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 June 30, 2005

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

(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 o     No þ

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

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 issuer had 7,000,000 common units and 7,000,000 subordinated units outstanding as of September 22, 2005.

 

 

WILLIAMS PARTNERS L.P.
INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statements of Operations — Three and Six Months Ended June 30, 2005 and 2004			3
Consolidated Balance Sheets — June 30, 2005 and December 31, 2004			4
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2005 and 2004			5
Notes to Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
Item 3. Quantitative and Qualitative Disclosures about Market Risk			28
Item 4. Controls and Procedures			28
Part II. Other Information
Item 1. Legal Proceedings			29
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			29
Item 5. Other Information			30
Item 6. Exhibits			30
Base Contract for Sale & Purchase of Natural Gas
Rule 13a-14(a)/15d-14(a) Certifications of CEO
Rule 13a-14(a)/15d-14(a) Certifications of CFO
Section 1350 Certifications of CEO & CFO

FORWARD-LOOKING STATEMENTS

     Certain matters discussed in this quarterly report, excluding historical information, include forward-looking statements — statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

     Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “continues,” “estimates,” “forecasts,” “might,” “potential,” “projects” or similar expressions. Similarly, statements that describe our future plans, objectives or goals are also forward-looking statements.

     Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. These risks and uncertainties include, among other things:

	•		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, our success depends on our ability to obtain new sources of natural gas supply, which is dependent on factors beyond our control, including Discovery’s ability to complete its Tahiti lateral expansion project. Any decrease in supplies of natural gas could adversely affect our business and operating results.
	•		Our processing, fractionation and storage business 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.

	•		The revolving credit facility of The Williams Companies, Inc. (“Williams”) 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 cannot initially remove our general partner without its consent.
	•		You may be required to pay taxes on your share of our income even if you 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.
	•		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.

     Additional information about risks and uncertainties that could cause actual results to differ materially from forward-looking statements is contained under the caption “Risk Factors” in our prospectus dated August 17, 2005 as filed with the Securities and Exchange Commission on August 19, 2005 pursuant to Rule 424(b) of the Securities Act of 1933. We refer you to that filing for that additional information regarding our risks and uncertainties.

     The forward-looking statements included in this report are only made as of the date of this report and we undertake no obligation to publicly update forward-looking statements to reflect subsequent events or circumstances.

PART I — FINANCIAL INFORMATION

Item 1. Financials Statements.

WILLIAMS PARTNERS L.P.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
						(Thousands)
Revenues:
Storage		$	4,638			$	3,801			$	9,026			$	6,910
Fractionation			2,307				2,152				4,737				4,130
Gathering			766				1,100				1,646				2,266
Product sales:
Affiliate			3,679				—				6,508				—
Third-party			—				432				63				1,560
Other:
Affiliate			—				—				—				28
Third-party			786				1,558				1,565				2,102
Total revenues			12,176				9,043				23,545				16,996
Costs and expenses:
Operating and maintenance expense:
Affiliate			2,693				2,406				5,346				4,693
Third-party			99				3,891				3,174				4,214
Product cost			3,327				334				6,062				1,371
Depreciation			893				909				1,798				1,778
General and administrative expense:
Affiliate			851				551				1,538				1,093
Third-party			27				19				46				38
Taxes other than income			146				179				338				358
Total costs and expenses			8,036				8,289				18,302				13,545
Operating income			4,140				754				5,243				3,451
Equity earnings — Discovery Producer Services LLC			691				1,292				2,903				3,274
Interest expense:
Affiliate			(2,812	)			(3,006	)			(5,617	)			(6,116	)
Third-party			(170	)			(165	)			(369	)			(165	)
Net income (loss)		$	1,849			$	(1,125	)		$	2,160			$	444

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		June 30,				December 31,
		2005				2004
		(Unaudited)
		(Thousands)
ASSETS
Current assets:
Accounts receivable:
Trade		$	1,804			$	2,150
Affiliate			539				—
Other			1,460				1,388
Other current assets			1,171				749
Total current assets			4,974				4,287
Investment in Discovery Producer Services LLC			139,186				147,281
Property, plant and equipment, net			66,757				67,793
Total assets		$	210,917			$	219,361
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable:
Trade		$	1,374			$	2,480
Affiliate			1,610				1,980
Product imbalance			2,768				1,071
Deferred revenue			7,423				3,305
Accrued liabilities			2,735				3,924
Total current liabilities			15,910				12,760
Advances from affiliate			183,026				186,024
Environmental remediation liabilities			3,964				3,909
Other noncurrent liabilities			187				—
Commitments and contingent liabilities (Note 6)
Partners’ capital			7,830				16,668
Total liabilities and partners’ capital		$	210,917			$	219,361

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		Six Months Ended
		June 30,
		2005				2004
		(Thousands)
OPERATING ACTIVITIES:
Net income		$	2,160			$	444
Adjustments to reconcile to cash provided by operations:
Depreciation			1,798				1,778
Undistributed earnings of Discovery Producer Services LLC			(2,903	)			(3,274	)
Cash provided (used) by changes in assets and liabilities:
Accounts receivable			(265	)			796
Other current assets			(422	)			(288	)
Accounts payable			(1,476	)			1,204
Accrued liabilities			(492	)			126
Deferred revenue			4,118				6,343
Other, including changes in noncurrent liabilities			1,159				(130	)
Net cash provided by operating activities			3,677				6,999
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(679	)			(368	)
Net cash used by investing activities			(679	)			(368	)
FINANCING ACTIVITIES:
Changes in advances from affiliates — net			(2,998	)			(6,631	)
Net cash used by financing activities			(2,998	)			(6,631	)
Increase in cash and cash equivalents			—				—
Cash and cash equivalents at beginning of period			—				—
Cash and cash equivalents at end of period		$	—			$	—

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 quarterly 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 Discovery Producer Services LLC, in which we own a 40 percent 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 percent interest in Discovery Producer Services LLC (“DPS”); (2) the Carbonate Trend gathering pipeline; (3) three integrated natural gas liquids (“NGL”) product storage facilities near Conway, Kansas; and (4) a 50 percent undivided ownership interest in a fractionator near Conway, Kansas. Prior to the closing of our initial public offering (the “IPO”) in August 2005, the 40 percent interest in DPS was held by Williams Energy, L.L.C. (“Energy”) and Williams Discovery Pipeline LLC; the Carbonate Trend gathering pipeline was held in Carbonate Trend Pipeline LLC (“CTP”), which was owned by Williams Mobile Bay Producers Services, L.L.C.; and the NGL product storage facilities and the interest in the fractionator were owned by Mid-Continent Fractionation and Storage, LLC (“MCFS”). All of these are all wholly-owned indirect subsidiaries of The Williams Companies, Inc. (collectively “Williams”). Williams Partners GP LLC, a Delaware limited liability company, was also formed in February 2005, to serve as the general partner for us. Additionally, Williams Partners Operating LLC, a wholly-owned operating limited liability company through which all our activities are conducted, was formed.

    Initial Public Offering, Concurrent Transactions and Subsequent Events

     On August 23, 2005, we completed our IPO of 5,000,000 common units representing limited partner interests in us at a price of $21.50 per unit. The proceeds of $100.2 million, net of the underwriters’ discount and a structuring fee of $7.3 million, were used to:

	•		distribute $58.7 million to Williams, in part to reimburse Williams for capital expenditures relating to the assets contributed to us and for a gas purchase contract contributed to us;
	•		provide $24.4 million to make a capital contribution to DPS to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;
	•		provide $12.8 million of additional working capital; and
	•		pay $4.3 million of expenses associated with the IPO and related formation transactions.

     Concurrent with the closing of the IPO, the 40 percent interest in DPS and all of the interests in CTP and MCFS were contributed to us by Williams subsidiaries in exchange for an aggregate of 2,000,000 common units and 7,000,000 subordinated units. The public, through the underwriters of the offering, contributed $107.5 million ($100.2 million net of the underwriters’ discount and a structuring fee) to us in exchange for 5,000,000 common units, representing a 35 percent limited partner interest in us. Additionally, at the closing of the IPO the underwriters fully exercised their option to purchase 750,000 common units from Williams subsidiaries at the IPO price of $21.50 per unit, less the underwriters’ discount and a structuring fee.

     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 combined financial statements and notes thereto included in our prospectus dated August 17, 2005 as filed with the Securities and Exchange Commission on August 19, 2005 pursuant to Rule 424(b) of the Securities Act of 1933. 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 June 30, 2005, and results of operations for the three months and six months ended June 30, 2005 and 2004 and cash flows for the six months ended June 30, 2005 and 2004. All intercompany transactions have been eliminated.

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     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. Description of Business

     We are principally engaged in the business of gathering, transporting and processing natural gas and fractionating and storing NGLs. Operations of our businesses are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) NGL Services. Our Gathering and Processing segment includes our equity investment in DPS and the Carbonate Trend gathering pipeline. Our NGL Services segment includes the Conway fractionation and storage operations.

     Gathering and Processing. We own a 40 percent interest in DPS, which owns 100 percent of Discovery Gas Transmission LLC (collectively referred to as “Discovery”). Discovery owns (1) a 273-mile natural gas gathering and transportation pipeline system, located primarily off the coast of Louisiana in the Gulf of Mexico, (2) a 600 million cubic feet per day (“MMcf/d”) cryogenic natural gas processing plant near Larose, Louisiana, (3) a 32,000 barrels per day (“bpd”) NGL fractionator near Paradis, Louisiana and (4) two onshore liquids pipelines, including a 22-mile mixed NGL pipeline connecting the gas processing plant to the fractionator and a 10-mile condensate pipeline connecting the gas processing plant to a third party oil gathering facility. 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. Hence, this equity investment is considered part of the Gathering and Processing segment.

     Our Carbonate Trend gathering pipeline is an unregulated sour gas gathering pipeline consisting of approximately 34 miles of pipeline off the coast of Alabama.

     NGL Services. Our Conway storage facilities include three integrated underground NGL storage facilities with 158 active caverns in the Conway, Kansas, area with a storage capacity of approximately 20 million barrels. The facilities are connected via a series of pipelines. The storage facilities receive daily shipments of a variety of products, including mixed NGLs and other hydrocarbons. In addition to pipeline connections, one facility offers truck and rail service.

     Our Conway fractionation facility is located near McPherson, Kansas, and has a capacity of approximately 107,000 bpd. We own a 50 percent undivided interest in these facilities representing capacity of approximately 53,500 bpd. Williams operates the facility pursuant to an operating agreement that extends through May 2011. The fractionator separates mixed NGLs into five products: ethane, propane, normal butane, isobutane and natural gasoline. Portions of these products are then transported and stored at our Conway storage facilities.

Note 3. Related Party Transactions

     The employees of our operated assets and all of our general and administrative employees are employees of Williams. Williams directly charges us for the payroll costs associated with these employees. Williams carries the obligations for most employee-related benefits in its financial statements, including the liabilities related to the employee retirement and medical plans and paid time off. Certain of these costs are charged back to the other Conway fractionator co-owners. Our share of those costs are charged to us through affiliate billings and reflected in Operating and maintenance expense — Affiliate in the accompanying Consolidated Statements of Operations.

     Williams charges its affiliates, including its Midstream segment of which we are a part, for certain corporate administrative expenses that are directly identifiable or allocable to the affiliates. Direct costs charged from Williams represent the direct costs of services provided by Williams on our behalf. A portion of the charges allocated to the Midstream segment are then reallocated to us. These allocated corporate administrative expenses are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. Certain of these costs are charged back to the other Conway fractionator co-owners. Our share of these costs is reflected in General and administrative expenses — Affiliate in the accompanying Consolidated Statements of Operations. In

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. Following the closing of the IPO on August 23, 2005, Williams will give us an annual credit for general and administrative expenses under the terms of an omnibus agreement. Those annual credits are as follows: $3.9 million in 2005 ($1.4 million pro rated for the portion of the year from August 23 to December 31), $3.2 million in 2006, $2.4 million in 2007, $1.6 million in 2008 and $0.8 million in 2009.

     We purchase fuel for the Conway fractionator, including fuel on behalf of the co-owners, from Williams Power Company (“Power”), a wholly-owned subsidiary of Williams. These purchases are made at market rates at the time of purchase. 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 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. The gas purchase contract is for the purchase of a sufficient quantity of natural gas to satisfy our fuel requirements under this fractionation contract and terminates on December 31, 2007. Our share of these costs is reflected in Operating and maintenance expense — Affiliate in the accompanying Consolidated Statements of Operations.

     In December 2004, we began selling NGLs to Power, which takes title to the product and resells it, for its own account, to end users. Revenues associated with these activities are reflected as Affiliate revenues on the Consolidated Statements of Operations. The transactions conducted between us and Power are transacted at current market prices for the products.

     A summary of the general and administrative expenses directly charged and allocated to us and fuel purchases from Power for the periods stated is as follows:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
						(Thousands)
General and administrative expense, including amounts subsequently charged to co-owners:
Allocated		$	607			$	448			$	1,110			$	873
Directly charged			245				104				428				220
Operating and maintenance expense, including amounts subsequently charged to co-owners:
Fuel purchases			4,892				4,294				9,800				7,695
Salaries and benefits			825				880				1,660				1,754

     The per-unit gathering fee associated with two of our Carbonate Trend gathering contracts was negotiated on a bundled basis that includes transportation along a segment of a pipeline system owned by Transcontinental Gas Pipe Line Company (Transco), a wholly-owned subsidiary of Williams. The fees we realize are dependent upon whether our customer elects to utilize this Transco capacity. When they make this election, our gathering fee is determined by subtracting the Transco tariff from the total negotiated fee. The rate associated with the capacity agreement is based on a Federal Energy Regulatory Commission tariff that is subject to change. Accordingly, if the Transco rate increases, our net gathering fees for these two contracts may be reduced. The customers with these bundled contracts must make an annual election to receive this capacity. For 2005, only one of our customers has elected to utilize this capacity.

     We currently participate in Williams’ cash management program; thus, we carry no cash balances on our Consolidated Balance Sheets. Effective with the IPO, we began maintaining our own bank accounts but will continue to utilize Williams’ personnel to manage our cash and investments. As of June 30, 2005 and December 31, 2004, our net Advances from affiliate consist of an unsecured promissory note agreement with Williams for both advances to and from Williams. The advances are due on demand; however, Williams has not historically required

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

repayment. Therefore Advances from affiliate at June 30, 2005 and December 31, 2004 are classified as noncurrent. Prior to the closing of the IPO, Williams forgave the advances due to them at the date the net assets were transferred to us. Accordingly, the advances balance will be reflected as Partners’ capital at that date.

     Affiliate interest expense is calculated using Williams’ weighted average cost of debt applied to the outstanding balance of the advances with Williams. The interest rate on the advances with Williams was 7.361 percent and 7.373 percent at June 30, 2005 and December 31, 2004, respectively.

Note 4. Investments

     Investments at June 30, 2005 and December 31, 2004 represent our 40 percent ownership interest in Discovery, which is accounted for using the equity method of accounting. At June 30, 2005, Williams owns an additional 26.67 percent ownership interest in Discovery through Energy. Of the total 66.67 percent ownership interest owned by Williams prior to the transfer of 40 percent to us, 16.67 percent was acquired by Williams in April 2005 resulting in a revised basis used for the calculation of the 40 percent interest transferred to us in connection with the IPO. As a result, the carrying value of our 40 percent interest in Discovery and Partners’ capital decreased $11.0 million during the second quarter. Another non-affiliated member of Discovery has an option, which expires October 31, 2005, to acquire a 6.67 percent interest in Discovery from Williams. The exercise of this option would have no impact on us. Although, on a combined basis, we and Williams hold a 66.67 percent interest in Discovery, the voting provisions of DPS’ limited liability company agreement give the other member of Discovery significant participatory rights such that we and Williams do not control Discovery.

     Williams is the operator of Discovery. Discovery reimburses Williams for actual payroll and employee benefit costs incurred on its behalf. In addition, Discovery pays Williams a monthly operations and management fee to cover the cost of accounting services, computer systems and management services provided to it. Discovery also has an agreement with Williams pursuant to which Williams markets the NGLs and excess natural gas to which Discovery takes title.

     On August 22, 2005, Discovery made a distribution of approximately $43.8 million to Williams and the other member of Discovery, its members at that date. This distribution was associated with Discovery’s operations prior to the IPO; hence, we did not receive any portion of this distribution.

     Due to the significance of Discovery’s equity earnings to our results of operations, the summarized financial position and results of operations for 100 percent of Discovery are presented below (in thousands).

		June 30,				December 31,
		2005				2004
		(unaudited)
Current assets		$	66,023			$	67,534
Property, plant and equipment			351,625				356,385
Current liabilities			(17,997	)			(31,572	)
Non-current liabilities			(747	)			(702	)
Members’ capital		$	398,904			$	391,645

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
						(unaudited)
Revenues		$	23,025			$	27,962			$	50,314			$	55,785
Costs and expenses			21,687				24,764				43,729				47,577
Interest income			(389	)			(140	)			(673	)			(192	)
Net income		$	1,727			$	3,338			$	7,258			$	8,400

Note 5. Credit Facilities

     On May 20, 2005, Williams amended its $1.275 billion revolving credit facility (“Williams facility”), which is available for borrowings and letters of credit, to allow us to borrow up to $75 million under the Williams facility. Borrowings under the Williams facility mature on May 3, 2007. Our $75 million borrowing limit under the Williams 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 June 30, 2005, letters of credit totaling $531 million had been issued on behalf of Williams by the participating institutions under the Williams facility and no revolving credit loans were outstanding.

     Interest on any borrowings under the Williams facility will be calculated based on our choice of two methods: (i) a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. We will also be required to pay or reimburse Williams for a commitment fee based on the unused portion of our $75 million borrowing limit under the Williams facility, currently 0.375 percent annually. The applicable margin, currently two percent, and the commitment fee are based on Williams’ senior unsecured long-term debt rating. Under the Williams facility, Williams and certain of its subsidiaries, other than us, are required to comply with certain financial and other covenants. Significant financial covenants under the Williams facility to which Williams is subject include the following:

	•		ratio of debt to net worth no greater than (i) 70 percent for the period after December 31, 2004 through December 31, 2005, and (ii) 65 percent for the remaining term of the agreement;
	•		ratio of debt to net worth no greater than 55 percent for Northwest Pipeline Corporation, a wholly-owned subsidiary of Williams, and Transco; and
	•		ratio of EBITDA to interest, on a rolling four quarter basis, no less than (i) 2.0 for any period through December 31, 2005 and (ii) 2.5 for the remaining term of the agreement.

     At the closing of the IPO on August 23, 2005, we entered into a $20 million revolving credit facility (the “credit facility”) with Williams as the lender. The credit facility is available exclusively to fund working capital requirements. Borrowings under the credit facility will mature on May 3, 2007 and will bear interest at the same rate as for borrowings under the Williams facility described above. We will pay a commitment fee to Williams on the unused portion of the credit facility of 0.30 percent annually. We are required to reduce all borrowings under the credit facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the credit facility.

Note 6. Commitments and Contingencies

     Environmental Matters. 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,

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

sampling, cleanup and monitoring programs. The costs of such activities will depend upon the program scope ultimately agreed to by the KDHE.

     In 2004, we purchased an insurance policy that covers up to $5 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. 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 million. In addition, under an omnibus agreement with Williams entered into at the closing of the IPO, Williams has agreed to indemnify us for the $4.2 million deductible (less amounts expended prior to the closing of the IPO) of remediation expenditures not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring. There is a $14 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. 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 the 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 $200,000 to $400,000 per year following the completion of the remediation work.

     It is reasonably possible that we will incur losses in excess of our $5.5 million accrued liabilities 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.

     Other. We are not currently a party to any legal proceedings but are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. 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 or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

Note 7. 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.

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		Gathering &				NGL
		Processing				Services				Total
						(Thousands)
Three months ended June 30, 2005
Segment revenues		$	765			$	11,411			$	12,176
Operating and maintenance expense			269				2,523				2,792
Product cost			—				3,327				3,327
Depreciation			300				593				893
Direct general and administrative expense			—				271				271
Other			—				146				146
Segment operating income			196				4,551				4,747
Equity earnings			691				—				691
Segment profit		$	887			$	4,551			$	5,438
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	4,747
Allocated general and administrative expense											(607	)
Combined operating income										$	4,140
Three months ended June 30, 2004
Segment revenues		$	2,049			$	6,994			$	9,043
Operating and maintenance expense			149				6,148				6,297
Product cost			—				334				334
Depreciation			300				609				909
Direct general and administrative expense			—				122				122
Other			—				179				179
Segment operating income (loss)			1,600				(398	)			1,202
Equity earnings			1,292				—				1,292
Segment profit (loss)		$	2,892			$	(398	)		$	2,494
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	1,202
Allocated general and administrative expense											(448	)
Combined operating income										$	754

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		Gathering &				NGL
		Processing				Services				Total
						(Thousands)
Six months ended June 30, 2005
Segment revenues		$	1,645			$	21,900			$	23,545
Operating and maintenance expense			376				8,144				8,520
Product cost			—				6,062				6,062
Depreciation			600				1,198				1,798
Direct general and administrative expense			—				474				474
Other			—				338				338
Segment operating income			669				5,684				6,353
Equity earnings			2,903				—				2,903
Segment profit		$	3,572			$	5,684			$	9,256
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	6,353
Allocated general and administrative expense											(1,110	)
Combined operating income										$	5,243
Six months ended June 30, 2004
Segment revenues		$	3,215			$	13,781			$	16,996
Operating and maintenance expense			262				8,645				8,907
Product cost			—				1,371				1,371
Depreciation			600				1,178				1,778
Direct general and administrative expense			—				258				258
Other			—				358				358
Segment operating income			2,353				1,971				4,324
Equity earnings			3,274				—				3,274
Segment profit		$	5,627			$	1,971			$	7,598
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	4,324
Allocated general and administrative expense											(873	)
Combined operating income										$	3,451

Note 8. Recent Accounting Standards

     In March 2005, the Financial Accounting Standards Board issued Interpretation 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143.” The Interpretation clarifies that the term conditional asset retirement obligation, as used in Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The effective date of this Interpretation is no later than the end of the fiscal year ending after December 15, 2005. We are assessing the impact of this Interpretation on our Consolidated Financial Statements and believe the effect will not be material to our results of operations, financial condition or cash flows.

WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9. Subsequent Events

     On August 29, 2005, Hurricane Katrina struck the Gulf Coast area. In anticipation of the hurricane, the Discovery and Carbonate Trend assets were temporarily shut down on August 27, 2005. The Discovery and Carbonate Trend assets were off-line for 13 and 10 days, respectively. Both assets have returned to service at reduced throughput rates as producers and downstream facilities restore their operations. As of this filing, we estimate the unfavorable impact of this hurricane to our net income to be between $1 million and $1.5 million.

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 historical consolidated financial statements included elsewhere in this quarterly report.

General

     We are a Delaware limited partnership formed in February 2005 to own, operate and acquire a diversified portfolio of complementary energy assets. On August 23, 2005 we completed our initial public offering (“IPO”) of 5,000,000 common units at a price of $21.50 per unit. Net proceeds from the sale of the units totaling $100.2 million were used to:

	•		distribute $58.7 million to affiliates of The Williams Companies, Inc. (“Williams”), the parent of our general partner, in part to reimburse Williams for capital expenditures relating to the assets contributed to us and for a gas purchase contract contributed to us;
	•		provide $24.4 million to make a capital contribution to Discovery Producer Services LLC (“Discovery”) to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;
	•		provide $12.8 million of additional working capital; and
	•		pay $4.3 million of expenses associated with our IPO and related formation transactions.

     Additionally, at the closing of the IPO the underwriters fully exercised their option to purchase 750,000 common units at the IPO price of $21.50 per unit from certain affiliates of Williams.

Overview

     We are principally engaged in the business of gathering, transporting and processing natural gas and fractionating and storing natural gas liquids (“NGL”). We manage our business and analyze our results of operations on a segment basis. Our operations are divided into two business segments:

	•		Gathering and Processing. Our Gathering and Processing segment includes (1) our 40 percent ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline. 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 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 NGL storage facilities and a 50 percent undivided interest in a fractionator near Conway, Kansas. These assets generate revenues by providing 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.

Recent Events

     In July 2005, Discovery executed an agreement with three producers to construct an approximately 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. In late August 2005, the Tahiti producers formally decided to proceed with the project. The Tahiti pipeline lateral expansion is expected to have a design capacity of approximately 200 million cubic feet per day, and its anticipated completion date is May 1, 2007. We expect the total construction cost of the Tahiti pipeline lateral expansion project to be approximately $69.5 million, of which our 40 percent share will be approximately $27.8 million. In September 2005, Discovery established an escrow account to cover a substantial portion of the total expenditures attributable to Williams’ and our share of

these costs. The portion of this escrow account attributable to our interest is $24.4 million. We retained $24.4 million of proceeds from our IPO to make this initial capital contribution to Discovery to fund our share of the payment into the escrow account.

     On August 29, 2005, Hurricane Katrina struck the Gulf Coast area. In anticipation of the hurricane the Discovery and Carbonate Trend assets were temporarily shut down on August 27, 2005. The Discovery and Carbonate Trend assets were off-line for 13 and 10 days, respectively. Both assets have returned to service at reduced throughput rates as producers and downstream facilities restore their operations. We estimate the unfavorable impact of this hurricane to our net income to be between $1 million and $1.5 million.

Results of operations

Consolidated Overview

     The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2005, compared to the three and six months ended June 30, 2004. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

		Three months ended June 30,												Six months ended June 30,
										% Change												% Change
		2005				2004				from 2004 (1)				2005				2004				from 2004 (1)
		(Thousands)												(Thousands)
Revenues		$	12,176			$	9,043				+35	%		$	23,545			$	16,996				+39	%
Costs and expenses:
Operating and maintenance expense			2,792				6,297				+56	%			8,520				8,907				+4	%
Product cost			3,327				334			NM					6,062				1,371			NM
Depreciation			893				909				+2	%			1,798				1,778				-1	%
General and administrative expense			878				570				-54	%			1,584				1,131				-40	%
Taxes other than income			146				179				+18	%			338				358				+6	%
Total costs and expenses			8,036				8,289				+3	%			18,302				13,545				-35	%
Operating income			4,140				754			NM					5,243				3,451				+52	%
Equity earnings — Discovery Producer Services LLC			691				1,292				-47	%			2,903				3,274				-11	%
Interest expense			(2,982	)			(3,171	)			+6	%			(5,986	)			(6,281	)			+5	%
Net income (loss)		$	1,849			$	(1,125	)		NM				$	2,160			$	444			NM

Three months ended June 30, 2005 vs. three months ended June 30, 2004

     The $3.1 million, or 35 percent, increase in Revenues is due mainly to higher revenues in our NGL Services segment, reflecting increased product sales volumes created through our product optimization activities and higher storage rates, partially offset by lower revenues in our Gathering and Processing segment.

     The $3.5 million, or 56 percent, decrease in Operating and maintenance expense is due primarily to lower costs in our NGL Services segment from a gain experienced when draining a cavern in the second quarter of 2005 as

compared to a loss experienced when draining a cavern in the second quarter of 2004 and a delay in the timing of the cavern workovers this year. It is expected that these workovers will be completed in the last half of 2005.

     The $3.0 million increase in Product costs, from $0.3 million, is directly related to the sale of surplus propane volumes created through our product optimization activities.

     The $0.3 million, or 54 percent, increase in General and administrative expense is due primarily to an increase in allocated general and administrative expenses from Williams for personnel providing business development and accounting services to support the requirements of a growing public entity.

     It is anticipated that our general and administrative expenses will increase following the closing of our IPO on August 23, 2005 due to the increased costs of being a publicly traded partnership. These costs include tax return preparation, audit fees, accounting support services, investor relations, directors’ and officers’ insurance, director fees and registration and transfer agent fees. We also expect a further increase in 2006 that reflects a full year as a publicly traded partnership. In an omnibus agreement entered into in connection with the closing of our IPO, Williams has agreed to provide a five-year credit for general and administrative expenses incurred on our behalf. The amount of credit in 2005 will be $3.9 million ($1.4 million pro rated for the period from August 23, 2005 through year end). The amount of credit will be $3.2 million in 2006 and will decrease by approximately $800,000 in each subsequent year. These credits will be reflected as capital contributions from Williams and will not reduce the amount of General and administrative expense reflected in our financial statements.

     The $3.4 million increase in Operating income, from $0.8 million, is due primarily to lower operating and maintenance expense in our NGL Services segment, partially offset by lower revenues in our Gathering and Processing segment.

     The $0.6 million decrease in Equity earnings from Discovery Producer Services LLC is discussed in detail in the “Results of Operations-Gathering and Processing” section below.

     Interest expense is expected to decrease significantly during the remainder of 2005 because the advances from Williams were forgiven prior to the closing of the IPO on August 23, 2005.

Six months ended June 30, 2005 vs. six months ended June 30, 2004

     The $6.5 million, or 39 percent, increase in Revenues is due mainly to higher revenues in our NGL Services segment reflecting increased product sales volumes and higher storage rates, slightly offset by lower revenue in our Gathering and Processing segment.

     The $0.4 million, or 4 percent, decrease in Operating and maintenance expense is due to the delay in the timing of cavern workovers in 2005.

     The $4.7 million increase in Product cost, from $1.4 million, is directly related to the increase in product sales volumes in our NGL Services segment.

     The $0.5 million, or 40 percent, increase in General and administrative expense is due primarily to an increase in allocated general and administrative expenses from Williams for personnel providing business development and accounting services to support the requirements of a growing public entity.

     The $1.8 million, or 52 percent, increase in Operating income is due primarily to higher storage revenues in our NGL Services segment, partially offset by lower revenues in our Gathering and Processing segment.

     The $0.4 million decrease in equity earnings from Discovery Producer Services LLC is discussed in detail in the “Results of Operations—Gathering and Processing” section.

Results of operations — Gathering and Processing

     The Gathering and Processing segment includes the Carbonate Trend gathering pipeline and our 40 percent ownership interest in Discovery.

		Three months ended								Six months ended
		June 30,								June 30,
		2005				2004				2005				2004
		(Thousands)
Segment revenues		$	765			$	2,049			$	1,645			$	3,215
Costs and expenses:
Operating and maintenance expense			269				149				376				262
Depreciation			300				300				600				600
Total costs and expenses			569				449				976				862
Segment operating income			196				1,600				669				2,353
Equity earnings			691				1,292				2,903				3,274
Segment profit		$	887			$	2,892			$	3,572			$	5,627

Carbonate Trend

Three months ended June 30, 2005 vs. three months ended June 30, 2004

     The $1.3 million, or 63 percent, decrease in Segment revenues is due primarily to:

	•		the absence of $950,000 of income from the settlement of a contractual volume deficiency provision recognized in 2004; and
	•		a 37 percent decline in gathering volumes causing a $0.3 million decrease in gathering revenue.

     The decline in gathering volumes is due primarily to normal reservoir depletion and reduced capacity experienced at an onshore treating plant in April 2005. During the second quarter of 2005, one of the existing wells was successfully reworked and daily gathered volumes increased to approximately 38,000 million British Thermal Units per day (MMBtu/day) prior to the shut down for Hurricane Katrina on August 27, 2005 (discussed earlier), a five percent increase from the second-quarter 2005 average daily gathered volume of approximately 36,000 MMBtu/d.

     The $120,000, or 81 percent, increase in Operating and maintenance expense is due primarily to costs incurred in 2005 to internally inspect the pipeline for corrosion. This inspection is conducted once every three years.

     The $1.4 million, or 88 percent, decrease in Segment operating income is due primarily to the lower revenues discussed above.

Six months ended June 30, 2005 vs. six months ended June 30, 2004

     The $1.6 million, or 49 percent, decrease in Segment revenues is due primarily to:

	•		the absence of $950,000 of income from the settlement of a contractual volume deficiency payment recognized in 2004; and
	•		a 34 percent decline in gathered volumes causing an $0.8 million decrease in gathering revenue;
	•		slightly offset by a 10 percent higher average gathering rate causing an $0.2 million increase in gathering revenue.

The volume decline is due primarily to normal reservoir depletion and reduced capacity experienced at an onshore treating plant in April, 2005. The increase in the average gathering rate was due to a customer’s annual election in 2005 under a bundled rate provision within its contract.

     The $114,000, or 44 percent, increase in Operating and maintenance expense is due primarily to the costs incurred to internally inspect the pipeline for corrosion.

     The $1.7 million, or 72 percent, decrease in Segment operating income is due primarily to the lower revenues discussed above.

Discovery Producer Services

     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 the Consolidated Statements of Operations. Due to the significance of Discovery’s equity earnings to our results of operations, the following discussion addresses in greater detail the results of operations for 100 percent of Discovery.

		Three months ended								Six months ended
		June 30,								June 30,
		2005				2004				2005				2004
		(Thousands)
Revenues		$	23,025			$	27,962			$	50,314			$	55,785
Costs and expenses, including interest:
Operating and maintenance expenses:
Fuel and shrink replacement			9,711				13,982				20,835				26,630
Other operating and maintenance			5,820				5,013				10,313				9,089
Depreciation and accretion			6,126				5,662				12,239				11,320
Interest income			(389	)			(140	)			(673	)			(192	)
Other expense, net			30				107				342				538
Total costs and expenses			21,298				24,624				43,056				47,385
Net income		$	1,727			$	3,338			$	7,258			$	8,400
Partnership’s 40 percent interest		$	691			$	1,335			$	2,903			$	3,360
Capitalized interest amortization			—				(43	)			—				(86	)
Equity earnings per our Consolidated Statements of Operations		$	691			$	1,292			$	2,903			$	3,274

Three months ended June 30, 2005 vs. three months ended June 30, 2004

     The $4.9 million, or 18 percent, decrease in Revenues is due primarily to lower fuel and shrink replacement gas sales volumes and transportation volumes, partially offset by higher per-unit NGL sales prices. The significant components of this decrease include the following.

•

Increasing natural gas prices during the second quarter of 2004 made it more economical for Discovery’s customers to bypass the processing plant rather than to process the gas, leaving Discovery with higher levels of excess fuel and replacement gas in the second quarter of 2004 than 2005. This excess natural gas was sold in the market and generated $7.3 million higher revenues in the second quarter of 2004.

	•		Fee-based revenues from gathering and transportation decreased $0.9 million due primarily to a 16 percent decline in the overall transportation volumes from the second quarter of 2004 to the second quarter of 2005. This decline resulted mainly from the high initial decline rate experienced by one of the larger newly connected fields and approximately 15,000 MMBtu/d lower volumes in June due to the reduction in gas flow volumes while the market expansion project connections were being made. This was somewhat offset by new volumes from the Front Runner, Rock Creek and Tarantula prospects.
	•		During the second quarter of 2005, two processing customers elected to have Discovery market their NGLs. Discovery sells these NGLs and distributes the proceeds to them less a marketing fee. The sales related to these two contracts generated an additional $2.1 million of revenue in the second quarter of 2005.
	•		NGL sales increased $1.2 million. This increase includes $1.6 million associated with 18 percent higher per-unit average NGL sales prices, slightly offset by $0.4 million from a four percent decrease in sales volumes.

     The $4.3 million, or 31 percent, decrease in Fuel and shrink replacement is due primarily to $7.2 million of higher costs related to the gas sales in 2004, partially offset by $2.1 million purchase costs for the two processing customers who elected to have Discovery market their NGLs and $0.8 million from 12 percent higher per-unit average natural gas prices.

     The $0.8 million, or 16 percent, increase in Other operating and maintenance is due primarily to:

	•		$0.2 million of computer support for the new digital control computer system for Larose and Paradis;
	•		$0.2 million higher management fees related to new facilities placed into service; and
	•		$0.2 million higher helicopter costs following the placement of the Front Runner project in-service.

     The $0.5 million, or eight percent, increase in Depreciation and accretion from the second quarter of 2004 is due primarily to the completion of a pipeline connection to the Front Runner prospect in late 2004.

     The $0.2 million, or 178 percent, increase in Interest income is due primarily to increasing interest-bearing cash balances during the 2005 period as additional cash flows from operations were retained.

     The $1.6 million, or 48 percent, decrease in Net income is due primarily to the $0.9 million lower fee-based revenues from gathering and transportation, $0.8 million higher Operating and maintenance expenses and $0.5 million higher Depreciation and accretion, slightly offset by $0.5 million higher fractionation revenues associated with higher fractionation volumes and $0.2 million higher Interest income.

Six months ended June 30, 2005 vs. six months ended June 30, 2004

     The $5.5 million, or 10 percent, decrease in Revenues is due primarily to lower fuel and shrink replacement gas sales volumes and transportation volumes, partially offset by higher per-unit NGL sales prices. The significant components of this decrease include the following.

	•		Increasing gas prices during the first half of 2004 made it more economical for Discovery’s customers to bypass the processing plant rather than to process the gas, leaving Discovery with higher levels of excess fuel and replacement gas in 2004 than 2005. This excess natural gas was sold in the market and generated $10.3 million higher revenues in the first half of 2004.
	•		Fee-based revenues from gathering and transportation decreased $2 million due primarily to a 19 percent decline in the overall transportation volumes from 2004 to 2005. This decline resulted mainly from the high initial decline rate experienced by one of the larger newly connected fields. This was somewhat offset by new volumes from the recently connected Front Runner, Rock Creek and Tarantula prospects.

	•		NGL sales increased $3.2 million. This increase includes $3.7 million associated with 18 percent higher average sales prices, slightly offset by $0.5 million from a two percent decrease in sales volumes.
	•		As disclosed previously, product sales increased by $2.1 million for the NGL sales related to two processing customers who elected to have Discovery market their NGLs for a fee under an option in their contracts.
	•		In 2005, Discovery received a $1.4 million volume threshold deficiency payment related to a volume shortfall under a transportation contract.

     The $5.8 million, or 22 percent, decrease in Fuel and shrink replacement is due primarily to $10 million of higher costs in 2004 related to gas sales, partially offset by $2.1 million of purchase costs for the two processing customers who elected to have Discovery market their NGLs and $2.1 million from 14 percent higher per-unit average natural gas prices.

     The $1.2 million, or 13 percent, increase in Other operating and maintenance is due primarily to:

	•		$0.4 million of computer support for the new digital control computer system;
	•		$0.3 million higher management fees related to new facilities placed into service;
	•		$0.1 million higher helicopter costs; and
	•		$0.2 million for higher power and fuel costs.

     The $0.9 million, or eight percent, increase in Depreciation and accretion from 2004 is due primarily to the completion of a pipeline connection to the Front Runner prospect in late 2004.

     The $0.5 million increase in Interest income, from $0.2 million, is due primarily to higher interest-bearing cash balances during 2005 as additional cash flows from operations were retained.

     The $1.1 million, or 14 percent, decrease in Net income is due primarily to the $2 million lower fee-based revenues from gathering and transportation, $1.2 million higher Operating and maintenance expenses, and $0.9 million higher Depreciation and accretion. Partially offsetting these decreases were the $1.4 million volume threshold deficiency payment received in 2005, $0.7 million higher fractionation revenues associated with higher fractionation volumes, $1 million higher gross processing margins, and $0.5 million higher Interest income.

Outlook

     We currently estimate that we will incur $3.4 million to $4.6 million of incremental maintenance expenditures in the next 12 months for restoration activities related to the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004. In an omnibus agreement entered into in connection with the closing of our initial public offering, Williams agreed to reimburse us for the cost of these restoration activities. In connection with these restoration activities, the Carbonate Trend pipeline may experience a temporary shut down. We estimate that this shut down could reduce our cash flows from operations by approximately $200,000 to $300,000.

     On August 29, 2005, Hurricane Katrina struck the Gulf Coast area. In anticipation of the hurricane the Discovery and Carbonate Trend assets were temporarily shut down on August 27, 2005. The Discovery and Carbonate Trend assets were off-line for 13 and 10 days, respectively. Both assets have returned to service at reduced throughput rates as producers and downstream facilities restore their operations. As of this filing, we estimate the unfavorable impact of this hurricane on the operating income of this segment to be between $1 million and $1.5 million.

     Following Hurricane Katrina, Discovery’s Larose plant was one of the first large-scale gas processing facilities to return to service in this area of Louisiana. As a result, we expect that Discovery’s processing throughput may temporarily increase as natural gas that is normally processed at other plants is diverted to the Larose facility.

     Throughput volumes on Discovery’s pipeline system and our Carbonate Trend pipeline are an important component of maximizing our profitability. Pipeline throughput volumes from existing wells connected to our 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, we and Discovery must continually obtain new supplies of natural gas.

	•		We anticipate recompletions and workovers to partially offset production declines from the wells currently connected to the Carbonate Trend pipeline.
	•		With the current oil and gas price environment, drilling activity across the shelf and the deepwater of the Gulf of Mexico has been robust. However, the availability of specialized rigs necessary to drill in the deepwater areas, such as those in and around Discovery’s gathering areas, limits producers’ ability 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.
	•		We expect continued growth in the average volumes of natural gas gathered by Discovery attributable to new production from the Front Runner, Rock Creek and Tarantula prospects, which we expect to offset declines in production from existing connected wells.
	•		Late in the fourth quarter of 2005, Discovery expects to connect a new well with an estimated initial volume of 35,000MMBtu/d. Capital to connect this new well will be provided by others.
	•		As previously discussed, In July 2005, Discovery executed an agreement with three producers to construct an approximately 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. In late August 2005, the Tahiti producers formally decided to proceed with the project. The Tahiti pipeline lateral expansion is expected to have a design capacity of approximately 200 million cubic feet per day, and its anticipated completion date is May 1, 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								Six months ended
		June 30,								June 30,
		2005				2004				2005				2004
						(Thousands)
Segment revenues		$	11,411			$	6,994			$	21,900			$	13,781
Costs and expenses:
Operating and maintenance expense			2,523				6,148				8,144				8,645
Product cost			3,327				334				6,062				1,371
Depreciation			593				609				1,198				1,178
General and administrative expense — direct			271				122				474				258
Taxes other than income			146				179				338				358
Total costs and expenses			6,860				7,392				16,216				11,810
Segment profit (loss)		$	4,551			$	(398	)		$	5,684			$	1,971

Three months ended June 30, 2005 vs. three months ended June 30, 2004

     The $4.4 million, or 63 percent, increase in Segment revenues is due primarily to higher product sales and storage revenues. The significant components of the increase include the following.

•

Product sales increased $3.2 million due primarily to the sale of surplus propane volumes created through our product optimization activities. We actively manage the fractionation process to optimize the resulting mix of products. This increase was offset by the related increase in Product cost.

	•		Storage revenue increased $0.8 million due to higher contracted storage volumes and slightly higher average per-unit storage rates. Volumes in the second quarter of 2004 were initially lower due to the 67 percent increase in the one-year storage rate on April 1, 2004 primarily reflecting the pass through of increased costs to comply with Kansas Department of Health and Environment (“KDHE”) regulations. Subsequently, the volumes returned to more normal levels.
	•		The $0.2 million increase in fractionation revenue is due to a ten percent increase in the per-unit fractionation rate for increases in fuel costs.

     The $3 million increase in Product cost, from $0.3 million, is directly related to the sale of surplus propane volumes created through our product optimization activities.

     The $3.6 million, or 59 percent, decrease in Operating and maintenance expense is due primarily to the difference in gains and losses experienced when draining caverns between the periods and a delay in the timing of cavern workovers this year. The significant components of the decrease consisted of the following.

	•		Other operating expense decreased $2.3 million due primarily to (a) the $1.2 million difference between a $0.7 million gain experienced when draining a cavern in 2005 and a $0.5 million loss experienced in 2004, (b) $0.5 million from a larger lower of cost or market inventory adjustment recorded in the second quarter of 2004 as compared to 2005 and (c) $0.4 million from higher blending gains at the Conway fractionator in 2005.
	•		Outside services decreased $1.1 million due to fewer cavern workovers in 2005 as compared to 2004. It is expected that these workovers will be completed in the last half of 2005.
	•		A $0.5 million reduction of our estimated asset retirement obligation for the storage caverns.
	•		Fuel and power costs increased $0.4 million due to a 14 percent increase in the average per-unit price of natural gas.

     The $4.9 million improvement in Segment profit (loss), from a $0.4 million loss in 2004, is due primarily to the $3.6 million lower Operating and maintenance expense and $0.8 million higher storage revenue.

Six months ended June 30, 2005 vs. six months ended June 30, 2004

     The $8.1 million, or 59 percent, increase in Segment revenues is due primarily to higher product sales and storage revenues. The significant components of the increase include the following.

	•		Product sales were $5 million higher due primarily to the sale of surplus propane volumes created through our product optimization activities. This increase was offset by the related increase in Product cost.
	•		Storage revenues increased $2.1 million due primarily to higher average per-unit storage rates for the first quarter of 2005 and higher storage volumes in the second quarter of 2005. The published rate for one-year storage contracts increased 67 percent on April 1, 2004, primarily reflecting the pass through of increased costs to comply with KDHE regulations. The storage volumes in the second quarter of 2004 initially declined due to these higher storage rates. Subsequently, the volumes returned to more normal levels.
	•		Fractionation revenues increased $0.6 million due to higher volumes in the first quarter and a ten percent increase in the average fractionation rate.
	•		During the second quarter of 2004, we began offering product upgrading services for normal butane at our fractionator. Other storage revenues increased $0.4 million due primarily to this new service in the first half of 2005.

     The $4.7 million increase in Product cost, from $1.4 million, is directly related to the sale of surplus propane volumes created through our product optimization activities.

     The $0.5 million, or six percent, decrease in Operating and maintenance expense is due primarily to a delay in beginning the cavern workovers this year and an adjustment of our asset retirement obligation, partially offset by higher fuel and power costs. The significant components of the decrease include the following.

	•		Outside services decreased by $1.1 million due to fewer cavern workovers in early 2005 as compared to 2004. It is expected that these workovers will be completed in the last half of 2005.
	•		A $0.5 million reduction of our estimated asset retirement obligation for the storage caverns.
	•		Fuel and power costs increased $0.8 million due to a 12 percent increase in the average per-unit price for natural gas and 13 percent higher fractionation volumes.
	•		Other operating expenses increased $0.3 million primarily for the differences between gains and losses experienced from cavern drains in the first and second quarter of 2004 as compared to 2005.

     Segment profit increased $3.7 million, from $2.0 million, due primarily to the $2.1 million higher storage revenues, $0.6 higher fractionation revenues, and $0.5 million lower operating and maintenance expense.

Outlook

	•		We expect volumes fractionated for our customers at the Conway fractionator to meet or exceed volumes from last year. Currently, commodity values in the Mid-Continent remain strong which minimizes the potential for volumes to be directed to the Mont Belvieu market.
	•		We expect storage revenues at the Conway storage facilities to exceed storage revenues from last year due to an increase in the demand for short-term storage leases at the facility. As of the date of this filing, new short-term storage leases totaling $1.5 million have been entered during the third quarter of 2005.
	•		We expect outside service costs to increase over the prior year due to the large number of cavern workovers planned for the third and fourth quarters of 2005. We expect outside service costs to continue near these levels through 2006 and 2007 to ensure we meet the regulatory compliance requirement to complete cavern workovers by 2008.
	•		Due to high demethanized mix inventories at the Conway fractionator, the planned November fractionator shutdown for scheduled maintenance may be deferred until spring 2006.

Financial condition and liquidity

Liquidity and Capital Resources — Williams Partners L.P.

     Historically, our sources of liquidity included cash generated from operations and funding from Williams. As of June 30, 2005, our cash receipts are deposited in Williams’ bank accounts and all cash disbursements were made from these accounts. Thus, historically our financial statements have reflected no cash balances. Cash transactions handled by Williams for us were reflected in affiliate advances between Williams and us. In August 2005, we established our own bank accounts; however, we will continue to utilize Williams’ personnel to manage our cash and investments.

     In addition to the retention of $37.2 million from the proceeds of our IPO, we expect our ongoing sources of liquidity to include cash generated from operations, cash distributions from Discovery, borrowings under Williams’ credit facility up to our borrowing limit ($75 million), borrowings under our $20 million working capital facility with Williams, issuance of additional partnership units, debt offerings, and capital contributions from Williams. Capital contributions from Williams required under the omnibus agreement consist of the following.

	•		Indemnification of environmental and related expenditures for a period of three years (for certain of those expenditures) up to $14 million, which includes between $3.4 million and $4.6 million for the restoration activities due to the partial erosion of the Carbonate Trend pipeline overburden by Hurricane Ivan, approximately $3.1 million for capital expenditures related to KDHE-related cavern compliance at our Conway storage facilities, and approximately $1 million for our 40 percent 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 $3.9 million in 2005 ($1.4 million pro rated for the portion of the year from August 23 to December 31), $3.2 million in 2006, $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 percent share of the expected total cost of the Tahiti pipeline lateral expansion project in excess of the amount of the required escrow deposit ($24.4 million) attributable to our 40 percent interest in Discovery.
	•		Reimbursement of our 40 percent share of any amounts the Federal Energy Regulatory Commission requires Discovery to refund to shippers for retained gas gains or over-recovery of lost and unaccounted for gas in excess of $4 million.

     We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements, capital contribution obligations to Discovery and expected quarterly cash distributions.

     The natural gas gathering, 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 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.

Discussed below are our significant expected capital requirements.

	•		We expect the total cost to Discovery of the Tahiti pipeline lateral expansion project will be approximately $69.5 million. Our 40 percent share of this project will be approximately $27.8 million. In September 2005, Discovery established an escrow account to cover a substantial portion of the total expenditures attributable to Williams’ and our share of those costs. We retained $24.4 million from the proceeds of our IPO to make this initial capital contribution to Discovery to fund our $24.4 million share of the payment into the escrow account. We expect this project to be completed by May 2007.
	•		We require cash in order to provide services to our storage customers who prepaid their annual storage contracts in April 2005. The storage year for customer contracts at our Conway storage facility runs from April 1 of a year to March 31 of the following year. We typically receive payment for these one-year contracts in advance in April after the beginning of the storage year and recognize the associated revenue over the course of the storage year. As of June 30, 2005, our deferred storage revenue is approximately $7.4 million. We retained a portion of the proceeds from our IPO for working capital purposes associated with this deferred revenue.
	•		We expect to make minimum quarterly distributions of $5 million ($0.35 per common and subordinated unit and a two percent payment on the general partner interest) to our unitholders and our general partner to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Our expected distribution for the third quarter of 2005 will be pro rated for the period from August 23 through September 30, 2005.

•

Maintenance capital expenditures for Conway assets are estimated to be approximately $4 million for 2005, of which approximately $679,000 has been spent through June 30, 2005. The amount of estimated maintenance capital expenditures for the Conway assets includes approximately $1.9 million to be spent in connection with the installation of wellhead control equipment and well meters and KDHE-related cavern compliance costs. In the omnibus agreement, Williams agreed to reimburse us for the cost of these expenditures as previously discussed.

Liquidity and Capital Resources — Discovery

     Historically, cash distributions by Discovery to its members required unanimous consent and no such distributions were made. Discovery’s limited liability company agreement was amended at the closing of the IPO to provide for quarterly distributions of available cash. We expect Discovery’s future cash requirements for working capital and maintenance capital expenditures to be funded from its cash on hand and from its internally generated cash flows from operations. We expect capital expenditures for future growth or expansion for Discovery to be funded by cash calls to its members (which require unanimous consent of the members except in limited circumstances), from proceeds from the issuance of debt or from internally generated funds.

     As disclosed previously, Discovery historically retained all its cash generated from operations. All this retained cash is associated with Discovery’s operations prior to our IPO. Discovery made a distribution of approximately $43.8 million on August 22, 2005 to its existing members, representing about 75 percent of this retained cash. We did not receive any portion of this distribution. After this distribution, Discovery has approximately $15.3 million of cash on hand which it will use to fund certain expected or potential expenditures. The amount retained by Discovery will be used to fund potential shipper refunds that may be required by the Federal Energy Regulatory Commission for retained system gas gains and the over-recovery of lost and unaccounted-for gas up to $4 million, $1 million of compressor modifications at the Larose gas processing plant, and working capital needs. As discussed above, the omnibus agreement provides for reimbursement by Williams for our share of any required capital contributions to Discovery related to the Federal Energy Regulatory Commission ordered refunds to shippers for retained gas gains or over-recovery of lost and unaccounted for gas in excess of $4 million. Prospectively, Discovery expects to make quarterly distributions of available cash to its members instead of retaining all cash from operations.

     In July, 2005, Discovery entered into an agreement for the construction of the Tahiti pipeline lateral expansion project. Total construction costs of this project are expected to be approximately $69.5 million and will be funded by contributions from Discovery’s members, including us. In September 2005, we and Williams made contributions totaling $40.7 million to Discovery covering a substantial portion of the total expenditures attributable to Williams’ and our share of these costs. Discovery deposited this $40.7 million into an escrow account that is restricted for use on this project.

Cash Flows and Capital Expenditures — Williams Partners L.P.

		Six months ended
		June 30,
		2005				2004
		(Thousands)
Net cash provided by operating activities		$	3,677			$	6,999
Net cash used by investing activities			(679	)			(368	)
Net cash used by financing activities			(2,998	)			(6,631	)

     The decrease of $3.3 million in Net cash provided by operating activities for the first six months of 2005 as compared to the first six months of 2004 is due primarily to a $5.4 million reduction of cash flows from changes in working capital, partially offset by $1.8 million higher operating income from the Conway and Carbonate Trend assets in 2005 as compared to 2004. Cash flows from changes in Accounts payable decreased $2.7 million related mainly to the $1.6 million payment for the December 2004 spot ethane purchases and $1 million higher December 2004 fuel costs paid in the first quarter of 2005. Cash flows from changes in Deferred revenue decreased $2.2 million due primarily to a long-term storage customer changing from an annual to a quarterly payment schedule ($3.7 million), which was partially offset by new storage contracts in 2005 and late renewals of some of our storage contracts in 2004 as noted above in “Results of operations—NGL Services.”

     Net cash used by investing activities in the first six months of 2005 and 2004 was for maintenance capital expenditures in our NGL Services segment. Net cash used by financing activities represents the pass through of our net cash flows to Williams under its cash management program. Following the closing of our IPO on August 23, 2005, we no longer participate in Williams’ cash management program, and our net cash flows will no longer pass through to Williams.

     Subsequent to the closing of our IPO, our cash flows from operations are favorably impacted by the effects of a gas purchase contract transferred to us by Williams in connection with the IPO. This contract is intended to mitigate the fuel price risk under one of our fractionation contracts that 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 contract is for the purchase of a sufficient quantity of natural gas from a wholly owned subsidiary of Williams at a price not to exceed a specified price to satisfy our fuel requirements under this fractionation contract. The fair value of this gas purchase contract was an equity contribution to us by Williams. This gas purchase contract will terminate on December 31, 2007. Our annual fuel expense will not be significantly impacted because of the monthly amortization of the related asset. However, this contract will reduce our annual cash outflows for fuel by approximately $3 million to $5 million.

Cash Flows and Capital Expenditures — Discovery

     As previously disclosed, cash distributions from Discovery will be a significant source of our liquidity. Due to the significance of Discovery’s cash flows to our ability to make cash distributions, the following discussion addresses in greater detail the cash flow activities for 100 percent of Discovery for the six months ended June 30, 2005 and 2004.

		Six months ended
		June 30,
		2005				2004
		(Thousands)
Operating Activities:
Net income		$	7,258			$	8,400
Adjustments to reconcile to cash provided by operations:
Depreciation and accretion			12,239				11,320
Cash provided (used) by changes in assets and liabilities:
Accounts receivable			120				(796	)
Inventory			311				(21	)
Other current assets			990				873
Accounts payable			(2,791	)			378
Other current liabilities			(947	)			(1,429	)
Accrued liabilities			37				1,970
Net cash provided by operating activities		$	17,217			$	20,695
Investing Activities:
Capital expenditures		$	(7,434	)		$	(27,289	)
Change in accounts payable — capital expenditures			(9,874	)			3,646
Net cash used by investing activities		$	(17,308	)		$	(23,643	)

     Net cash provided by operating activities decreased $3.5 million for the first six months of 2005 as compared to the first six months of 2004 due primarily to a $3.3 million reduction of cash flows from changes in working capital. Cash flows from changes in accounts payable decreased $3.2 million related mainly to $3.5 million higher payments for December 2004 shrink replacement gas costs in 2005. During the first six months of 2004, accrued liabilities increased $2 million for potential shipper refunds that may be required by the Federal Energy Regulatory Commission for retained system gas gains and the over-recovery of lost and unaccounted-for gas at Discovery.

     During 2005, Net cash used by investing activities was primarily for the completion of Discovery’s market expansion project and $1.7 million for the purchase of leased compressors at the Larose processing plant. During 2004, Net cash used by investing activities was primarily for the construction of a gathering lateral to connect Discovery’s pipeline system to the Front Runner prospect.

     Discovery had no cash flows from financing activities during the six months ended June 30, 2005 and 2004.

Contractual Cash Obligations — Williams Partners L.P.

     As of June 30, 2005, we have an approximately $183 million unsecured promissory note agreement from Williams. The advances are due upon demand; however, Williams has not historically required repayment. Prior to the closing of our IPO on August 23, 2005, these advances were forgiven by Williams. Accordingly, the advances will be reflected as Partners’ capital on that date.

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 risk to which we are exposed is commodity price risk for natural gas and natural gas liquids (“NGLs”). We are also exposed to the risk of interest rate fluctuations. Our future borrowings will bear interest at variable market based rates.

Commodity Price Risk

     Certain of Discovery’s contracts, including percent-of-liquids contracts and keep-whole processing arrangements, 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 Discovery’s services in the future. Carbonate Trend 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. We and Discovery do not currently use derivatives to manage the risks associated with these price fluctuations.

Interest Rate Risk

     We previously had interest rate exposure related to our advances from Williams. These advances were due on demand. However, as previously discussed, prior to the closing of our IPO on August 23, 2005, these advances were forgiven by Williams.

Item 4. 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 partnership 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.

     There were no changes in our internal controls over financial reporting that occurred during the fiscal quarter ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II— OTHER INFORMATION

Item 1. Legal Proceedings

     The information required for this item is provided in Note 6, 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 2. Unregistered Sales of Equity Securities and Use of Proceeds

Use of Proceeds

     On August 17, 2005, we commenced an IPO of common units representing limited partner interests pursuant to a registration statement on Form S-1 (SEC File No. 333-124517) that was declared effective on August 11, 2005. The managing underwriters included Lehman Brothers Inc., Citigroup Global Markets Inc., RBC Capital Markets Corporation and Wachovia Capital Markets, LLC. Our sale of 5,000,000 registered common units at $21.50 per common unit was completed on August 23, 2005. In addition, on August 23, 2005, 750,000 common units were sold by subsidiaries of Williams as selling unitholders pursuant to the exercise of the underwriters’ over-allotment option.

						Aggregate Offering Price of
		Amount of Common Units				Common Units Registered
		Registered and Sold				and Sold
Williams Partners L.P.			5,000,000			$	107,500,000
Williams Energy Services, LLC*			95,084				2,044,306
Williams Energy, L.L.C.*			268,385				5,770,277.5
Williams Discovery Pipeline LLC*			129,587				2,786,120.5
Williams Partners Holdings LLC*			256,944				5,524,296
Total			5,750,000			$	123,625,000

     Discounts paid by us to the underwriters amounted to $6,850,000. After discounts paid to underwriters, we received $100,650,000 in proceeds from the sale of the common units. We did not receive any proceeds from the common units sold by the selling unitholders. Set forth below are the expenses (other than underwriting discounts and structuring fee) expected to be incurred in connection with the issuance and distribution of the common units. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE filing fee, the amounts set forth below are estimates.

SEC registration fee		$	14,554
NASD filing fee			12,575
NYSE listing fee			150,000
Printing and engraving expenses			846,580
Accounting fees and expenses			1,453,420
Tax planning expenses			250,000
Legal fees and expenses			1,890,000
Blue sky fees and expenses (including legal fees)			5,000
Transfer agent and registrar fees			5,000
Miscellaneous			3,209
Total		$	4,630,338

     In addition, we paid the representative of the underwriters a structuring fee of $403,125 for evaluation, analysis and structuring of our partnership. The underwriters reimbursed us $268,750 for certain of our expenses incurred in connection with the offering of the common units. The expenses of the offering that are payable by us are estimated to be approximately $4,361,588 (exclusive of underwriting discounts and the structuring fee, but net of the reimbursement received from the underwriters for certain expenses).

     Our net proceeds from the offering are estimated to be approximately $95.9 million and have been used as follows:

	•		$58.7 million was distributed to affiliates of The Williams Companies, Inc., the parent of our general partner, in part to reimburse Williams for capital expenditures relating to the assets contributed to us and for a gas purchase contract contributed to us;
	•		$24.4 million was used to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project; and
	•		$12.8 million was used for additional working capital.

Item 5. Other Information.

     On September 16, 2005, Ms. Alice M. Peterson was elected to serve as a director of our general partner. Ms. Peterson will join Mr. Bill Z. Parker as a member of the audit, compensation and conflicts committees of the board of directors of our general partner.

     There is no arrangement or understanding between Ms. Peterson and any other persons pursuant to which she was selected as a director. There are no relationships between Ms. Peterson and us that would require disclosure pursuant to Item 404(a) of Regulation S-K.

     Also on September 16, 2005, Mr. Ted T. Timmermans, age 48, was appointed vice president, chief accounting officer and controller of our general partner. Since July 2005, Mr. Timmermans has served as vice president, chief accounting officer and controller of Williams. Previously, Mr. Timmermans was assistant controller for Williams with responsibilities for SEC financial reporting and providing financial consulting to Williams’ business units.

Item 6. Exhibits.

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

		*Exhibit 3.1 – Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (attached as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
		*Exhibit 3.2 – Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (attached as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).

		*Exhibit 10.1 – Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (attached as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
		*Exhibit 10.2 – Williams Partners GP LLC Long-Term Incentive Plan (attached as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
		*Exhibit 10.3 – Contribution, Conveyance and Assumption Agreement, dated August 23, 2005, by and among Williams Partners L.P., Williams Energy, L.L.C., Williams Partners GP LLC, Williams Partners Operating LLC, Williams Energy Services, LLC, Williams Discovery Pipeline LLC, Williams Partners Holdings LLC and Williams Natural Gas Liquids, Inc. (attached as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K filed with the Commission on August 26, 2005).
		*Exhibit 10.4 – Working Capital Loan Agreement, dated August 23, 2005, between The Williams Companies, Inc. and Williams Partners L.P. (attached as Exhibit 10.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
		*Exhibit 10.5 – Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and the Banks, Citibank, N.A. and Bank of America, N.A., and Citicorp USA, INC. as administrative agent (attached as Exhibit 1.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with the Commission on May 26, 2005).
		*Exhibit 10.6 – Third Amended and Restated Limited Liability Company Agreement for Discovery Producer Services LLC (attached as Exhibit 10.7 to Amendment No. 1 to Williams Partners L.P.’s Registration Statement on Form S-1 (File No. 333-124517) filed with the Commission).
		+Exhibit 10.7 – Base Contract for Sale and Purchase of Natural Gas between Williams Natural Gas Liquids, Inc. and Williams Power Company, Inc., dated August 15, 2005.
		+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.

 

*  Each such exhibit has heretofore been filed with the Commission as part of the filing indicated and is incorporated herein by reference.

+  Filed herewith.

SIGNATURE

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

		WILLIAMS PARTNERS L.P.
		By: Williams Partners GP LLC, its general partner
		/s/Ted T. Timmermans
		Ted. T. Timmermans
		Controller (Duly Authorized Officer and Chief Accounting Officer)
September 22, 2005

EXHIBIT INDEX

Exhibit Number				Description
3.1* –				Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (attached as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
3.2* –				Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (attached as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
10.1* –				Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (attached as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
10.2* –				Williams Partners GP LLC Long-Term Incentive Plan (attached as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
10.3* –				Contribution, Conveyance and Assumption Agreement, dated August 23, 2005, by and among Williams Partners L.P., Williams Energy, L.L.C., Williams Partners GP LLC, Williams Partners Operating LLC, Williams Energy Services, LLC, Williams Discovery Pipeline LLC, Williams Partners Holdings LLC and Williams Natural Gas Liquids, Inc. (attached as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K filed with the Commission on August 26, 2005).
10.4* –				Working Capital Loan Agreement, dated August 23, 2005, between The Williams Companies, Inc. and Williams Partners L.P. (attached as Exhibit 10.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the Commission on August 26, 2005).
10.5* –				Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and the Banks, Citibank, N.A. and Bank of America, N.A., and Citicorp USA, INC. as administrative agent (attached as Exhibit 1.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) filed with the Commission on May 26, 2005).
10.6* –				Third Amended and Restated Limited Liability Company Agreement for Discovery Producer Services LLC (attached as Exhibit 10.7 to Amendment No. 1 to Williams Partners L.P.’s Registration Statement on Form S-1 (File No. 333-124517) filed with the Commission).
10.7+ –				Base Contract for Sale and Purchase of Natural Gas between Williams Natural Gas Liquids, Inc. and Williams Power Company, Inc., dated August 15, 2005.
31.1+ –				Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2+ –				Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32+ –				Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.