Edgar Filing: Williams Partners L.P.

e10vq

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 September 30, 2007


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 þ No o

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

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

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

The registrant had 32,360,538 common units and 7,000,000 subordinated units outstanding as of October 31, 2007.

WILLIAMS PARTNERS L.P.
INDEX


	Page
Part I. Financial Information

Item 1. Financial Statements

Consolidated Statements of Income — Three and Nine Months Ended September 30, 2007 and 2006		3

Consolidated Balance Sheets — September 30, 2007 and December 31, 2006		4

Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2007 and 2006		5

Consolidated Statement of Partners’ Capital from January 1, 2007 to September 30, 2007		6

Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		36

Item 4. Controls and Procedures		36

Part II. Other Information

Item 1. Legal Proceedings		37

Item 1A. Risk Factors		37

Item 6. Exhibits		38
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer

FORWARD-LOOKING STATEMENTS

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations.

All statements, other than statements of historical facts, included in this report which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

	•		amounts and nature of future capital expenditures;

	•		expansion and growth of our business and operations;

	•		business strategy;

	•		cash flow from operations;

	•		seasonality of certain business segments; and

	•		natural gas liquids and gas prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. Many of the factors that will determine these results are

beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

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

	•		Because of the natural decline in production from existing wells and competitive factors, the success of our gathering and transportation businesses depends on our ability to connect new sources of natural gas supply, which is dependent on factors beyond our control. Any decrease in supplies of natural gas could adversely affect our business and operating results.

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

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

	•		We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and natural gas liquids. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.

	•		If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and natural gas liquids or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

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

	•		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 currently have little ability to remove our general partner without its consent.

	•		Unitholders 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.

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item IA “Risk Factors” in our Form 10-K for the year ended December 31, 2006.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per-unit amounts)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006*			2007				2006*
Revenues:
Product sales:
Affiliate	$	75,519		$	68,542		$	194,190			$	190,308
Third-party		4,297			4,553			15,680				15,111
Gathering and processing:
Affiliate		9,178			10,162			27,412				30,851
Third-party		51,721			52,679			154,246				153,460
Storage		7,404			6,581			20,632				17,610
Fractionation		2,723			2,708			7,256				9,650
Other		(1,266	)		1,357			3,244				3,513


Total revenues		149,576			146,582			422,660				420,503

Costs and expenses:
Product cost and shrink replacement:
Affiliate		18,806			19,159			59,051				58,596
Third-party		30,043			25,542			76,670				74,824
Operating and maintenance expense (excluding depreciation):
Affiliate		15,275			10,681			40,087				39,768
Third-party		25,259			26,888			77,203				76,155
Depreciation, amortization and accretion		10,345			10,944			34,757				32,510
General and administrative expense:
Affiliate		10,816			7,730			29,866				24,238
Third-party		925			1,038			2,778				3,293
Taxes other than income		2,474			2,352			7,214				6,392
Other (income) expense		134			90			792				(3,225	)


Total costs and expenses		114,077			104,424			328,418				312,551


Operating income		35,499			42,158			94,242				107,952

Equity earnings-Discovery Producer Services		7,902			6,083			15,708				15,275
Interest expense:
Affiliate		(16	)		(15	)		(46	)			(45	)
Third-party		(14,268	)		(3,256	)		(43,038	)			(4,110	)
Interest income		312			462			2,556				642


Net income	$	29,429		$	45,432		$	69,422			$	119,714


Allocation of net income:
Net income	$	29,429		$	45,432		$	69,422			$	119,714
Allocation of net income to general partner		4,937			32,851			8,292				98,439

Allocation of net income to limited partners	$	24,492		$	12,581		$	61,130			$	21,275


Basic and diluted net income per limited partner unit:
Common units	$	0.62		$	0.58		$	1.41			$	1.19
Subordinated units		0.62			0.58			1.41				1.19

Weighted average number of units outstanding:
Common units		32,359,555			14,597,072			32,359,053		(a)		9,870,084
Subordinated units		7,000,000			7,000,000			7,000,000				7,000,000


*		Restated as discussed in Note 1.

(a)		Includes Class B units converted to Common on May 21, 2007 (See Note 8).

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS


	September 30,		December 31,
	2007		2006
	(Unaudited)
	(Thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	16,089	$	57,541
Accounts receivable:
Trade		17,693		18,320
Affiliate		13,757		12,420
Other		2,908		3,991
Gas purchase contract — affiliate		1,188		4,754
Product imbalance		7,283		10,308
Prepaid expense		5,187		3,765
Other current assets		2,499		2,534

Total current assets		66,604		113,633

Investment in Discovery Producer Services		209,791		221,187
Property, plant and equipment, net		649,037		647,578
Other assets		31,114		34,752


Total assets	$	956,546	$	1,017,150


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable — trade	$	23,610	$	19,827
Product imbalance		10,774		10,959
Deferred revenue		7,205		3,382
Accrued interest		10,563		2,796
Other accrued liabilities		11,708		13,377

Total current liabilities		63,860		50,341

Long-term debt		750,000		750,000
Environmental remediation liabilities		3,964		3,964
Other noncurrent liabilities		8,146		3,749
Commitments and contingent liabilities (Note 8)
Partners’ capital		130,576		209,096


Total liabilities and partners’ capital	$	956,546	$	1,017,150

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Nine Months Ended
	September 30,
	2007			2006*
	(Thousands)
OPERATING ACTIVITIES:
Net income	$	69,422		$	119,714
Adjustments to reconcile to cash provided by operations:
Depreciation, amortization and accretion		34,757			32,510
Amortization of gas purchase contract — affiliate		3,566			3,998
Gain on sale of property, plant and equipment		—			(2,622	)
Equity earnings of Discovery Producer Services		(15,708	)		(15,275	)
Distributions related to equity earnings of Discovery Producer Services		13,106			10,183
Cash provided (used) by changes in assets and liabilities:
Accounts receivable		373			(25,090	)
Prepaid expense		(1,500	)		(1,000	)
Other current assets		35			—
Accounts payable		3,246			(8,043	)
Product imbalance		2,840			(4,900	)
Deferred revenue		4,347			3,266
Accrued liabilities		10,257			3,009
Other, including changes in non-current liabilities		4,324			771


Net cash provided by operating activities		129,065			116,521


INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(33,029	)		(21,514	)
Change in accrued liabilities-capital expenditures		(4,779	)		—
Proceeds from sales of property, plant and equipment		—			7,299
Purchase of equity investment		(69,061	)		(156,129	)
Distributions in excess of equity earnings of Discovery Producer Services		4,964			1,817
Other		536			—


Net cash used by investing activities		(101,369	)		(168,527	)


FINANCING ACTIVITIES:
Proceeds from sale of common units		—			227,107
Proceeds from debt issuance		—			150,000
Excess purchase price over contributed basis of equity investment		(8,939	)		(203,871	)
Payment of debt issuance costs		—			(3,138	)
Payment of offering costs		—			(2,168	)
Distributions to unitholders		(62,935	)		(19,875	)
Distributions to The Williams Companies, Inc.		—			(73,842	)
General partner contributions		—			4,841
Contributions per omnibus agreement		2,726			4,244


Net cash provided (used) by financing activities		(69,148	)		83,298


Increase (decrease) in cash and cash equivalents		(41,452	)		31,292
Cash and cash equivalents at beginning of period		57,541			6,839


Cash and cash equivalents at end of period	$	16,089		$	38,131


*		Restated as discussed in Note 1.

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(Unaudited)


	Limited Partners												Accumulated Other			Total
										General			Comprehensive			Partners’
	Common			Class B			Subordinated			Partner			Loss			Capital
	(Thousands)
Balance — January 1, 2007	$	733,878		$	241,923		$	108,862		$	(875,567	)		—		$	209,096
Comprehensive income:
Net income		44,772			9,212			10,530			4,908			—			69,422
Other comprehensive loss:
Net unrealized losses on cash flow hedges		—			—			—			—			(620	)		(620	)

Total other comprehensive loss																	(620	)

Total comprehensive income																	68,802
Cash distributions		(41,776	)		(6,601	)		(10,465	)		(4,093	)		—			(62,935	)
Contributions pursuant to the omnibus agreement		—			—			—			2,726			—			2,726
Conversion of B units to Common (6,805,492 units)		244,534			(244,534	)		—			—			—			—
Distribution to general partner in exchange for additional investment in Discovery		—			—			—			(78,000	)		—			(78,000	)
Discovery distributions to The Williams Companies, Inc., not attributable to the Partnership		—						—			(9,035	)					(9,035	)
Other		(78	)		—			—			—			—			(78	)


Balance — September 30, 2007	$	981,330		$	—		$	108,927		$	(959,061	)	$	(620	)	$	130,576

See accompanying notes to consolidated financial statements.

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

Note 1. Organization and Basis of Presentation

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries and include the operations of Discovery Producer Services LLC (“Discovery”) in which we own a 60% interest. When we refer to Discovery by name, we are referring exclusively to its businesses and operations.

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

During 2006, we acquired Williams Four Corners LLC (“Four Corners”) pursuant to two agreements with Williams Energy Services, LLC (“WES”), Williams Field Services Group LLC, Williams Field Services Company, LLC and OLLC. Because Four Corners was an affiliate of The Williams Companies, Inc. (“Williams”) at the time of the acquisition, the transactions were accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities of Four Corners were combined with Williams Partners L.P. at their historical amounts. Accordingly, the comparative September 30, 2006 financial statements and notes have been restated to reflect the combined results, increasing net income by $95.5 million. The restatement does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.

On June 28, 2007 we closed on the acquisition of an additional 20% interest in Discovery from Williams Energy, L.L.C. and WES for aggregate consideration of $78.0 million in cash. This transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was purchased from an affiliate of Williams, the transaction was between entities under common control and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes have been restated to reflect the combined historical results of our investment in Discovery throughout the periods presented. We now own 60% of Discovery. We continue to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment. The acquisition increased net income for the nine months ended September 30, 2007 and 2006 by $2.6 million and $5.1 million, respectively. The acquisition had no impact on earnings per unit for periods prior to the acquisition as pre-acquisition earnings were allocated to the general partner.

The accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 8-K, filed August 29, 2007, for the year ended December 31, 2006. The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2007, results of operations for the three and nine months ended September 30, 2007 and 2006 and cash flows for the nine months ended September 30, 2007 and 2006. All intercompany transactions have been eliminated.

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

Certain amounts have been reclassified to conform to the current classifications.

Note 2. Recent Accounting Standards

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

Note 3. Allocation of Net Income and Distributions

The allocation of net income between our general partner and limited partners, as reflected in the Consolidated Statement of Partners’ Capital, for the three months and nine months ended September 30, 2007 and 2006 is as follows (in thousands):


	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006*			2007			2006*

Allocation to general partner:
Net income	$	29,429		$	45,432		$	69,422		$	119,714
Net income applicable to pre-partnership operations allocated to general partner		—			(33,472	)		(2,602	)		(100,575	)
2^nd quarter beneficial conversion of Class B units**		—			—			(5,308	)		—
Charges direct to general partner:
Reimbursable general and administrative costs		605			806			1,795			2,393
Core drilling indemnified costs		—			679			—			784


Total charges direct to general partner		605			1,485			1,795			3,177

Income subject to 2% allocation of general partner interest		30,034			13,445			63,307			22,316
General partner’s share of net income		2.0	%		2.0	%		2.0	%		2.0	%


General partner’s allocated share of net income before items directly allocable to general partner interest		600			268			1,266			446
Incentive distributions paid to general partner		1,267			74			2,835			74
Direct charges to general partner		(605	)		(1,485	)		(1,795	)		(3,177	)
Pre-partnership net income allocated to general partner		—			33,472			2,602			100,575


Net income allocated to general partner	$	1,262		$	32,329		$	4,908		$	97,918


Net income	$	29,429		$	45,432		$	69,422		$	119,714
Net income allocated to general partner		1,262			32,329			4,908			97,918


Net income allocated to limited partners	$	28,167		$	13,103		$	64,514		$	21,796


*		Restated as discussed in Note 1.


**		On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis. Accordingly, under EITF 98-05, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios” we should have made a $5.3 million non-cash allocation of income to the Class B units representing the Class B unit beneficial conversion feature in the second quarter of 2007. The $5.3 million beneficial conversion feature was computed as the product of the 6,805,492 Class B units and the difference between the fair value of a privately placed common unit on the date of issuance ($36.59) and the issue price of a Class B unit ($35.81). This results in an $0.08 decrease from $0.56 per unit to $0.48 per unit on our earnings per common unit for the second quarter of 2007. Because we did not make this $5.3 million non-cash allocation in the second quarter of 2007, we have reflected this adjustment in the year-to-date earnings per common unit through September 30, 2007. While this correction affects net income available to limited partners, it does not affect net income, cash flows nor does it affect total partners’ equity.

Under the “two class” method of computing earnings per share prescribed by SFAS No. 128, “Earnings Per Share,” earnings are to be allocated to participating securities as if all of the earnings for the period had been distributed. As a result, the general partner receives an additional allocation of income in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeds the actual incentive distribution. The assumed incentive distribution for the three and nine months ended September 30, 2007 is $4.9 million and $5.7 million, respectively. There were no assumed incentive distributions for the three or nine months ended September 30, 2006. This results in an allocation of income for the calculation of earnings per limited partner unit as shown on the Consolidated Statements of Income.

Pursuant to the partnership agreement, income allocations are made on a quarterly basis; therefore, earnings per limited partner unit for the nine months ended September 30, 2007 and 2006 is calculated as the sum of the quarterly earnings per limited partner unit for each of the first three quarters of 2007 and 2006. Common and subordinated unitholders share equally, on a per-unit basis, in the net income allocated to limited partners for the three and nine months ended September 30, 2007 and 2006.

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


									General Partner
											Incentive
	Per Unit		Common		Subordinated		Class B				Distribution		Total Cash
Payment Date	Distribution		Units		Units		Units		2%		Rights		Distribution
2/14/2006	$	0.3500	$	2,452	$	2,450	$	—		100		—	$	5,002
5/15/2006	$	0.3800	$	2,662	$	2,660	$	—		109		—	$	5,431
8/14/2006	$	0.4250	$	6,204	$	2,975	$	—		189		74	$	9,442
11/14/2006	$	0.4500	$	6,569	$	3,150	$	—		202		199	$	10,120
2/14/2007	$	0.4700	$	12,010	$	3,290	$	3,198		390		603	$	19,491
5/15/2007	$	0.5000	$	12,777	$	3,500	$	3,403		421		965	$	21,066
8/14/2007	$	0.5250	$	16,989	$	3,675	$	—		447		1,267	$	22,378
11/14/2007(a)	$	0.5500	$	17,799	$	3,850	$	—		487		2,211	$	24,347



(a)		The board of directors of our general partner declared this cash distribution on October 23, 2007 to be paid on November 14, 2007 to unitholders of record at the close of business on November 7, 2007.

Note 4. Out of Period Adjustments

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


	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006
				Increase (decrease) in net income

Gathering and Processing — West

Adjustment to property, plant and equipment and deferred revenue balances related to electronic flow measurement revenue recognition	$	(2,108	)	$	—		$	(2,108	)	$	—
Adjustment to record condensate revenue on a current basis		—			—			—			1,900
Adjustment to correct carrying value of prepaid right-of-way asset recorded from 2001 through 2006		—			—			(1,243	)		—
Adjustment to correct the 2006 incentive compensation accrual		—			—			899			—
Adjustment to correct the asset retirement obligation originally recorded in 2005		—			—			(785	)		—
Adjustment to correct the accounts payable balance recorded in 2005		—			—			—			2,000
Misstated accounts payable balances at June 30, 2006 corrected in the third quarter of 2006		—			(2,000	)		—			—
Misstated accounts payable balances at June 30, 2006 corrected in the third quarter of 2006		—			840			—			—

Note 5. Equity Investments

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

Discovery Producer Services LLC


	September 30,			December 31,
	2007			2006
	(Unaudited)
Current assets	$	61,048		$	73,841
Non-current restricted cash and cash equivalents		6,117			28,773
Property, plant and equipment, net		378,552			355,304
Current liabilities		(33,166	)		(40,559	)
Non-current liabilities		(13,993	)		(3,728	)


Members’ capital	$	398,558		$	413,631


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(Unaudited)

Revenues:
Affiliate	$	51,829		$	38,755		$	144,997		$	113,992
Third-party		8,281			8,663			31,098			28,462
Costs and expenses:
Affiliate		24,973			13,263			72,145			54,397
Third-party		22,452			24,459			78,986			65,662
Interest income		(389	)		(608	)		(1,472	)		(1,835	)
Loss on sale of operating assets		—			—			603			—
Foreign exchange (gain) loss		(94	)		166			(346	)		(1,228	)


Net income	$	13,168		$	10,138		$	26,179		$	25,458

As discussed in Note 1. Organization and Basis of Presentation, our consolidated financial statements and notes have been restated to include the additional 20% interest in Discovery, which we closed on in June 2007. However, certain cash transactions that occurred between Discovery and Williams before June 2007 that related to the additional 20% interest are not reflected in our Consolidated Statement of Cash Flows even though these transactions affect the carrying value of our restated investment in Discovery. A summary of these transactions is as follows (in thousands):


	Nine Months Ended
	September 30,
	2007		2006
Cash distributions from Discovery to Williams	$	9,035	$	6,000

Note 6. Credit Facilities and Long-Term Debt

Credit Facilities

We may borrow up to $75.0 million under Williams’ $1.5 billion revolving credit facility, which is available for borrowings and letters of credit. Pursuant to an amendment dated May 9, 2007, borrowings under the Williams facility mature in May 2012. Our $75.0 million borrowing limit under Williams’ revolving credit facility is available for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. At September 30, 2007, letters of credit totaling $28.0 million had been issued on behalf of Williams, none on behalf of the Partnership, by the participating institutions under this facility and no revolving credit loans were outstanding.

We also have a $20.0 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the credit facility will mature on June 29, 2009. We are required to reduce all borrowings under this facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility. As of September 30, 2007, we have no outstanding borrowings under the working capital credit facility.

Long-Term Debt

In connection with the issuances of our $600.0 million of 7.25% senior unsecured notes on December 13, 2006 and $150.0 million of 7.5% senior unsecured notes on June 20, 2006, sold in private debt placements to qualified institutional buyers in accordance with Rule 144A under the Securities Act and outside the United States in accordance with Regulations under the Securities Act, we entered into registration rights agreements with the initial purchasers of the senior unsecured notes. Under these agreements, we agreed to conduct a registered exchange offer of exchange notes in exchange for the senior unsecured notes or cause to become effective a shelf registration statement providing for resale of the senior unsecured notes. We launched exchange offers for both series on April 10, 2007 and they were successfully closed on May 11, 2007.

Note 7. Derivative Instruments and Hedging Activities

Accounting policy

We utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swap agreements. We execute these transactions in over-the-counter markets in which quoted prices exist for active periods. We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheet in other current assets, other accrued liabilities, other assets or other noncurrent liabilities. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual contracts.

The accounting for changes in the fair value of derivatives is governed by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and depends on whether the derivative has been designated in a hedging relationship and what type of hedging relationship it is. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in other revenues.

For derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in other comprehensive loss and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in other revenues. Gains or losses deferred in accumulated other comprehensive loss associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in accumulated other comprehensive loss until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in accumulated other comprehensive loss is recognized in other revenues at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.

Energy commodity cash flow hedges

We are exposed to market risk from changes in energy commodity prices within our operations. Our Four Corners operation receives NGL volumes as compensation for certain processing services. To reduce our exposure to a decrease in revenues from the sale of these NGL volumes from fluctuations in NGL market prices, we entered into financials swap contracts for 8.8 million gallons of May through December 2007 forecasted NGL sales. These derivatives were designated in cash flow hedge relationships and are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. No ineffectiveness was recognized through September 30, 2007. There were no derivative gains or losses excluded from the assessment of hedge effectiveness through September 30, 2007. Based on recorded values at September 30, 2007, approximately $0.6 million of net losses will be reclassified into earnings in the fourth quarter. These recorded values are based on market prices of the commodities as of September 30, 2007. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized in 2007 will likely differ from these values. These gains or losses will offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

Note 8. Commitments and Contingencies

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

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

We have accrued liabilities totaling $0.7 million at September 30, 2007 for these environmental activities. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by governmental authorities and other factors.

We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance.

On April 11, 2007, the New Mexico Environment Department’s Air Quality Bureau (“NMED”) issued a Notice of Violation to Four Corners that alleges various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. We are investigating the matter and exchanging information with the NMED.

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

In 2004, we purchased an insurance policy that covers up to $5.0 million of remediation costs until an active remediation system is in place or April 30, 2008, whichever is earlier, excluding operation and maintenance costs and ongoing monitoring costs for these projects to the extent such costs exceed a $4.2 million deductible, of which $2.7 million has been incurred to date from the onset of the policy. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25.0 million. In addition, under an omnibus agreement with Williams entered into at the closing of our IPO, Williams agreed to indemnify us for the $4.2 million deductible not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring. There is a $14.0 million cap on the total amount of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under the environmental insurance policy. There is also a three-year time limitation from the August 23, 2005 IPO closing date. The benefit of this indemnification is accounted for as a capital contribution to us by Williams as the costs are reimbursed. We estimate that the approximate cost of this project management and soil and groundwater monitoring associated with the four remediation projects at the Conway storage facilities and for which we will not be indemnified will be approximately $0.2 million to $0.4 million per year following the completion of the remediation work. At September 30, 2007, we had accrued liabilities totaling $4.3 million for these costs. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by KDHE and other governmental authorities and other factors.

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

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

GE Litigation. General Electric International Inc. (GEII) worked on turbines at our Ignacio, New Mexico plant. We disagree with GEII on the quality of GEII’s work and the appropriate compensation. GEII asserts that it is entitled to additional extra work charges under the agreement, which we deny are due. On September 29, 2006, we filed suit in the U.S. District Court in Tulsa, Oklahoma against GEII, GE Energy Services, Inc., and Qualified Contractors, Inc. and alleged, among other claims, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, and sought unspecified damages. On March 16, 2007, all three defendants filed their answer, and GEII filed a counterclaim against us alleging breach of contract and breach of the implied duty of good faith and fair dealing. We denied the counterclaim’s allegations in our answer to the counterclaim. Trial has been set for April 21, 2008. We are unable to estimate or quantify any potential liability.

Outstanding Registration Rights Agreement. On December 13, 2006, we issued approximately $350.0 million of common and Class B units in a private equity offering. In connection with these issuances, we entered into a registration rights agreement with the initial purchasers whereby we agreed to file a shelf registration statement providing for the resale of the common units purchased and the common units issued upon conversion of the Class B units. We filed the shelf registration statement on January 12, 2007, and it became effective on March 13, 2007. On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis. If the shelf is unavailable for a period that exceeds an aggregate of 30 days in any 90-day period or 105 days in any 365 day period, the purchasers are entitled to receive liquidated damages. Liquidated damages with respect to each purchaser are calculated as 0.25% of the Liquidated Damages Multiplier per 30-day period for the first 60 days following the 90th day, increasing by an additional 0.25% of the Liquidated Damages Multiplier per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the Liquidated Damages Multiplier per 30-day period; provided, the aggregate amount of liquidated damages payable to any purchaser is capped at 10.0% of the Liquidated Damages Multiplier. The Liquidated Damages Multiplier, with respect to each purchaser, is (i) the product of $36.59 times the number of common units purchased plus (ii) the product of $35.81 times the number of Class B units purchased. We do not expect to pay any liquidated damages related to this agreement.

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

Summary. Litigation, arbitration, regulatory matters and environmental matters are subject to inherent uncertainties. Were an unfavorable event to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the event occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.

Note 9. Segment Disclosures

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


			Gathering &
	Gathering &		Processing -			NGL
	Processing - West		Gulf			Services		Total
	(In thousands)
Three Months Ended September 30, 2007:

Segment revenues	$	134,035	$	521		$	15,020	$	149,576

Operating and maintenance expense		34,267		443			5,824		40,534
Product cost and shrink replacement		45,791		—			3,058		48,849
Depreciation, amortization and accretion		8,564		304			1,477		10,345
Direct general and administrative expense		1,839		—			510		2,349
Other, net		2,414		—			194		2,608


Segment operating income (loss)		41,160		(226	)		3,957		44,891
Equity earnings — Discovery Producer Services		—		7,902			—		7,902


Segment profit	$	41,160	$	7,676		$	3,957	$	52,793


Reconciliation to the Consolidated Statements of Income:
Segment operating income								$	44,891
General and administrative expenses:
Allocated — affiliate									(8,670	)
Third party — direct									(722	)


Combined operating income								$	35,499


*Three Months Ended September 30, 2006:**

Segment revenues	$	132,603	$	632		$	13,347	$	146,582

Operating and maintenance expense		29,950		399			7,220		37,569
Product cost and shrink replacement		41,821		—			2,880		44,701
Depreciation, amortization and accretion		10,035		300			609		10,944
Direct general and administrative expense		2,838		—			279		3,117
Other, net		2,260		—			182		2,442


Segment operating income (loss)		45,699		(67	)		2,177		47,809
Equity earnings — Discovery Producer Services		—		6,083			—		6,083


Segment profit	$	45,699	$	6,016		$	2,177	$	53,892


Reconciliation to the Consolidated Statements of Income:
Segment operating income								$	47,809
General and administrative expenses:
Allocated — affiliate									(5,091	)
Third party — direct									(560	)


Combined operating income								$	42,158


*		Restated as discussed in Note 1.


			Gathering &
	Gathering &		Processing -			NGL
	Processing - West		Gulf			Services		Total
	(In thousands)
Nine Months Ended September 30, 2007:

Segment revenues	$	379,510	$	1,541		$	41,609	$	422,660

Operating and maintenance expense		96,851		1,354			19,085		117,290
Product cost and shrink replacement		127,779		—			7,942		135,721
Depreciation, amortization and accretion		30,942		911			2,904		34,757
Direct general and administrative expense		5,457		—			1,478		6,935
Other, net		7,422		—			584		8,006


Segment operating income (loss)		111,059		(724	)		9,616		119,951
Equity earnings — Discovery Producer Services		—		15,708			—		15,708


Segment profit	$	111,059	$	14,984		$	9,616	$	135,659

Reconciliation to the Consolidated Statements of Income:
Segment operating income								$	119,951
General and administrative expenses:
Allocated — affiliate									(23,324	)
Third party — direct									(2,385	)


Combined operating income								$	94,242


*Nine Months Ended September 30, 2006:**

Segment revenues	$	376,069	$	2,041		$	42,393	$	420,503

Operating and maintenance expense		93,570		872			21,481		115,923
Product cost and shrink replacement		121,898		—			11,522		133,420
Depreciation, amortization and accretion		29,801		900			1,809		32,510
Direct general and administrative expense		8,599		9			815		9,423
Other, net		2,612		—			555		3,167


Segment operating income		119,589		260			6,211		126,060
Equity earnings — Discovery Producer Services		—		15,275			—		15,275


Segment profit	$	119,589	$	15,535		$	6,211	$	141,335


Reconciliation to the Consolidated Statements of Income:
Segment operating income								$	126,060
General and administrative expenses:
Allocated — affiliate									(16,434	)
Third party — direct									(1,674	)


Combined operating income								$	107,952


*		Restated as discussed in Note 1.

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

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

Overview

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

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

	•		Gathering and Processing — Gulf. Our Gulf segment includes (1) our 60% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline off the coast of Alabama. Discovery owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and an NGL fractionator in Louisiana. These assets generate revenues by providing natural gas gathering, transporting and processing services and integrated NGL fractionating services to customers under a range of contractual arrangements. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such.

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

Executive Summary

Through the third quarter of 2007, we continued to realize strong NGL margins at Four Corners. Gathering and processing revenues for Four Corners are slightly below 2006 due to lower volumes, but we expect our full-year gathering volumes will approximate 2006 levels. At Conway we continue to see strong demand for leased storage and new product upgrade services. Discovery’s income is comparable with the prior year even though it had an exceptional first half of 2006 when it was processing volumes from damaged third-party facilities after Hurricanes Katrina and Rita. Our consolidated operating and maintenance expenses are slightly above 2006 levels, while we have seen significant increases in general and administrative expense. Year-over-year net income comparisons are also significantly impacted by the interest on our $750.0 million in long-term debt issued in June 2006 and December 2006 to finance a portion of our acquisition of Four Corners. Additionally, our results reflect the impact of adjustments to our operating costs and expenses, which are itemized in Note 4 of the Notes to our Consolidated Financial Statements.

Recent Events

Conversion of Class B Units. On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis by a majority vote of common units eligible to vote.

Additional Investment in Discovery. On June 28, 2007, we closed on the acquisition of an additional 20% limited liability company interest in Discovery for aggregate consideration of $78.0 million pursuant to an agreement with Williams Energy, L.L.C. and Williams Energy Services, LLC. This transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was purchased from an affiliate of The Williams Companies, Inc. (“Williams”), the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes and this discussion of results of operations have been restated to reflect the combined historical results of our investment in Discovery throughout

the periods presented. We continue to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment.

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, 2007, compared to the three and nine months ended September 30, 2006. The results of operations by segment are discussed in further detail following this consolidated overview discussion. All prior period information in the following discussion and analysis of results of operations has been restated to reflect our 100% interest acquisition in Four Corners in 2006 and our 60% equity interest in Discovery.


	Three months ended									Nine months ended						% Change
	September 30,						% Change from			September 30,						from
	2007			2006			2006⁽¹⁾			2007			2006			2006⁽¹⁾
	(Thousands)									(Thousands)

Revenues	$	149,576		$	146,582			+2	%	$	422,660		$	420,503			+1	%

Costs and expenses:
Product cost and shrink replacement		48,849			44,701			-9	%		135,721			133,420			-2	%
Operating and maintenance Expense		40,534			37,569			-8	%		117,290			115,923			-1	%
Depreciation, amortization and accretion		10,345			10,944			+5	%		34,757			32,510			-7	%
General and administrative Expense		11,741			8,768			-34	%		32,644			27,531			-19	%
Taxes other than income		2,474			2,352			-5	%		7,214			6,392			-13	%
Other (income) expense		134			90			-49	%		792			(3,225	)	NM


Total costs and expenses		114,077			104,424			-9	%		328,418			312,551			-5	%


Operating income		35,499			42,158			-16	%		94,242			107,952			-13	%
Equity earnings — Discovery		7,902			6,083			+30	%		15,708			15,275			3	%
Interest expense		(14,284	)		(3,271	)	NM				(43,084	)		(4,155	)	NM
Interest income		312			462			-32	%		2,556			642		NM


Net income	$	29,429		$	45,432			-35	%	$	69,422		$	119,714			-42	%


(1)		+ = Favorable Change; — = Unfavorable Change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.

Three months ended September 30, 2007 vs. three months ended September 30, 2006

Revenues increased $3.0 million, or 2%, due primarily to higher revenues in our Gathering and Processing — West and NGL Services segments. Revenues in our Gathering and Processing — West segment increased due primarily to higher product sales, partially offset by lower gathering, processing and other revenues. Revenues increased in our NGL Services segment due primarily to higher storage and product upgrade fees. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

Product cost and shrink replacement increased $4.1 million, or 9%, due primarily to increased NGL purchases from producers in our Gathering and Processing — West segment. This fluctuation is discussed in detail in the “—

Results of Operations — Gathering and Processing — West” section.

Operating and maintenance expense increased $3.0 million, or 8%, due primarily to higher expense in our Gathering and Processing — West segment, partially offset by lower expense in our NGL Services segment. Operating and maintenance expense in our Gathering and Processing — West segment increased due primarily to higher system losses, leased compression and rent expense, partially offset by lower materials and supplies and outside services costs. Operating and maintenance expense in our NGL Services segment decreased due primarily to lower product losses from cavern empties. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

General and administrative expense increased $3.0 million, or 34%, due primarily to higher Williams technical support services and other charges allocated by Williams to us for various administrative support functions.

Operating income decreased $6.7 million, or 16%, due primarily to higher general and administrative and operating and maintenance expense.

Equity earnings from Discovery increased $1.8 million, or 30%, due primarily to higher NGL gross margins, largely offset by higher operating and maintenance expense. This increase is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

Interest expense increased $11.0 million due to interest on our $600.0 million senior unsecured notes issued in December 2006 to finance a portion of our acquisition of Four Corners.

Nine months ended September 30, 2007 vs. nine months ended September 30, 2006

Revenues increased $2.2 million, or 1%, due primarily to higher product sales in our Gathering and Processing — West segment, partially offset by lower gathering, processing and other revenues in the same segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.

Product cost and shrink replacement increased $2.3 million, or 2%, due primarily to increased NGL purchases from producers in our Gathering and Processing — West segment, partially offset by decreased product sales volumes in our NGL Services segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

Operating and maintenance expense increased $1.4 million, or 1%, due primarily to higher expense in our Gathering and Processing — West segment, partially offset by lower expense in our NGL Services segment. Operating and maintenance expense in our Gathering and Processing — West segment increased due primarily to higher fuel, leased compression and rent expense, largely offset by lower maintenance and supplies costs. Operating and maintenance expense in our NGL Services segment decreased due primarily to lower fuel and power costs related to the lower fractionator throughput. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

The $2.2 million, or 7%, increase in Depreciation, amortization and accretion reflects $2.0 million of first quarter 2007 right-of-way amortization and asset retirement obligation adjustments in our Gathering and Processing — West segment.

General and administrative expense increased $5.1 million, or 19%, due primarily to higher Williams technical support services and other charges allocated by Williams to us for various administrative support functions.

Taxes other than income increased $0.8 million, or 13%, due primarily to an increase in New Mexico gas processor’s tax in the Gathering and Processing — West segment.

Other (income) expense, changed from $3.2 million income in 2006 to $0.8 million expense in 2007, due primarily to a $3.6 million gain in 2006 on the sale of property in the Gathering and Processing — West segment.

Operating income declined $13.7 million, or 13%, due primarily to higher general and administrative expense, the absence of the 2006 gain on the sale of property and higher depreciation, amortization and accretion expense.

Equity earnings from Discovery increased $0.4 million, or 3%, due primarily to higher NGL gross processing margins that offset lower fee-based revenues following the loss of 2006 revenues associated with providing services for stranded gas after the 2005 hurricanes. Discovery’s results are discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

Interest expense increased $38.9 million due to interest on our $750.0 million senior unsecured notes issued in June and December 2006 to finance a portion of our acquisition of Four Corners.

Interest income increased from $0.6 million to $2.6 million due to higher cash balances during the first and second quarters of 2007.

Results of operations — Gathering and Processing — West

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

Four Corners


	Three months ended				Nine months ended
	September 30,				September 30,
	2007		2006		2007		2006
	(Thousands)

Revenues	$	134,035	$	132,603	$	379,510	$	376,069

Costs and expenses, including interest:
Product cost and shrink replacement		45,791		41,821		127,779		121,898
Operating and maintenance expense		34,267		29,950		96,851		93,570
Depreciation, amortization and accretion		8,564		10,035		30,942		29,801
General and administrative expense — direct		1,839		2,838		5,457		8,599
Taxes other than income		2,278		2,170		6,628		5,842
Other (income) expense, net		136		90		794		(3,230	)


Total costs and expenses		92,875		86,904		268,451		256,480


Segment profit	$	41,160	$	45,699	$	111,059	$	119,589

Three months ended September 30, 2007 vs. three months ended September 30, 2006

Revenues increased $1.4 million, or 1%, due primarily to higher product sales, partially offset by lower gathering, processing and other revenues. The significant components of the revenue fluctuations are addressed more fully below.

Product sales revenues increased $6.7 million due primarily to:

	•		$4.3 million higher sales of NGLs on behalf of third party producers from whom we purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an affiliate. This increase is offset by higher associated product costs of $4.3 million discussed below.

	•		$3.3 million related to a 8% increase in average NGL sales prices realized on sales of NGLs which we received under certain processing contracts; and

These product sales increases were partially offset by $0.8 million lower revenues related to a 2% decrease in NGL volumes that Four Corners received under certain processing contracts.

Miscellaneous revenues decreased $3.7 million due primarily to a $3.5 million out of period revenue recognition correction for electronic flow measurement fees recorded prior to 2003 that should have been deferred and recognized over the contract period. See Note 4 of the Notes to Consolidated Financial Statements. The amount shown in Note 4 for this correction is net of the related $1.4 million decrease in depreciation expense.

Gathering and processing revenues decreased $1.8 million, or 3%, due primarily to a $1.2 million decrease in the average rate charged for these services and $0.6 million from a 1% decrease in gathered and processed volumes. The decrease in the average rate was due primarily to a lower rate on one of our agreements that is adjusted annually based on the price of natural gas on January 1. The price of natural gas was substantially higher on January 1, 2006 than on January 1, 2007.

Product cost and shrink replacement increased $4.0 million, or 9%, due primarily to a $4.3 million increase from third party producers who elected to have us purchase their NGLs, which was offset by the corresponding increase in product sales revenues discussed above.

Operating and maintenance expense increased $4.3 million, or 14%, due primarily to:

	•		$5.5 million higher non-shrink natural gas purchases caused primarily by $3.7 million higher system losses. During the third quarter of 2007 our volumetric loss, as a percentage of total volume received, was higher than in 2006. System losses are an unpredictable component of our operating costs. Given the scale of throughput on Four Corners’ system, relatively small percentage product losses can generate a fairly significant impact to operating costs.

	•		$1.7 million higher leased compression costs under agreements that are currently being renegotiated but are at present under month-to-month terms.

	•		$1.3 million higher rent expense related to the purchase of a temporary special business license upon the expiration of a right-of-way agreement.

Partially offsetting these increases were $4.2 million in lower materials and supplies and outside services expense including the absence of the $2.0 million third quarter 2006 adjustment discussed in Note 4 of the Notes to Consolidated Financial Statements.

The $1.5 million, or 15%, decrease in depreciation, amortization and accretion expense includes $1.4 million lower expense resulting from the electronic flow measurement fees correction mentioned previously.

General and administrative expense — direct decreased $1.0 million, or 35%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense but not in our segment results.

Segment profit decreased $4.5 million, or 10%, due primarily to $4.3 million higher operating and maintenance expense, $3.7 million lower miscellaneous revenue and $1.8 million lower gathering and processing revenues, partially offset by $2.7 million higher product sales margins, $1.5 million lower depreciation expense including the effect of the out of period correction and $1.0 million lower direct general and administrative expense.

Nine months ended September 30, 2007 vs. nine months ended September 30, 2006

Revenues increased $3.4 million, or 1%, due primarily to higher product sales, partially offset by lower gathering, processing and other revenues. The significant components of the revenue fluctuations are addressed more fully below.

Product sales revenues increased $8.4 million due primarily to:

	•		$6.9 million related to a 6% increase in average NGL sales prices realized on sales of NGLs which we received under certain processing contracts.

	•		$5.5 million higher sales of NGLs on behalf of third party producers from whom we purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an affiliate. This increase is offset by higher associated product costs of $5.5 million discussed below.

These product sales revenue increases were offset by:

	•		$2.6 million decrease in condensate and liquefied natural gas sales due primarily to the absence of the $1.9 million second quarter 2006 adjustment discussed in Note 4 of the Notes to Consolidated Financial Statements. Prior to 2006, condensate revenue had been recognized two months in arrears.

	•		$1.3 million related to a 1% decrease in NGL volumes that we received under certain processing contracts.

Gathering and processing revenues decreased $2.2 million, or 1%, due primarily to a 1% decrease in average gathered and processed volumes.

Miscellaneous revenues decreased $2.8 million due primarily to the $3.5 million out of period revenue recognition correction mentioned previously.

Product cost and shrink replacement increased $5.9 million, or 5%, due primarily to a $5.5 million increase from third party producers who elected to have us purchase their NGLs, which was offset by the corresponding increase in product sales discussed above.

Operating and maintenance expense increased $3.3 million, or 4%, due primarily to:

	•		$3.8 million higher leased compression costs under agreements that are currently being renegotiated but are at present under month-to-month terms.

	•		$3.1 million higher non-shrink natural gas purchases caused primarily by higher fuel costs, partially offset by lower system losses.

	•		$2.6 million higher right-of-way expense related to our special business licenses with the Jicarilla Apache Nation.

Partially offsetting these increases were $6.2 million in lower costs including $5.8 million lower maintenance costs and supplies purchases.

The $1.1 million, or 4%, increase in depreciation, amortization and accretion expense includes $2.0 million of first quarter 2007 right-of-way amortization and asset retirement obligation adjustments, partially offset by $1.4 million lower expense related to the electronic flow measurement fee correction discussed previously.

General and administrative expense — direct decreased $3.1 million, or 37%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense but not in our segment results.

Other (income) expense, changed unfavorably by $4.0 million due primarily to a $3.6 million gain recognized on the sale of the LaMaquina treating facility in the first quarter of 2006.

Taxes other than income increased $0.8 million, or 13%, due primarily due to increases in the New Mexico gas processor’s tax.

Segment profit decreased $8.5 million, or 7%, due primarily to the net $7.1 million unfavorable impact of 2006 and 2007 adjustments discussed in Note 4 of the Notes to the Consolidated Financial Statements and the absence of the $3.6 million gain on the sale of the LaMaquina treating facility in 2006, partially offset by $3.1 million lower general and administrative expense — direct.

Outlook

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

	•		We anticipate that gathered volumes in the fourth quarter of 2007 will continue to increase over the previous quarters of 2007 due to improved operating conditions, sustained drilling activity, expansion opportunities and production enhancement activities by existing customers.

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

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

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

	•		Our right of way agreement with the Jicarilla Apache Nation (“JAN”), which covered certain gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006. We currently operate our gathering assets on the JAN lands pursuant to a special business license granted by the JAN which expires December 31, 2007. We are engaged in discussions with the JAN designed to result in the sale of our gathering assets which are located on or are isolated by the JAN lands. Provided the parties are able to reach an acceptable value on the sale of the subject gathering assets, our expectation is that we will nonetheless maintain partial revenues associated with gathering and processing downstream of the JAN lands and continue to operate the gathering assets on the JAN lands for an undetermined period of time beyond December 31, 2007. Based on current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the JAN lands represents approximately $20 to $30 million of Four Corners' annual gathering and processing revenue less related product costs.

Results of Operations — Gathering and Processing — Gulf

The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership interest in Discovery. This 60% ownership interest includes the 40% interest we have owned since our initial public offering (“IPO”) and the additional 20% ownership acquired from Williams on June 28, 2007. This transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was purchased from an affiliate of Williams, the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes and this discussion of results of operations have been restated to reflect the combined historical results of our investment in Discovery throughout the periods presented. We continue to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment.


	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Thousands)

Segment revenues	$	521		$	632		$	1,541		$	2,041

Costs and expenses:
Operating and maintenance expense		443			399			1,354			872
Depreciation		304			300			911			900
General and administrative expense — direct		—			—			—			9



Total costs and expenses		747			699			2,265			1,781


Segment operating income (loss)		(226	)		(67	)		(724	)		260
Equity earnings — Discovery (60%)		7,902			6,083			15,708			15,275


Segment profit	$	7,676		$	6,016		$	14,984		$	15,535

Carbonate Trend

Segment operating loss for the three and nine months ended September 30, 2007 increased $0.2 million and $1.0 million, respectively, as compared to the three and nine months ended September 30, 2006, due primarily to higher insurance premiums related to the increased hurricane activity in the Gulf Coast region in recent years. In addition, gathering revenues decreased due to 20% and 27% declines in average daily gathered volumes, respectively. These volumetric declines are caused by normal reservoir depletion that was not offset by new sources of throughput.

Discovery Producer Services — 100 %


	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Thousands)

Revenues	$	60,110		$	47,418		$	176,095		$	142,454

Costs and expenses, including interest:
Product cost and shrink replacement		34,538			26,862			107,945			84,310
Operating and maintenance expense		5,751			3,864			21,265			13,918
Depreciation and accretion		6,243			6,380			19,234			19,133
General and administrative expense		579			372			1,702			1,606
Interest income		(389	)		(608	)		(1,472	)		(1,835	)
Other (income) expense, net		220			410			1,242			(136	)


Total costs and expenses, including interest		46,942			37,280			149,916			116,996


Net income	$	13,168		$	10,138		$	26,179		$	25,458


Williams Partners’ 60% interest — Equity earnings per our Consolidated Statements of Income
	$	7,902		$	6,083		$	15,708		$	15,275

Three months ended September 30, 2007 vs. three months ended September 30, 2006

Revenues increased $12.7 million, or 27%, due primarily to increased product sales. Product sales increased $14.7 million, due primarily to $8.5 million from higher NGL volumes sold which Discovery received under certain processing contracts, $3.9 million increase in NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs under an option in their contracts and $2.3 million related to higher NGL prices Discovery received for these NGLs.

These product sales increases were partially offset by:

	•		$0.6 million lower transportation revenues due to $1.9 million from lower average transportation rates partially offset by $1.3 million from higher transportation volumes.

	•		Fee-based gathering, processing and fractionation revenues that decreased $1.6 million due primarily to reduced fee-based revenues related to processing Texas Eastern Transmission Company (“TETCO”) open season volumes. In 2006 the open season agreements included fee-based processing and fractionation. Our current agreement with TETCO includes processing services based on a percent-of-liquids contract, where the NGLs we take as compensation are reflected in the higher product sales discussed above.

Product cost and shrink replacement increased $7.7 million, or 29%, due primarily to $3.8 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs and $2.6 million for higher volumetric natural gas requirements from increased processing activity.

Operating and maintenance expense increased $1.9 million, or 49%, due primarily to $0.7 million higher property insurance premiums related to the increased hurricane activity in the Gulf Coast region in prior years and other increased repair, maintenance and labor expenses.

Net income increased $3.0 million, or 30%, due primarily to $6.9 million higher gross NGL margins attributable to higher NGL sales volumes, partially offset by $1.6 million lower fee-based gathering, processing and fractionation revenues, $0.6 million lower transportation revenues and $1.9 million higher operating and maintenance expense.

Nine months ended September 30, 2007 vs. Nine months ended September 30, 2006

Revenues increased $33.6 million, or 24%, due primarily to $44.5 million increased product sales, partially offset by the reduction of $10.1 million in fee-based transportation, gathering, processing and fractionation revenues. The 2006 period included revenues from the Tennessee Gas Pipeline (“TGP”) and the TETCO open season agreements. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita. TGP’s open season contract came to an end in early 2006. TETCO’s volumes continued throughout 2006 and in October 2006 we signed a one-year contract, which is discussed further in the Outlook section. The significant components of the revenue increase are addressed more fully below.

	•		Product sales increased $44.5 million, primarily due to $31.8 million from higher NGL volumes sold under certain processing contracts, including the TETCO agreement, $6.2 million from higher average NGL prices received for these NGLs, $3.9 million increase in NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs under an option in their contracts and $2.6 million from higher sales of excess fuel and shrink replacement gas. See below for the related changes in product cost and shrink replacement for each of these product sales increases.

	•		Fee-based gathering, processing and fractionation revenues decreased $7.5 million due primarily to reduced fee-based revenues related to processing the TGP and TETCO open seasons volumes discussed above. In 2006 the open season agreements included fee-based processing and fractionation. Our current agreement with TETCO includes processing services based on a percent-of-liquids contract, where the NGLs we take as compensation are reflected in the higher product sales discussed above.

	•		Transportation revenues decreased $2.5 million, including $3.7 million in reduced fee-based revenues related to the absence of TGP and TETCO open season agreements discussed above.

Product cost and shrink replacement increased $23.6 million, or 28%, due primarily to $14.5 million higher volumetric natural gas requirements from increased processing activity, $3.7 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs and $3.0 million higher product cost associated with the excess fuel and shrink replacement gas sales discussed above.

Operating and maintenance expense increased $7.3 million, or 53%, due primarily to $3.1 million higher property insurance premiums related to the increased hurricane activity in the Gulf Coast region in prior years, $1.6 million from costs related to decommissioning two pipelines and other increased repair, maintenance and labor expenses.

Other (income) expense, net changed from $0.1 million of income in 2006 to $1.2 million of expense in 2007. The increased expense was due primarily to the loss on retirement for the two pipelines that were decomissioned and a decrease in non-cash foreign currency transaction gains. The non-cash foreign currency transaction gains resulted 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.

Net income increased $0.7 million, or 3%, due primarily to $20.9 million higher gross NGL margins on higher NGL sales volumes substantially offset by $11.2 million lower fee-based transportation, gathering, processing and fractionation revenues from the absences of the 2006 TGP and TETCO open season agreements, $7.3 million higher operating and maintenance expense and $1.3 million higher other expense.

Outlook

Discovery

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

	•		The Tahiti pipeline lateral expansion project is currently on schedule. The pipeline was installed on the sea bed in February 2007. Chevron had scheduled initial throughput to begin in mid-2008, but recently announced that it will face delays because of metallurgical problems discovered in the facility’s mooring shackles. Chevron recently announced that it expects first production by the third quarter of 2009. Discovery’s revenues from the Tahiti project are dependent on receiving throughput from Chevron. Therefore, delays Chevron experiences in bringing their production online will impact the initial timing of revenues for Discovery.

	•		Effective June 1, 2007, Discovery amended the 100 BBtu/d contract with TETCO to increase the volume to 200 BBtu/d through October 31, 2007. At the conclusion of this agreement, we expect continued throughput of about 150 BBtu/d through the first quarter of 2008 at which time we expect no further volumes under this agreement. Current flowing volumes are approximately 250 BBtu/d.

	•		With the current oil and natural gas price environment, drilling activity across the shelf and the deepwater of the Gulf of Mexico has been robust. However, the limited availability of specialized rigs necessary to drill in the deepwater areas, such as those in and around Discovery’s gathering areas, limits the ability of producers to bring identified reserves to market quickly. This will prolong the timeframe over which these reserves will be developed. We expect Discovery to be successful in competing for a portion of these new volumes.

	•		Discovery has contracted additional throughput of 70 BBtu/d and 140 BBtu/d for October and November 2007, respectively, under short-term keep-whole agreements with shippers.

	•		ATP Oil & Gas Corporation completed modifications to their Gomez facility in October 2007, which will increase the volumes to approximately 75 BBtu/d.

	•		Discovery has contracted additional throughput of approximately 25 BBtu/d increasing to approximately 50 BBtu/d in 2008 with Energy Partners Limited.

Results of Operations — NGL Services

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2007		2006		2007		2006
	(Thousands)
Segment revenues	$	15,020	$	13,347	$	41,609	$	42,393

Costs and expenses:
Operating and maintenance expense		5,824		7,220		19,085		21,481
Product cost		3,058		2,880		7,942		11,522
Depreciation and accretion		1,477		609		2,904		1,809
General and administrative expense — direct		510		279		1,478		815
Other expense, net		194		182		584		555


Total costs and expenses		11,063		11,170		31,993		36,182


Segment profit	$	3,957	$	2,177	$	9,616	$	6,211

Three months ended September 30, 2007 vs. three months ended September 30, 2006

Segment revenues increased $1.7 million, or 13%, due primarily to higher storage and product upgrade fee revenues. The significant components of the revenue fluctuations are addressed more fully below.

	•		Storage revenues increased $0.8 million due primarily to higher average storage rates.

	•		Low sulfur natural gasoline upgrade fees increased $0.7 million. This upgrade service began in late 2006.

Operating and maintenance expense decreased $1.4 million, or 19%, due primarily to $0.5 million of product losses on cavern empties in the third quarter of 2007 compared to $1.5 million of product losses in the third quarter of 2006.

Depreciation and accretion expense increased $0.9 million due primarily to a correction made in the third quarter of 2007 to year-to-date depreciation and accretion expense related to asset retirement obligation assumption changes.

Segment profit increased $1.8 million, or 82%, due primarily to the $1.4 million decrease in operating and maintenance expense discussed above and higher storage and product upgrade fee revenues, partially offset by higher depreciation and accretion expense.

Nine months ended September 30, 2007 vs. nine months ended September 30, 2006

Segment revenues decreased $0.8 million, or 2%, due primarily to lower product sales and fractionation revenues, partially offset by higher storage and product upgrade fee revenues. The significant components of the revenue fluctuations are addressed more fully below.

	•		Product sales decreased $4.0 million due to lower sales volumes. This decrease was offset by the related decrease in product cost discussed below.

	•		Fractionation revenues decreased $2.4 million due primarily to 17% lower fractionation volumes and 9% lower rates. Fractionation throughput was lower during 2007 due to a customer’s decision to fractionate a

percentage of their volumes outside of the Mid-Continent region for three months. This decision was based on current prices being paid for fractionated products outside of the Mid-Continent region. The lower fractionation rates relate to the pass through to customers of decreased fuel and power costs.

	•		Storage revenues increased $3.0 million due primarily to more contracted storage and higher average storage rates for all of 2007.

	•		Other revenue increased $2.5 million due primarily to low sulfur natural gasoline upgrade fees. This upgrade service began in late 2006.

Product cost decreased $3.6 million, or 31%, due to the lower product sales volumes discussed above, resulting in a net margin loss of $0.4 million.

Operating and maintenance expense decreased $2.4 million, or 11%, due primarily to lower fuel and power costs related to the lower fractionator throughput.

Depreciation and accretion expense increased $1.1 million, or 61%, due primarily to asset retirement obligation assumption changes.

Segment profit increased $3.4 million, or 55%, due primarily to the $2.4 million decrease in operating and maintenance expense discussed above and higher storage and product upgrade fee revenues, partially offset by lower fractionation revenues and higher depreciation and accretion expense.

Outlook

	•		Based on year-to-date storage lease renewals, we expect 2007 storage revenues will exceed 2006 levels due to strong demand for propane and butane storage as well as higher priced specialty storage services.

	•		We continue to execute a large number of storage cavern workovers and wellhead modifications to comply with KDHE regulatory requirements. We expect outside service costs to continue at current levels throughout 2007 and 2008 to ensure we remain on track to meet the regulatory compliance requirements. Our forecast for 2007 is to workover approximately 57 caverns (both complete and partial) compared to 51 cavern workovers (38 complete and 13 partial) in 2006. Through September 30, 2007 we completed 33 workovers with another 19 caverns out of service for workovers.

Financial Condition and Liquidity

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

	•		Cash and cash equivalents on hand;

	•		Cash generated from operations, including cash distributions from Discovery;

	•		Capital contributions from Williams pursuant to the omnibus agreement; and

	•		Credit facilities, as needed.

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

	•		Maintenance capital expenditures for our Four Corners and Conway assets;

	•		Expansion capital expenditures for our Four Corners assets;

	•		Interest on our long-term debt; and

	•		Quarterly distributions to our unitholders.

Discovery

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


	Total Distribution to
Date of Distribution	Members		Our Share**
1/30/07	$	9,000	$	3,600
4/30/07	$	16,000	$	6,400
6/22/07*	$	11,173	$	4,469
7/30/07	$	9,000	$	3,600
10/31/07	$	14,000	$	8,400


*		Special distribution Discovery made after receipt of insurance proceeds.

**		On June 28, 2007, we closed on the acquisition of an additional 20% limited liability company interest in Discovery. Because this acquisition was effective July 1, 2007, we did not begin to receive 60% of Discovery’s distributions until October 2007.

In 2005, Discovery’s facilities sustained damages from Hurricane Katrina. The estimated total cost for hurricane-related repairs is approximately $21.5 million, including $19.9 million in potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, $20.0 million has been spent as of September 30, 2007. Discovery is funding these repairs with cash flows from operations and is seeking reimbursement from its insurance carrier. As of September 30, 2007, Discovery has received $16.1 million from the insurance carriers and has an insurance receivable balance of $3.9 million.

Capital Contributions from Williams

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

Indemnification of environmental and related expenditures, less any related insurance recoveries, for a period of three years ending August 2008, (for certain of those expenditures), up to a cap of $14.0 million. As of September 30, 2007 we have received $3.4 million from Williams for indemnified items since inception of the agreement in

August 2005. Thus, approximately $10.6 million remains available for reimbursement of our costs on these items. Amounts expected to be incurred in 2007 related to these indemnifications are as follows:

	•		$3.8 million for capital expenditures related to KDHE-related cavern compliance at our Conway storage facilities. Approximately $2.0 million has been received through September 30, 2007.

	•		$1.2 million for our initial 40% share of Discovery’s costs for marshland restoration and repair or replacement of Paradis’ emission-control flare. Approximately $0.4 million has been received through September 30, 2007.

	•		We expect all costs to repair the partial erosion of the Carbonate Trend pipeline overburden caused by Hurricane Ivan in 2004 will be recoverable from insurance, but to the extent they are not, we will seek indemnification under the omnibus agreement.

Additionally, under the omnibus agreement, we will receive an annual credit for general and administrative expenses of $2.4 million in 2007, $1.6 million in 2008 and $0.8 million in 2009 and up to $3.4 million to fund our initial 40% share of the expected total cost of Discovery’s Tahiti pipeline lateral expansion project in excess of the $24.4 million we contributed during September 2005. As of September 30, 2007 we have received $1.6 million from Williams for this indemnification.

Although we recently acquired an additional 20% ownership interest in Discovery, Discovery-related indemnifications under the omnibus agreement continue to be based on the 40% ownership interest we held when this agreement became effective.

Credit Facilities

We may borrow up to $75.0 million under Williams’ $1.5 billion revolving credit facility, which is available for borrowings and letters of credit. Our $75.0 million borrowing limit under Williams’ revolving credit facility is available for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. At September 30, 2007, the entire $75.0 million was available for our use.

We also have a $20.0 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. We are required to reduce all borrowings under this facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility. As of September 30, 2007 we had no outstanding borrowings under the working capital credit facility.

Capital Expenditures

The natural gas gathering, treating, processing and transportation, and NGL fractionation and storage businesses are capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of:

	•		Maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives; and

	•		Expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities.

The following table provides summary information related to our and Discovery’s expected capital expenditures for 2007 and actual spending through September 30, 2007 (millions):


	Maintenance				Expansion				Total
			Through				Through				Through
Company	Total Year Estimate		Sept. 30, 2007		Total Year Estimate		Sept. 30, 2007		Total Year Estimate		Sept. 30, 2007
Conway	$	6.9	$	4.2	$	6.5	$	3.0	$	13.4	$	7.2

Four Corners		21.5		17.6		18.9		8.1		40.4		25.7
Discovery — 100%		2.7		2.5		33.8		32.0		36.5		34.5

For 2007, we estimate approximately $3.8 million of Conway’s maintenance capital expenditures will be reimbursed by Williams subject to the omnibus agreement. We expect to fund the remainder of these expenditures through cash flows from operations. These expenditures relate primarily to cavern workovers and wellhead modifications necessary to comply with KDHE regulations.

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

We expect Four Corners will continue to fund its maintenance capital expenditures through its cash flows from operations. For 2007, these expenditures include approximately $13.0 million related to well connections necessary to connect new sources of throughput for the Four Corners’ system which serve to offset the historical decline in throughput volumes. The $8.5 million balance relates to various smaller projects.

We expect Four Corners will fund its expansion capital expenditures through its cash flows from operations. For 2007, these expenditures include estimates of approximately $5.0 million for certain well connections that we believe will increase throughput volumes in late 2007 and early 2008. The $13.9 million balance relates primarily to plant and gathering system expansion projects.

We estimate approximately $0.2 million and $1.0 million of Discovery’s 2007 maintenance and expansion capital expenditures, respectively, may be reimbursed by Williams subject to the omnibus agreement. We expect Discovery will fund the remainder of its maintenance capital expenditures through its cash flows from operations. These maintenance capital expenditures relate to numerous small projects.

For 2007, we estimate that expansion capital expenditures for 100% of Discovery will be approximately $33.8 million, of which our 60% share is $20.3 million. Of the 100% amount, approximately $31.0 million is for the ongoing construction of the Tahiti pipeline lateral expansion project. Discovery is funding the originally approved expenditures with amounts previously escrowed for this project. We currently anticipate that the project will exceed the original estimate by approximately $3.5 million and that this amount will be funded with cash on hand or contributions from Discovery’s members, including us. Discovery will fund its other expansion capital expenditures either by cash calls to its members, which requires the unanimous consent of the members except in limited circumstances, or from internally generated funds.

Carbonate Trend Overburden Restoration

In compliance with applicable permit requirements, we completed a survey of portions of our Carbonate Trend pipeline to assess the impact of Hurricane Ivan in 2004 and Hurricane Katrina in 2005. As a result of this survey, we determined that it was necessary to undertake certain restoration activities to repair the partial erosion of the pipeline overburden. We completed these restoration activities during the third quarter of 2007. The surveys and repairs were funded with cash flows from operations in advance of our receiving a $2.0 million advance insurance payment in July 2007. The $0.6 million of repair costs have been offset against the $2.0 million advance payment. We anticipate we may be able to offset the remaining costs against the $1.4 million remainder of the advance payment. The completeness of these repairs is subject to regulatory approval by the U.S. Minerals Management Service, but they are under no obligation to provide us with notice of their approval. We consider the repair work to be complete.

Additionally, in the omnibus agreement, Williams agreed to reimburse us for the cost of the restoration activities related to Hurricane Ivan to the extent that we are not reimbursed by our insurance carrier and subject to an overall limitation of $14.0 million for all indemnified environmental and related expenditures generally for a period of three years that ends in August 2008.

Debt Service — Long-Term Debt

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

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

Cash Distributions to Unitholders

We have paid quarterly distributions to our unitholders and our general partner interest after every quarter since our IPO on August 23, 2005. Our most recently declared quarterly distribution of $24.3 million will be paid on November 14, 2007 to the general partner interest and common and subordinated unitholders of record at the close of business on November 7, 2007. This distribution includes an incentive distribution to our general partner of approximately $2.2 million.

Our general partner called a special meeting of common unitholders on May 21, 2007 to vote upon a proposal to approve (a) a change in the terms of our Class B units to provide that each Class B unit is convertible into one of our common units and (b) the issuance of additional common units upon such conversion (the “Class B Conversion and Issuance Proposal”). On May 21, 2007, at this meeting, by a majority vote of common units eligible to vote, the Class B units were converted into common units on a one-for-one basis.

Results of Operations — Cash Flows

Williams Partners L.P.


	Nine months ended
	September 30,
	2007			2006
	(Thousands)

Net cash provided by operating activities	$	129,065		$	116,521

Net cash used by investing activities	$	(101,369	)	$	(168,527	)

Net cash provided (used) by financing activities	$	(69,148	)	$	83,298

The $12.5 million increase in net cash provided by operating activities for the first nine months of 2007 as compared to the first nine months of 2006 is due primarily to:

•

$51.3 million increase in working capital excluding accrued interest. Cash provided by working capital increased due primarily to $25.5 million in favorable accounts receivable activity, which includes the following items in 2006:

	•		a $16.1 million increase, in 2006, in affiliate receivables as a result of our transition from Williams’ cash management program to a stand-alone cash management program; and

	•		an increase of $6.8 million from accounts receivable due from an affiliate for reimbursable compression projects.

Additionally, changes in our accounts payable and product imbalance activity between periods accounted for another $19.0 million in cash provided by working capital.

•

$2.9 million higher distributions related to the equity earnings of Discovery.

Partially, offsetting these increases were $33.2 million in cash interest payments in June and August for the interest on our $750.0 million senior unsecured notes issued in 2006 to finance our acquisition of Four Corners and $9.3 million lower operating income excluding non-cash items.

Net cash used by investing activities in 2006 includes the purchase of a 25.1% interest in Four Corners on June 20, 2006. Net cash used by investing activities in 2007 includes the closing of an additional 20% ownership interest in Discovery on June 28, 2007. Since Four Corners and Discovery were affiliates of Williams, the transactions were between entities under common control, and have been accounted for at historical cost. Therefore the amount reflected as cash used by investing activities for these purchases represents the historical cost to Williams. Additionally, net cash used by investing activities includes maintenance and expansion capital expenditures primarily used for well connects in our Four Corners business and the installation of cavern liners and KDHE-related cavern compliance with the installation of wellhead control equipment and well meters in our NGL Services segment.

Net cash provided by financing activities in 2006 included various transactions related to the financing of our purchase of the 25.1% interest in Four Corners. Net cash used by financing activities for both years also includes our quarterly distributions to unitholders.

Discovery — 100 %


	Nine months ended
	September 30,
	2007			2006
	(Thousands)

Net cash provided by operating activities	$	39,557		$	38,934

Net cash used by investing activities		(7,444	)		(9,486	)

Net cash used by financing activities		(41,252	)		(23,609	)

Net cash provided by operating activities increased $0.6 million in 2007 as compared to 2006 due primarily to a $1.4 million increase in operating income, adjusted for non-cash expenses, partially offset by a $0.8 million decrease in cash from changes in working capital.

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

Net cash used by financing activities increased $17.6 million in 2007 due to $12.6 million higher distributions paid to members and the impact of $5.0 million lower capital contributions from members to finance capital projects.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

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

Derivatives

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

Interest Rate Risk

Our long-term senior unsecured notes have fixed interest rates. Any borrowings under our credit agreements would be at a variable interest rate and would expose us to the risk of increasing interest rates. As of September 30, 2007, we did not have borrowings under our credit agreements.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d) — (e) of the Securities Exchange Act) (“Disclosure Controls”) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our general partner’s management, including our general partner’s chief executive officer and chief financial officer. Based upon that evaluation, our general partner’s chief executive officer and chief financial officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Our management, including our general partner’s chief executive officer and chief financial officer, does not expect that our Disclosure Controls or our internal controls over financial reporting (“Internal Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been

detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls will be modified as systems change and conditions warrant.

Third-Quarter 2007 Changes in Internal Control Over Financial Reporting

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

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

The information required for this item is provided in Note 8, Commitments and Contingencies, included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which information is incorporated by reference into this item.

Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006 includes certain risk factors that could materially affect our business, financial condition or future results. Those risk factors have not materially changed.

Item 6. Exhibits

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


Exhibit
Number		Description


+Exhibit 31.1		Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

+Exhibit 31.2		Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

+Exhibit 32		Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.


+		Filed herewith.

SIGNATURES

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


	WILLIAMS PARTNERS L.P. (Registrant)
	By:	Williams Partners GP LLC, its general partner


	/s/ Ted T. Timmermans
	Ted. T. Timmermans Controller (Duly Authorized Officer and Principal Accounting Officer)

November 1, 2007

EXHIBIT INDEX


Exhibit
Number		Description


+Exhibit 31.1		Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

+Exhibit 31.2		Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

+Exhibit 32		Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.


+		Filed herewith.

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