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

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

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 October 31, 2005.

 

 

WILLIAMS PARTNERS L.P.
INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2005 and 2004			3
Consolidated Balance Sheets — September 30, 2005 and December 31, 2004			4
Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2005 and 2004			5
Consolidated Statement of Partners’ Capital from January 1, 2005 to September 30, 2005			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			16
Item 3. Quantitative and Qualitative Disclosures about Market Risk			32
Item 4. Controls and Procedures			32
Part II. Other Information
Item 1. Legal Proceedings			33
Item 6. Exhibits			33
Rule 13a-14(a)/15d-14(a) Certification of CEO
Rule 13a-14(a)/15d-14(a) Certification of CFO
Section 1350 Certifications of CEO & 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.
	•		Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.

	•		Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.
	•		Even if unitholders are dissatisfied, they 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.
	•		Lower natural gas liquids prices could adversely affect our fractionation and storage businesses.
	•		We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and natural gas liquids. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.
	•		If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and natural gas liquids or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

     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. Financial Statements.

WILLIAMS PARTNERS L.P.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Revenues:
Storage		$	5,409			$	4,165			$	14,435			$	11,075
Fractionation			2,386				2,414				7,123				6,544
Gathering			649				793				2,295				3,059
Product sales:
Affiliate			2,726				—				9,234				—
Third-party			—				1,976				63				3,536
Other			1,006				1,109				2,571				3,239
Total revenues			12,176				10,457				35,721				27,453
Costs and expenses:
Operating and maintenance expense:
Affiliate			2,592				2,554				7,938				7,247
Third-party			5,680				3,097				8,854				7,311
Product cost			2,258				1,445				8,320				2,816
Depreciation			896				918				2,694				2,696
General and administrative expense:
Affiliate			1,170				745				2,708				1,838
Third-party			385				18				431				56
Taxes other than income			194				179				532				537
Total costs and expenses			13,175				8,956				31,477				22,501
Operating income (loss)			(999	)			1,501				4,244				4,952
Equity earnings (loss) – Discovery Producer Services LLC			66				(90	)			2,969				3,184
Interest expense:
Affiliate			(1,822	)			(2,929	)			(7,439	)			(9,045	)
Third-party			(192	)			(166	)			(561	)			(331	)
Interest income			76				—				76				—
Net loss		$	(2,871	)		$	(1,684	)		$	(711	)		$	(1,240	)
Allocation of 2005 net loss:
Net loss		$	(2,871	)						$	(711	)
Net loss applicable to the period through August 22, 2005			(2,192	)							(32	)
Net loss applicable to the period August 23 through September 30, 2005			(679	)							(679	)
Allocation of Net loss to general partner			(423	)							(423	)
Allocation of Net loss to limited partners		$	(256	)						$	(256	)
Basic and diluted net loss per limited partner unit:
Common units		$	(0.02	)						$	(0.02	)
Subordinated units			(0.02	)							(0.02	)
Weighted average number of units outstanding:
Common units			7,000,000								7,000,000
Subordinated units			7,000,000								7,000,000

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		September 30,				December 31,
		2005				2004
		(Unaudited)
		(Thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	14,482			$	—
Accounts receivable:
Trade			1,444				2,150
Other			1,992				1,388
Gas purchase contract — affiliate			5,449				—
Other current assets			875				749
Total current assets			24,242				4,287
Investment in Discovery Producer Services LLC			146,146				147,281
Property, plant and equipment, net			67,042				67,793
Gas purchase contract - noncurrent - affiliate			6,076				—
Total assets		$	243,506			$	219,361
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable:
Trade		$	2,069			$	2,480
Affiliate			6,076				1,980
Product imbalance			4,736				1,071
Deferred revenue			6,876				3,305
Accrued liabilities:
Affiliate			512				317
Other			2,678				3,607
Total current liabilities			22,947				12,760
Advances from affiliate			—				186,024
Environmental remediation liabilities			3,964				3,909
Other noncurrent liabilities			187				—
Commitments and contingent liabilities (Note 7)
Partners’ capital			216,408				16,668
Total liabilities and partners’ capital		$	243,506			$	219,361

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		Nine Months Ended
		September 30,
		2005				2004
		(Thousands)
OPERATING ACTIVITIES:
Net loss		$	(711	)		$	(1,240	)
Adjustments to reconcile to cash provided by operations:
Depreciation			2,694				2,696
Amortization of gas purchase contract - affiliate			581				—
Undistributed earnings of Discovery Producer Services LLC			(2,969	)			(3,184	)
Cash provided (used) by changes in assets and liabilities:
Accounts receivable			(2,538	)			(91	)
Other current assets			(126	)			96
Accounts payable			3,685				779
Accrued liabilities			45				(65	)
Deferred revenue			3,571				4,114
Other, including changes in noncurrent liabilities			3,045				1,189
Net cash provided by operating activities			7,277				4,294
INVESTING ACTIVITIES:
Capital expenditures			(1,860	)			(635	)
Contribution to Discovery Producer Services LLC			(24,400	)			—
Net cash used by investing activities			(26,260	)			(635	)
FINANCING ACTIVITIES:
Proceeds from sale of common units			100,247				—
Payment of offering costs			(4,291	)			—
Distribution to The Williams Companies, Inc			(58,756	)			—
Changes in advances from affiliates – net			(3,735	)			(3,659	)
Net cash provided (used) by financing activities			33,465				(3,659	)
Increase in cash and cash equivalents			14,482				—
Cash and cash equivalents at beginning of period			—				—
Cash and cash equivalents at end of period		$	14,482			$	—

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.

		Number of Limited								Pre-IPO																Total
		Partner Units								Owner’s				Limited Partner								General				Partners’
		Common				Subordinated				Equity				Common				Subordinated				Partner				Capital
Balance - January 1, 2005			—				—			$	16,668			$	—			$	—			$	—			$	16,668
Accounts receivable not contributed			—				—				(2,640	)			—				—				—				(2,640	)
Net loss attributable to the period through August 22, 2005			—				—				(32	)			—				—				—				(32	)
			—				—				13,996				—				—				—				13,996
Contribution of net assets of predecessor companies			2,000,000				7,000,000				(13,996	)			10,416				106,372				4,343				107,135
Issuance of units to public			5,000,000				—				—				100,247				—				—				100,247
Offering costs			—				—				—				(4,291	)			—				—				(4,291	)
Net loss attributable to the period August 23, 2005 through September 30, 2005			—				—				—				(128	)			(128	)			(423	)			(679	)
Balance - September 30, 2005			7,000,000				7,000,000			$	—			$	106,244			$	106,244			$	3,920			$	216,408

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 (“Discovery”), 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; (2) the Carbonate Trend gathering pipeline off the coast of Alabama; (3) three integrated natural gas liquids (“NGL”) product storage facilities near Conway, Kansas; and (4) a 50 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 Discovery was held by Williams Energy, L.L.C. (“Energy”) and Williams Discovery Pipeline LLC (“Williams Pipeline”); 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 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, an operating limited liability company (wholly-owned by us) through which all our activities are conducted, was formed.

  Initial Public Offering and Related Transactions

     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 totaling $7.3 million, were used to:

	•		distribute $58.8 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 $12.7 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 September 30, 2005, and results of operations for the three months and nine months ended September 30, 2005 and 2004 and cash flows for the nine months ended September 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 Discovery 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 Discovery, which owns 100 percent of Discovery Gas Transmission LLC. 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.

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

Note 3. Allocation of Net Income and Distributions

     The allocation of net loss between our general partner and limited partners for the period August 23, 2005 through September 30, 2005 is as follows (in thousands):

Allocation of net loss to general partner:
Net loss for the period August 23, 2005 through September 30, 2005		$	(679	)
Charges direct to general partner:
Reimbursable general and administrative costs			417
Loss before direct charges to general partner			(262	)
General partner’s share of net loss			2.0	%
General partner’s allocated share of net loss before direct charges			(6	)
Direct charges to general partner			(417	)
Net loss allocated to general partner			(423	)
Net loss for the period August 23, 2005 through September 30, 2005			(679	)
Net loss allocated to general partner			(423	)
Net loss allocated to limited partners		$	(256	)

     On October 24, 2005, the board of directors of our general partner declared a cash distribution of $0.1484 per unit on our outstanding common and subordinated units. The distribution represents the $0.35 per unit minimum quarterly distribution pro-rated for the 39-day period following the IPO closing date (August 23, 2005 through September 30, 2005). The $2.1 million distribution will be paid on November 14, 2005 to our general partner and unitholders of record at the close of business on November 7, 2005.

Note 4. 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 the operations employees and certain general and administrative 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 expense — Affiliate in the accompanying Consolidated Statements of Operations. In 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 a quarterly credit for general and administrative expenses under the terms of an omnibus agreement. The annual amounts of those 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.

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

     At September 30, 2005, we have a contribution receivable from our general partner of $0.6 million including $417,000 for the third-quarter 2005 general and administrative expense credit and other items provided for in the omnibus agreement, which is netted against Partners’ capital on the Consolidated Balance Sheets.

     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. The carrying value of this contract is reflected as Gas purchase contract — affiliate and Gas purchase contract — noncurrent — affiliate on the Consolidated Balance Sheets.

     In December 2004, we began selling surplus propane and other 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. Correspondingly, we purchase ethane and other NGLs from Power to replenish deficit product positions. 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, fuel purchases from Power and NGL purchases from Power for the periods stated is as follows:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
		(Thousands)
General and administrative expense, including amounts subsequently charged to co-owners:
Allocated		$	971			$	718			$	2,229			$	1,734
Directly charged			275				100				703				321
Operating and maintenance expense, including amounts subsequently charged to co-owners:
Fuel purchases			5,911				4,503				15,711				12,198
Salaries and benefits			886				855				2,546				2,609
NGL purchases			2,500				—				6,363				—

     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 historically participated in Williams’ cash management program; thus, we carried no cash balance on our Consolidated Balance Sheet at December 31, 2004. Effective with the IPO, we began maintaining our own bank accounts but continue to utilize Williams’ personnel to manage our cash and investments. As of December 31, 2004, our net Advances from affiliate consisted of an unsecured promissory note agreement with Williams for both advances to and from Williams. The advances were due on demand; however, Williams did not historically require

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

repayment. Therefore, Advances from affiliate at December 31, 2004 were 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 was transferred to 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 7.373 percent at December 31, 2004.

Note 5. Investment in Discovery Producer Services LLC

     Our 40 percent investment in Discovery is accounted for using the equity method of accounting. At September 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 of 2005.

     On August 22, 2005, Discovery made a distribution of approximately $43.8 million to Williams and the other member of Discovery. This distribution was associated with Discovery’s operations prior to the IPO; hence, we did not receive any portion of this distribution. The distribution resulted 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 $17.5 million during the third quarter of 2005.

     In September 2005, we made a $24.4 million capital contribution to Discovery for a substantial portion of our share of the estimated future capital expenditures for the Tahiti pipeline lateral expansion project.

     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.

     In October 2005, a non-affiliated member of Discovery exercised its option to acquire a 6.67 percent interest in Discovery from Energy. The exercise of this option had no impact on us. Although after the exercise of this option, we and Williams hold a 60 percent interest in Discovery on a combined basis, the voting provisions of Discovery’s limited liability company agreement give the other member of Discovery significant participatory rights such that we and Williams do not control Discovery.

     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).

		September 30,				December 31,
		2005				2004
		(unaudited)
Current assets		$	31,913			$	67,534
Noncurrent restricted cash and cash equivalents			45,501				—
Property, plant and equipment			347,414				356,385
Current liabilities			(20,453	)			(31,572	)
Non-current liabilities			(770	)			(702	)
Members’ capital		$	403,605			$	391,645

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
		(unaudited)
Revenues		$	19,100			$	20,947			$	69,414			$	76,732
Costs and expenses			19,432				21,216				63,161				68,793
Interest income			(498	)			(153	)			(1,171	)			(345	)
Net income (loss)		$	166			$	(116	)		$	7,424			$	8,284

Note 6. 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 September 30, 2005, letters of credit totaling $713 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 is 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 are also required to pay or reimburse Williams for a commitment fee based on the unused portion of its $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 after March 31, 2005 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 mature on May 3, 2007 and bear interest at the same rate as for borrowings under the Williams facility described above. We 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 7. 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 this project management and soil and groundwater monitoring associated with the four remediation projects at the Conway storage facilities and for which we will not be indemnified will be approximately $200,000 to $400,000 per year following the completion of the remediation work.

     At September 30, 2005, we had accrued liabilities totaling $5.5 million for these costs. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by KDHE and other governmental authorities and other factors.

     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 8. Segment Disclosures

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

     The following table reflects total assets by reporting segment.

		September 30,				December 31,
		2005				2004
		(Thousands)
Segment assets:
Gathering & Processing		$	165,147			$	166,985
NGL Services			66,158				52,376
Unallocated partnership assets			15,269				—
Eliminations			(3,068	)			—
Total assets		$	243,506			$	219,361

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

		Gathering &				NGL
		Processing				Services				Total
						(Thousands)
Three months ended September 30, 2005:
Segment revenues		$	650			$	11,526			$	12,176
Operating and maintenance expense			101				8,171				8,272
Product cost			—				2,258				2,258
Depreciation			300				596				896
Direct general and administrative expense			—				308				308
Other			—				194				194
Segment operating income (loss)			249				(1	)			248
Equity earnings			66				—				66
Segment profit (loss)		$	315			$	(1	)		$	314
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	248
Allocated general and administrative expense											(1,247	)
Combined operating loss										$	(999	)
Three months ended September 30, 2004:
Segment revenues		$	794			$	9,663			$	10,457
Operating and maintenance expense			142				5,509				5,651
Product cost			—				1,445				1,445
Depreciation			300				618				918
Direct general and administrative expense			—				118				118
Other			—				179				179
Segment operating income			352				1,794				2,146
Equity loss			(90	)			—				(90	)
Segment profit		$	262			$	1,794			$	2,056
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	2,146
Allocated general and administrative expense											(645	)
Combined operating income										$	1,501

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

		Gathering &				NGL
		Processing				Services				Total
						(Thousands)
Nine months ended September 30, 2005:
Segment revenues		$	2,295			$	33,426			$	35,721
Operating and maintenance expense			477				16,315				16,792
Product cost			—				8,320				8,320
Depreciation			900				1,794				2,694
Direct general and administrative expense			—				782				782
Other			—				532				532
Segment operating income			918				5,683				6,601
Equity earnings			2,969				—				2,969
Segment profit		$	3,887			$	5,683			$	9,570
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	6,601
Allocated general and administrative expense											(2,357	)
Combined operating income										$	4,244
Nine months ended September 30, 2004:
Segment revenues		$	4,009			$	23,444			$	27,453
Operating and maintenance expense			404				14,154				14,558
Product cost			—				2,816				2,816
Depreciation			900				1,796				2,696
Direct general and administrative expense			—				376				376
Other			—				537				537
Segment operating income			2,705				3,765				6,470
Equity earnings			3,184				—				3,184
Segment profit		$	5,889			$	3,765			$	9,654
Reconciliation to the Consolidated Statements of Operations:
Segment operating income										$	6,470
Allocated general and administrative expense											(1,518	)
Combined operating income										$	4,952

Note 9. 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.” This 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.

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 in Item 1 of 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 $58.8 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 $12.7 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.

     Prior to the closing of our IPO, our assets were held by wholly-owned subsidiaries of Williams. Upon the closing of our IPO, these Williams’ subsidiaries transferred the assets and the related liabilities to us. The following discussion includes the historical period prior to the closing of our IPO.

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 off the coast of Alabama. Discovery owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and an NGL fractionator in Louisiana. These assets generate revenues by providing natural gas gathering, transporting and processing services and integrated NGL fractionating services to customers under a range of contractual arrangements. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such.
	•		NGL Services. Our NGL Services segment includes three NGL storage facilities and a 50 percent undivided interest in a fractionator near Conway, Kansas. These assets generate revenues by providing stand-alone NGL fractionation and storage services using various fee-based contractual arrangements where we receive a fee or fees based on actual or contracted volumetric measures.

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, we made a $24.4 million

contribution to Discovery to cover a substantial portion of the total expenditures attributable to our share of these costs. We funded this contribution with proceeds from our IPO.

     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 assets were off-line for six days and then continued to experience lower throughput rates until being temporarily shut down for Hurricane Rita on September 21, 2005. The Carbonate Trend assets were off-line for 10 days and then experienced a gradual return to pre-hurricane throughput rates by September 19, 2005. We estimate the unfavorable impact of this hurricane on our third-quarter net income was approximately $0.7 million. This estimate includes $0.1 million for expenses and an estimated $0.6 million in lost revenue due to decreased throughput volumes.

     On September 24, 2005, Hurricane Rita struck the Gulf Coast area. In anticipation of the hurricane, the Discovery assets, which were already at reduced throughput from Hurricane Katrina, were temporarily shut down on September 21, 2005. The Discovery assets were off-line for seven days and then continued to experience lower throughput rates through the end of the third quarter. We estimate the unfavorable impact of this hurricane on our third-quarter net income was approximately $0.3 million in lost revenue due to decreased throughput volumes.

     As of October 21, 2005, gathering volumes for Discovery were approximately 376,000 million British Thermal Units per day (“MMBtu/d”) and exceeded levels experienced prior to hurricanes Katrina and Rita. This volume includes approximately 77,000 MMBtu/d from multiple customers whose gas is normally processed at another plant that was severely damaged by Hurricane Katrina.

     In October 2005, Discovery conducted two expedited open seasons for firm transportation to provide outlets for natural gas that has been stranded following damage to third-party facilities during hurricanes Katrina and Rita. Both of these open seasons were for up to 250,000 MMBtu/d. The first of these includes the construction of a new receipt point at Texas Eastern Transmission Company’s Larose compressor station in Lafourche Parish, Louisiana. The second is via an existing interconnection to Tennessee Gas Pipeline’s Line 500 in Terrebonne Parish, Louisiana. We expect to begin receiving additional incremental volumes from these receipt points by December 2005 and anticipate continued throughput for the subsequent three to six months. Shippers will reimburse Discovery for all capital necessary to establish these connections.

     We and Williams have identified Williams’ existing gathering and processing assets in the Four Corners area as the initial asset that we would acquire. We plan to acquire an approximately 25 percent interest in the Four Corners assets. On a 100 percent basis, the unaudited operating income plus depreciation from these assets has been $154 million, $151 million and $165 million for 2002, 2003 and 2004, respectively. The same measure for the first nine months of 2005 is $136 million. The terms of this proposed transaction, including price, will be subject to the approval of the boards of directors of both our general partner and Williams. Assuming such approvals are obtained, we expect that this transaction would be completed during the second quarter of 2006.

Results of operations

Consolidated Overview

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

		Three months ended September 30,												Nine months ended September 30,
										% Change												% Change
		2005				2004				from 2004 (1)				2005				2004				from 2004 (1)
		(Thousands)												(Thousands)
Revenues		$	12,176			$	10,457				+16%			$	35,721			$	27,453				+30%
Costs and expenses:
Operating and maintenance expense			8,272				5,651				-46%				16,792				14,558				-15%
Product cost			2,258				1,445				-56%				8,320				2,816				-195%
Depreciation			896				918				+2%				2,694				2,696				—
General and administrative expense			1,555				763				-104%				3,139				1,894				-66%
Taxes other than income			194				179				-8%				532				537				+1%
Total costs and expenses			13,175				8,956				-47%				31,477				22,501				-40%
Operating income (loss)			(999	)			1,501				NM				4,244				4,952				-14%
Equity earnings (loss) – Discovery Producer Services LLC			66				(90	)			NM				2,969				3,184				-7%
Interest expense			(2,014	)			(3,095	)			+35%				(8,000	)			(9,376	)			+15%
Interest income			76				—				NM				76				—				NM
Net loss		$	(2,871	)		$	(1,684	)			-70%			$	(711	)		$	(1,240	)			+43%

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

     Revenues increased $1.7 million, or 16 percent, due primarily to higher revenues in our NGL Services segment, reflecting higher storage revenues and increased product sales volumes created through our product optimization activities.

     Operating and maintenance expense increased $2.6 million, or 46 percent, due primarily to a larger lower of cost or market inventory valuation adjustment recognized by our NGL Services segment in the third quarter of 2005 as compared to 2004.

     Product cost increased $0.8 million, or 56 percent, directly related to the sale of surplus propane volumes created through our product optimization activities.

     General and administrative expense increased $0.8 million, or 104 percent, due primarily to the increased costs of being a publicly-traded partnership. These costs included $0.4 million for business development and technical support and $0.4 million for various other fees including audit fees, tax return preparation, 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. At September 30, 2005, we have a contribution receivable from our general partner which includes $417,000 for the third-quarter 2005 credit.

     Operating income (loss) decreased $2.5 million, to a $1.0 million loss, due primarily to increased lower of cost or market inventory valuation adjustment in our NGL Services segment and higher general and administrative expense, partially offset by higher NGL Services’ storage revenues.

     Equity earnings from Discovery Producer Services LLC increased $0.2 million. This increase is discussed in detail in the “Results of Operations — Gathering and Processing” section.

     Interest expense decreased $1.1 million, or 35 percent, due to the forgiveness of the advances from Williams in conjunction with the closing of the IPO on August 23, 2005, slightly offset by the commitment fees on our $75 million borrowing capacity under Williams’ revolving credit facility and our $20 million working capital revolving credit facility with Williams.

Nine months ended September 30, 2005 vs. nine months ended September 30, 2004

     Revenues increased $8.3 million, or 30 percent, due primarily to higher revenues in our NGL Services segment reflecting increased product sales volumes and higher storage revenues, slightly offset by lower revenue in our Gathering and Processing segment.

     Operating and maintenance expense increased $2.2 million, or 15 percent, due primarily to a larger lower of cost or market inventory valuation adjustment recognized by our NGL Services segment in 2005 as compared to 2004.

     Product cost increased $5.5 million, or 195 percent, directly related to the increase in product sales volumes in our NGL Services segment.

     General and administrative expense increased $1.2 million, or 66 percent, due primarily to the increased costs of being a publicly-traded partnership. These costs included $0.8 million for business development and technical support and $0.4 million for various other costs, including audit fees, tax return preparation, director fees, and registration and transfer agent fees.

     Operating income decreased $0.7 million, or 14 percent, due primarily to higher operating and maintenance expense in our NGL Services segment, lower revenues in our Gathering and Processing segment and higher general and administrative expenses, partially offset by higher storage revenues in our NGL Services segment.

     Equity earnings from Discovery Producer Services LLC decreased $0.2 million. This decrease is discussed in detail in the “Results of Operations — Gathering and Processing” section.

     Interest expense decreased $1.4 million, or 15 percent, due to the forgiveness of the advances from Williams in conjunction with the closing of the IPO on August 23, 2005.

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								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
						(Thousands)
Segment revenues		$	650			$	794			$	2,295			$	4,009
Costs and expenses:
Operating and maintenance expense			101				142				477				404
Depreciation			300				300				900				900
Total costs and expenses			401				442				1,377				1,304
Segment operating income			249				352				918				2,705
Equity earnings (loss)			66				(90	)			2,969				3,184
Segment profit		$	315			$	262			$	3,887			$	5,889

Carbonate Trend

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

     Segment revenues decreased $144,000, or 18 percent, due primarily to a 26 percent decline in average gathered volumes between 2005 and 2004. Average gathered volumes for 2004 of approximately 40,500 MMBtu/d were negatively impacted by Hurricane Ivan in September 2004. The 2005 average gathered volumes of approximately 30,000 MMBtu/d were negatively impacted by Hurricane Dennis in July 2005 and Hurricane Katrina in August 2005. The Carbonate Trend pipeline was off-line five days and 10 days for hurricanes Dennis and Katrina, respectively.

     As of October 21, 2005, the Carbonate Trend gathering pipeline has returned to service and the daily gathered volume has increased to approximately 39,300 MMBtu/d, which represents a nine percent increase from the second-quarter 2005 average daily gathered volume of approximately 36,000 MMBtu/d. This increase is due primarily to the second-quarter 2005 successful recompletion of an existing well.

     The decline in gathered volumes was partially offset by a $65,000 increase in gathering revenue resulting from an 11 percent higher average gathering rate. 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.

     Operating and maintenance expense decreased $41,000, or 29 percent, due primarily to painting expenses incurred in 2004.

     Segment operating income decreased $103,000, or 29 percent, due primarily to the lower revenues discussed above.

Nine months ended September 30, 2005 vs. nine months ended September 30, 2004

     Segment revenues decreased $1.7 million, or 43 percent, due primarily to the absence of $950,000 of income from the settlement of a contractual volume deficiency payment recognized in 2004 and a 32 percent decline in average daily gathered volumes between 2005 and 2004.

     The decline in average daily gathered volumes was caused by normal reservoir depletion, reduced capacity experienced at a third-party onshore treating plant in April 2005 and the temporary shutdowns for Hurricane Dennis in July 2005 and Hurricane Katrina in August 2005. The overall impact of this decline in gathered volumes on gathering revenue was approximately $1.0 million. This decline in gathered volumes was partially offset by a 10

percent higher average gathering rate causing a $200,000 increase in gathering revenue. 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.

     Operating and maintenance expense increased $73,000, or 18 percent, due primarily to increased costs for inhibitor chemicals and internal pipeline corrosion inspection. This inspection is conducted once every three years. These increases were offset partially by increased painting expense in 2004.

     Segment operating income decreased $1.8 million, or 66 percent, 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								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
						(Thousands)
Revenues		$	19,100			$	20,947			$	69,414			$	76,732
Costs and expenses, including interest:
Operating and maintenance expense:
Fuel and shrink replacement			7,763				9,441				28,598				36,071
Other operating and maintenance expense			4,583				5,840				14,709				14,686
Depreciation and accretion			6,127				5,671				18,366				16,991
Interest income			(498	)			(153	)			(1,171	)			(345	)
Other expense, net			959				264				1,488				1,045
Total costs and expenses			18,934				21,063				61,990				68,448
Net income (loss)		$	166			$	(116	)		$	7,424			$	8,284
Williams Partners’ 40 percent interest		$	66			$	(46	)		$	2,969			$	3,314
Capitalized interest amortization			—				(44	)			—				(130	)
Equity earnings (loss) per our Consolidated Statements of Operations		$	66			$	(90	)		$	2,969			$	3,184

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

     Revenues decreased $1.8 million, or nine percent, due primarily to lower product sales and transportation revenue, partially offset by higher gathering and fractionation revenue. The significant components of this decrease include the following.

•

NGL sales volumes decreased from approximately 14.1 million gallons in 2004 to 4.4 million in 2005 with a resulting $7.1 million decrease in product sales revenues. This decline was due primarily to the temporary shutdown of the Discovery assets for hurricanes Dennis in July 2005, Katrina in August 2005 and Rita in September 2005. Total NGL volumes sold in the 2004 period were negatively impacted by an interruption of service because of an accidental influx of seawater in a lateral while putting in place a subsea connection to the Front Runner prospect. This decrease was partially offset

by a $1.7 million increase in product sales revenues associated with a 53 percent increase in average sales prices.

	•		Fee-based revenues from transportation services decreased $0.3 million due primarily to $0.7 million from a lower average natural gas transmission rate and $0.1 million from lower condensate transportation volumes, partially offset by $0.5 million from higher natural gas transmission volumes. Average gas transmission volumes for 2004 of approximately 131,000 MMBtu/d were negatively impacted by a temporary interruption of service because of an accidental influx of seawater in a lateral while putting in place a subsea connection to the Front Runner prospect. The 2005 average gas transmission volumes of approximately 149,000 MMBtu/d were negatively impacted by hurricanes Dennis in July 2005, Katrina in August 2005 and Rita in September 2005.
	•		Product sales also decreased $0.4 million due to lower sales of excess fuel and replacement gas in the third quarter of 2005 than 2004.

     Largely offsetting these decreases were the following:

	•		Product sales were also impacted by two processing customers’ elections 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 $3.2 million of revenue in the third quarter of 2005. This increase was offset by a related increase in fuel and shrink replacement discussed below.
	•		Fee-based revenues from gathering services increased $0.4 million due primarily to a 14 percent increase in the average gathering rate and a 14 percent increase in gathering volumes. This average rate increase resulted from higher gathering rates associated with the new volumes from the Front Runner, Rock Creek and Tarantula prospects which came on-line in late 2004. Gathered volumes for 2004 were negatively impacted by the seawater influx incident discussed above.
	•		Processing and fractionation revenues increased $0.9 million due primarily to higher fractionated volumes in 2005 as compared to 2004. The increase in fractionated volumes was due primarily to the new volumes from Front Runner.

     Fuel and shrink replacement decreased $1.7 million, or 18 percent, due primarily to $4.3 million lower costs related to the reduced processing activity that resulted from the temporary shutdowns for hurricanes Dennis, Katrina and Rita discussed previously and $0.4 million lower costs related to the sales of excess fuel and replacement gas. These decreases were partially offset by $3.2 million purchase costs for the two processing customers who elected to have Discovery market their NGLs.

     Other operating and maintenance expense decreased $1.3 million, or 22 percent, due primarily to $1.3 million in repair costs related to the accidental influx of seawater in 2004.

     Depreciation and accretion increased $0.5 million, or eight percent, due primarily to the completion of a pipeline connection to the Front Runner prospect in late 2004.

     Interest income increased $0.3 million, from $0.2 million, due primarily to increasing interest-bearing cash balances during the 2005 period as cash flows from operations were retained.

     Other expense, net increased $0.7 million, from $0.3 million, due primarily to a non-cash foreign currency transaction loss from the revaluation of restricted cash accounts denominated in Euros. These restricted cash accounts were established from contributions made by Discovery’s members, including us, for the construction of the Tahiti pipeline lateral expansion project. Discovery used a portion of the amounts contributed by its members to purchase Euros for construction costs that are contractually required to be paid in Euros.

     Net income (loss) for the period improved $0.3 million, from a loss of $0.1 million, due primarily to the absence of $1.3 million in repair costs incurred in 2004, $0.9 million higher processing and fractionation revenues,

and $0.3 million higher interest income, partially offset by $0.9 million lower gross processing margins, $0.5 million higher Depreciation and accretion expense and $0.7 million foreign currency transaction loss.

Nine months ended September 30, 2005 vs. nine months ended September 30, 2004

     Revenues decreased $7.3 million, or 10 percent, due primarily to lower product sales and transportation volumes, partially offset by higher fractionation revenue and average 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 $10.7 million higher Product sales revenues in the first nine months of 2004.
	•		Total NGL volumes sold in the 2004 period were approximately 45 million gallons as compared to 35 million gallons in 2005, which resulted in a $7.2 million decrease in revenues between the two periods. This decrease is primarily related to the third-quarter 2005 decline discussed previously. This decrease was partially offset by a $5.0 million revenue increase associated with a 20 percent increase in average sales prices.
	•		Fee-based revenues from transportation services decreased $2.7 million due primarily to $2.1 million from a lower average natural gas transmission rate and $0.6 million from lower condensate transportation volumes, partially offset by $0.5 million from higher natural gas transmission volumes.
	•		Other revenues declined $1.2 million due largely to lower platform rental fees.

     Partially offsetting these decreases were the following:

	•		Fee-based revenues from gathering increased $0.8 million due primarily to a 32 percent increase in the average gathering rate associated with new volumes from the Front Runner, Rock Creek and Tarantula prospects which came on-line in late 2004.
	•		Processing and fractionation revenues increased $2.0 million due primarily to an increase in fractionated volumes in 2005 from 2004 related primarily to the new volumes from Front Runner.
	•		Product sales also increased $5.3 million for the NGL sales related to two processing customers’ election to have Discovery market their NGLs for a fee under an option in their contracts as discussed above. This increase was offset by a related increase in fuel and shrink replacement discussed below.
	•		In 2005, Discovery received a $1.4 million volume threshold deficiency payment related to a volume shortfall under a transportation contract.

     Fuel and shrink replacement decreased $7.5 million, or 21 percent, due primarily to $10.7 million lower costs related to the sales of excess fuel and replacement gas and $4.7 million lower costs related to reduced processing activity primarily in the third quarter of 2005, partially offset by $5.3 million of purchase costs for the two processing customers who elected to have Discovery market their NGLs and $2.6 million resulting from 15 percent higher average per-unit natural gas prices.

     Depreciation and accretion expense increased $1.4 million, or eight percent, due primarily to the completion of a pipeline connection to the Front Runner prospect in late 2004.

     Interest income increased $0.8 million, from $0.3 million, due primarily to increasing interest-bearing cash balances during the 2005 period as cash flows from operations were retained.

     Other expense, net increased $0.4 million, or 42 percent, due primarily to a foreign non-cash currency transaction loss from the revaluation of restricted cash accounts denominated in Euros discussed previously.

     Net income decreased $0.9 million, or 10 percent, due primarily to $1.2 million lower other revenues, $1.4 million higher depreciation and accretion and $0.4 million higher Other expense, net. Partially offsetting these were a $1.4 million volume threshold deficiency payment received in 2005 and $0.8 million higher Interest income.

Outlook

     We currently estimate that we will incur $3.4 million to $4.6 million of incremental maintenance expenditures for Carbonate Trend within the next six 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, excluding the maintenance expenditures, by approximately $200,000 to $300,000.

     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.
	•		Following Hurricane Katrina, Discovery’s Larose plant was one of the first large-scale gas processing facilities to return to service in that area of Louisiana. In October 2005, Discovery conducted two expedited open seasons for firm transportation to provide outlets for natural gas that has been stranded following damage to third-party facilities during hurricanes Katrina and Rita. Both of these open seasons were for up to 250,000 MMBtu/d. The first of these includes the construction of a new receipt point at Texas Eastern Transmission Company’s Larose compressor station in Lafourche Parish, Louisiana. The second is via an existing interconnection to Tennessee Gas Pipeline’s Line 500 in Terrebonne Parish, Louisiana. We expect to begin receiving additional incremental volumes from these receipt points by December 2005, and anticipate continued throughput for the subsequent three to six months. Shippers will reimburse Discovery for all capital necessary to establish these connections.
	•		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 natural 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 35,000 MMBtu/d. Capital to connect this new well will be provided by others.
	•		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								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
						(Thousands)
Segment revenues		$	11,526			$	9,663			$	33,426			$	23,444
Costs and expenses:
Operating and maintenance expense			8,171				5,509				16,315				14,154
Product cost			2,258				1,445				8,320				2,816
Depreciation			596				618				1,794				1,796
General and administrative expense — direct			308				118				782				376
Taxes other than income			194				179				532				537
Total costs and expenses			11,527				7,869				27,743				19,679
Segment profit (loss)		$	(1	)		$	1,794			$	5,683			$	3,765

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

     Segment revenues increased $1.9 million, or 19 percent, due primarily to higher storage revenues and product sales. The significant components of this increase include the following.

	•		Storage revenue increased $1.2 million due to higher contracted storage volumes and a slightly higher average per-unit storage rate. Volumes in the third 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.
	•		Product sales of surplus propane volumes created through our product optimization activities increased $0.8 million due to increased volumes and higher average sales prices. We actively manage the fractionation process to optimize the resulting mix of products. This increase was offset by the related increase in Product cost.