.0 million in addition to our normal quarterly distribution from Discovery in July 2007.

     We expect Discovery to fund future cash requirements relating to working capital and maintenance capital expenditures from its own internally generated cash flows from operations. We expect Discovery to fund growth or expansion capital expenditures either by cash calls to its members, which requires the unanimous consent of the members except in limited circumstances, or from internally generated funds.

Capital Contributions from Williams

     Capital contributions from Williams required under the omnibus agreement consist of the following:

•

Indemnification of environmental and related expenditures, less any related insurance recoveries, for a period of three years (for certain of those expenditures) up to a cap of $14 million. Amounts expected to be incurred in 2007 related to these indemnifications are as follows:

Ø

approximately $2.9 million for capital expenditures related to KDHE-related cavern compliance at our Conway storage facilities; and

Ø

approximately $1.2 million for our 40% share of Discovery’s costs for marshland restoration and repair or replacement of Paradis’ emission-control flare.

•

An annual credit for general and administrative expenses of $2.4 million in 2007, $1.6 million in 2008 and $0.8 million in 2009.

•

Up to $3.4 million to fund our 40% share of the expected total cost of Discovery’s Tahiti pipeline lateral expansion project in excess of the $24.4 million we contributed during September 2005. As of March 31, 2007 we have received $1.6 million from Williams for this indemnification.

     We expect all costs to repair the partial erosion of the Carbonate Trend pipeline overburden caused by Hurricane Ivan in 2004 will be recoverable from insurance and/or contractual counterparties, but to the extent they are not, we will seek indemnification under the omnibus agreement. We are in discussions with our contractual counterparties with respect to these restoration activities.

     As of March 31, 2007 we have received $2.7 million from Williams for indemnified items since inception of the agreement in August 2005. Thus, approximately $11.3 million remains for reimbursement of our costs on these items.

Credit Facilities

     We may borrow up to $75.0 million under Williams’ $1.5 billion revolving credit facility, which is available for borrowings and letters of credit. Borrowings under this facility mature on May 1, 2009. Our $75.0 million borrowing limit under Williams’ revolving credit facility is available for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. At March 31, 2007, letters of credit totaling $28.0 million had been issued on behalf of Williams by the participating institutions under this facility and no revolving credit loans were outstanding.

     We also have a $20.0 million revolving credit facility with Williams as the lender. The facility was amended and restated on August 7, 2006. The facility is available exclusively to fund working capital borrowings. Borrowings under the amended and restated facility will mature on June 29, 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, 2007 we had no outstanding borrowings under the working capital credit facility.

Capital Requirements

     The natural gas gathering, treating, processing and transportation, and NGL fractionation and storage businesses are 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 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; and

•

Expansion capital expenditures such as those 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.

     The following table provides summary information related to ours and Discovery’s expected capital expenditures for 2007:

Company		Maintenance				Expansion				Total
Conway		$	11.0			$	2.0			$	13.0
Four Corners			25.0				24.0				49.0
Discovery — 100%			7.0				40.0				47.0

     We estimate approximately $2.9 million of Conway’s maintenance capital expenditures may be reimbursed by Williams subject to the omnibus agreement. We expect to fund the remainder of these expenditures through cash flows from operations. These expenditures relate primarily to cavern workovers and wellhead modifications necessary to comply with KDHE regulations.

     Expansion capital expenditures for the Conway assets will be funded from its own internally generated cash flows from operations.

     We expect Four Corners will fund its maintenance capital expenditures through its cash flows from operations. These expenditures include approximately $13.0 million related to well connections necessary to connect new sources of throughput for the Four Corners’ system which serve to offset the historical decline in throughput volumes. The $12.0 million remainder amount relates to various smaller projects.

     We expect Four Corners will fund its expansion capital expenditures through its cash flows from operations. These expenditures include estimates of approximately $6.0 million for certain well connections that we believe will increase throughput volumes in 2007. The $18.0 million remainder amount relates primarily to plant and gathering system expansion projects.

     We estimate approximately $1.2 million of Discovery’s maintenance capital expenditures may be reimbursed by Williams subject to the omnibus agreement. We expect Discovery will fund the remainder of its maintenance capital expenditures through its cash flows from operations. These maintenance capital expenditures relate to numerous smaller projects.

     We estimate that expansion capital expenditures for 100% of Discovery will be approximately $40.0 million for 2007, of which our 40% share is $16.0 million. Of the 100% amount, approximately $34 million is for the ongoing construction of the Tahiti pipeline lateral expansion project. Discovery will fund the originally approved expenditures with amounts previously escrowed for this project. We currently anticipate that the project will exceed the original estimate by approximately $2.5 million and that this amount will be funded with cash on hand or contributions from Discovery’s members, including us.

Carbonate Trend Overburden Restoration

     We will fund the repairs related to the partial erosion of the Carbonate Trend pipeline overburden caused by Hurricane Ivan in 2004 and Hurricane Katrina in 2005 with cash flows from operations and then seek reimbursement from insurance and/or contractual counterparties. We are in discussions with our contractual counterparties with respect to these restoration activities.

Debt Service — Long-Term Debt

     We have $150.0 million senior unsecured notes outstanding that bear interest at 7.5% per annum payable semi-annually in arrears on June 15 and December 15 of each year. The senior notes mature on June 15, 2011.

     Additionally, we have $600.0 million of 7.25% senior unsecured notes outstanding. The maturity date of the notes is February 1, 2017. Interest is payable semi-annually in arrears on February 1 and August 1 of each year, beginning on August 1, 2007.

Cash Distributions to Unitholders

     We paid quarterly distributions to common and subordinated unitholders and our general partner interest after every quarter since our initial public offering (“IPO”) on August 23, 2005. Our most recent quarterly distribution of $21.1 million will be paid on May 15, 2007 to the general partner interest and common, Class B and subordinated unitholders of record at the close of business on May 7, 2007. This distribution includes an additional incentive distribution to our general partner of approximately $1.0 million.

     Our general partner called a special meeting of common unitholders for May 21, 2007 to vote upon a proposal to approve (a) a change in the terms of our Class B units to provide that each Class B unit is convertible into one of our common units and (b) the issuance of additional common units upon such conversion (the “Class B Conversion and Issuance Proposal”). Upon approval of this proposal, all 6,805,492 outstanding Class B units will convert automatically into 6,805,492 common units without any further action. If the Class B Conversion and Issuance Proposal is not approved by the holders of our common units, then beginning on June 11, 2007, the Class B units will be entitled to receive (i) 115% of the quarterly distribution payable on common units and (ii) 115% of any distributions on liquidation payable on the common units. Although, in each case, the Class B units would remain subordinated to the common units, any increase in distributions payable on the Class B units would reduce the amount of cash available for distributions to holders of common units.

Results of Operations — Cash Flows

     Williams Partners L.P.

		Three months ended
		March 31,
		2007				2006
		(Thousands)
Net cash provided by operating activities		$	50,796			$	31,859
Net cash used by investing activities			(11,196	)			(2,415	)
Net cash used by financing activities			(18,649	)			(31,968	)

     The $18.9 million increase in net cash provided by operating activities for the first three months of 2007 as compared to the first three months of 2006 is due primarily to a $25.0 million increase in cash provided by working capital excluding accrued interest. Working capital increased due primarily to an increase in cash provided by accounts payable. These working capital increases were offset by the following decreases:

•

$5.1 million decrease in operating income as adjusted for non-cash items; and

•

$0.8 million decrease in distributed earnings from Discovery.

     Net cash used by investing activities includes maintenance and expansion capital expenditures primarily used for well connects in our Four Corners business and the installation of cavern liners and KDHE-related cavern compliance with the installation of wellhead control equipment and well meters in our NGL Services segment. The cash used in investing in 2007 was higher due primarily to the absence of $7.2 million of proceeds received on the sale of property, plant and equipment in 2006.

     Net cash used by financing activities decreased $13.3 million for the first three months of 2007 as compared to the first three months of 2006 due to $28.2 million of Four Corners’ net cash flows distributed to Williams in 2006 prior to our acquisition of Four Corners, partially offset by a $14.5 million increase in quarterly distributions to unitholders.

     Discovery — 100 percent

		Three months ended
		March 31,
		2007				2006
		(Thousands)
Net cash provided by operating activities		$	1,469			$	18,515
Net cash provided (used) by investing activities			(1,517	)			608
Net cash used by financing activities			(6,600	)			(6,215	)

     Net cash provided by operating activities decreased $17.0 million in 2007 as compared to 2006 due primarily to a $14.2 million decrease in cash from changes in working capital and a $2.8 million decrease in operating income, adjusted for non-cash expenses. The change in working capital is due primarily to an extra month of liquid sales invoices outstanding at the end of the first quarter of 2006.

     Net cash used by investing activities increased in 2007 related primarily to increased spending on the Tahiti pipeline lateral expansion project, which was not entirely funded from amounts previously escrowed in 2005 and included on the balance sheet as restricted cash.

     Net cash used by financing activities in 2007 includes $4.5 million lower distributions paid to members offset by $4.9 million of lower capital contributions from members to finance capital projects.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk and interest rate risk.

     Commodity Price Risk

     Certain of our and Discovery’s processing contracts are exposed to the impact of price fluctuations in the commodity markets, including the correlation between natural gas and NGL prices. In addition, price fluctuations in commodity markets could impact the demand for our and Discovery’s services in the future. Our Carbonate Trend pipeline and our fractionation and storage operations are not directly affected by changing commodity prices except for product imbalances, which are exposed to the impact of price fluctuation in NGL markets. Price fluctuations in commodity markets could also impact the demand for storage and fractionation services in the future. In connection with the IPO, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. This physical contract is intended to mitigate the fuel price risk under one of our fractionation contracts which contains a cap on the per-unit fee that we can charge, at times limiting our ability to pass through the full amount of increases in variable expenses to that customer. This physical contract is a derivative. However, we elected to account for this contract under the normal purchases exemption to the fair value accounting that would otherwise apply. We also have physical contracts for the purchase of ethane and the sale of propane related to our operating supply management activities at Conway. These physical contracts are derivatives. However, we elected to account for these contracts under the normal purchases exemption to the fair value accounting that would otherwise apply.

     In May 2007, we hedged 8.8 million gallons of May through December 2007 forecasted NGL sales using financial swap contracts with a range of fixed prices of $1.15 to $1.62 per gallon depending on the specific product. We receive the underlying NGL gallons as compensation for processing services provided at Four Corners. We have designated these derivatives as cash flow hedges under Statement of Financial Accounting Standards No. 133.

     Interest Rate Risk

     Our long-term senior unsecured notes have fixed interest rates. Any borrowings under our credit agreements would be at a variable interest rate and would expose us to the risk of increasing interest rates. As of March 31, 2007 we did not have borrowings under our credit agreements.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

     An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d) — (e) of the Securities Exchange Act) (“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 general partner’s 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.

     Our management, including our general partner’s chief executive officer and chief financial officer, does not expect that our 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 the company 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 also is 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 the Internal Controls will be modified as systems change and conditions warrant.

First-Quarter 2007 Changes in Internal Control Over Financial Reporting

     There have been no changes during the first quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

     The information required for this item is provided in Note 7, Commitments and Contingencies, included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which information is incorporated by reference into this item.

Item 1A. Risk Factors

     There are no material changes to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006.

Item 6. Exhibits

     The exhibits listed below are filed or furnished as part of this report:

Exhibit
Number		Description
+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.

SIGNATURES

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.

May 3, 2007

EXHIBIT INDEX

Exhibit
Number		Description
+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.