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 June 30, 2008


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 (State or other Jurisdiction of Incorporation or Organization)		20-2485124 (I.R.S. Employer Identification No.)


ONE WILLIAMS CENTER TULSA, OKLAHOMA (Address of principal executive offices)		74172-0172 (Zip Code)

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

NO CHANGE

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

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

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

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company 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 52,774,728 common units outstanding as of August 6, 2008

WILLIAMS PARTNERS L.P.
INDEX


	Page
Part I. Financial Information

Item 1. Financial Statements

Consolidated Statements of Income — Three and Six Months Ended June 30, 2008 and 2007		4

Consolidated Balance Sheets — June 30, 2008 and December 31, 2007		5

Consolidated Statements of Cash Flows — Six Months Ended June 30, 2008 and 2007		6

Consolidated Statement of Partners’ Capital from January 1, 2008 to June 30, 2008		7

Notes to Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3. Quantitative and Qualitative Disclosures About Market Risk		40

Item 4. Controls and Procedures		41

Part II. Other Information

Item 1. Legal Proceedings		42

Item 1A. Risk Factors		42

Item 6. Exhibits		44
Rule 13a-14(a) Certification of Chief Executive Officer
Rule 13a-14(a) Certification of Chief Financial Officer
Section 1350 Certifications
Financial Statements

FORWARD-LOOKING STATEMENTS

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

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

	•		amounts and nature of future capital expenditures;

	•		expansion and growth of our business and operations;

	•		business strategy;

	•		cash flow from operations;

	•		seasonality of certain business segments; and

	•		natural gas liquids and gas prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

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

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

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

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

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

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

	•		We do not own all of the interests in Wamsutter LLC, the Conway fractionator or Discovery Producer Services LLC (Discovery), which could adversely affect our ability to operate and control these assets in a manner beneficial to us.

	•		Our results of storage and fractionation operations are dependent upon the demand for propane and other NGLs. A substantial decrease in this demand could adversely affect our business and operation results.

	•		Discovery and Wamsutter may reduce their cash distributions to us in some situations.

	•		Discovery’s interstate tariff rates and terms and conditions are subject to review and possible adjustment by federal regulators, and are subject to changes in policy by federal regulators which could have a material adverse effect on our business and operating results.

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

	•		We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.

	•		Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

	•		The Williams Companies Inc.’s (Williams) public indentures and our credit facility contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.

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

	•		We may not be able to grow or effectively manage our growth.

	•		We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make payments on our debt obligations and distributions on our common units.

	•		Common units held by Williams eligible for future sale may have adverse effects on the price of our common units.

	•		Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interests with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.

	•		Even if unitholders are dissatisfied, they currently have little ability to remove our general partner without its consent.

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item IA “Risk Factors” in our Form 10-K for the year ended December 31, 2007, and Part II, Item 1A. Risk Factors of this quarterly report on Form 10-Q.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007*			2008			2007*
Revenues:
Product sales:
Affiliate	$	94,134		$	62,119		$	172,256		$	118,671
Third-party		9,741			5,070			13,962			11,383
Gathering and processing:
Affiliate		9,847			8,743			18,637			18,234
Third-party		49,548			51,422			95,758			102,525
Storage		7,102			6,818			14,435			13,228
Fractionation		4,804			2,616			8,096			4,533
Other		3,069			2,481			5,463			4,510


Total revenues		178,245			139,269			328,607			273,084

Costs and expenses:
Product cost and shrink replacement:
Affiliate		27,686			18,520			49,719			40,245
Third-party		38,323			26,157			68,388			46,627
Operating and maintenance expense (excluding depreciation):
Affiliate		16,548			10,484			39,681			24,812
Third-party		29,984			23,759			53,935			51,944
Depreciation, amortization and accretion		11,002			11,234			22,228			24,412
General and administrative expense:
Affiliate		12,385			9,644			22,261			19,050
Third-party		749			1,189			1,677			1,853
Taxes other than income		2,167			2,626			4,672			4,740
Other (income) expense — net		(2,811	)		198			(2,478	)		658


Total costs and expenses		136,033			103,811			260,083			214,341


Operating income		42,212			35,458			68,524			58,743

Equity earnings-Wamsutter		37,480			20,558			58,674			31,886
Equity earnings-Discovery Producer Services		8,570			3,875			22,191			7,806
Interest expense:
Affiliate		(15	)		(15	)		(40	)		(30	)
Third-party		(16,668	)		(14,359	)		(34,316	)		(28,714	)
Interest income		243			1,225			418			2,188


Net income	$	71,822		$	46,742		$	115,451		$	71,879


Allocation of net income:
Net income	$	71,822		$	46,742		$	115,451		$	71,879
Allocation of net income to general partner		23,008			22,417			31,919			35,329

Allocation of net income to limited partners	$	48,814		$	24,325		$	83,532		$	36,550


Basic and diluted net income per limited partner unit:
Common units	$	0.92		$	0.48		$	1.58		$	0.79

Weighted average number of units outstanding:
Common units (b)		52,774,728			39,358,798	(a)		52,774,728			39,358,798	(a)


*		Recast as discussed in Note 1.
(a)		Includes Class B units converted to Common on May 21, 2007.
(b)		Includes Subordinated units converted to Common on February 19, 2008.

See accompanying notes to consolidated financial statements.

WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS


	June 30,		December 31,
	2008		2007
	(Unaudited)
	(In thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	57,715	$	36,197
Accounts receivable:
Trade		22,042		12,860
Affiliate		39,146		20,402
Other		7,477		2,543
Product imbalance		32,858		20,660
Prepaid expense		4,668		4,056
Derivative assets — affiliate		—		231
Reimbursable projects		416		8,989
Assets held for sale		11,296		11,519
Other current assets		3,544		3,574

Total current assets		179,162		121,031

Investment in Wamsutter		294,837		284,650
Investment in Discovery Producer Services		204,753		214,526
Property, plant and equipment, net		638,964		630,770
Other noncurrent assets		29,570		32,500


Total assets	$	1,347,286	$	1,283,477


LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable:
Trade	$	34,906	$	35,947
Affiliate		34,425		17,676
Product imbalance		20,142		21,473
Deferred revenue		11,125		4,569
Derivative liabilities — affiliate		11,978		2,718
Accrued interest		19,101		19,500
Other accrued liabilities		6,982		8,243

Total current liabilities		138,659		110,126

Long-term debt		1,000,000		1,000,000
Other noncurrent liabilities		11,818		11,864
Commitments and contingent liabilities (Note 9)
Partners’ capital		196,809		161,487


Total liabilities and partners’ capital	$	1,347,286	$	1,283,477

See accompanying notes to consolidated financial statements.

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


	Six Months Ended
	June 30,
	2008			2007*
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	115,451		$	71,879
Adjustments to reconcile to cash provided by operations:
Depreciation, amortization and accretion		22,228			24,412
Amortization of gas purchase contract — affiliate		—			2,377
Gain on involuntary conversion		(3,266	)		—
Equity earnings of Wamsutter		(58,674	)		(31,886	)
Equity earnings of Discovery Producer Services		(22,191	)		(7,806	)
Distributions related to equity earnings of Wamsutter		49,307			—
Distributions related to equity earnings of Discovery Producer Services		22,191			5,204
Cash provided (used) by changes in assets and liabilities:
Accounts receivable		(32,860	)		(13,907	)
Prepaid expense		(612	)		(24	)
Other current assets		5,679			19
Accounts payable		15,708			19,761
Product imbalance		(13,529	)		(5,414	)
Deferred revenue		6,428			6,770
Accrued liabilities		(1,272	)		23,437
Derivative assets and liabilities		377			—
Other, including changes in non-current liabilities		1,925			619


Net cash provided by operating activities		106,890			95,441


INVESTING ACTIVITIES:
Purchase of equity investment		—			(69,061	)
Capital expenditures		(29,031	)		(21,703	)
Cumulative distributions in excess of equity earnings of Discovery Producer Services		10,209			9,265
Insurance proceeds		6,190			—
Change in accrued liabilities-capital expenditures		9			(2,810	)
Contributions to Wamsutter		(820	)		—
Contributions to Discovery Producer Services		(437	)		—


Net cash used by investing activities		(13,880	)		(84,309	)


FINANCING ACTIVITIES:
Distributions to unitholders		(73,204	)		(40,557	)
Proceeds from sale of common units		28,992			—
Redemption of common units from general partner		(28,992	)		—
Excess purchase price over contributed basis of equity investment		—			(8,939	)
Contributions per omnibus agreement		1,636			1,667
Other		76			—


Net cash used by financing activities		(71,492	)		(47,829	)

Increase (decrease) in cash and cash equivalents		21,518			(36,697	)
Cash and cash equivalents at beginning of period		36,197			57,541


Cash and cash equivalents at end of period	$	57,715		$	20,844


*		Recast 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			Subordinated			Partner			Loss			Capital
	(In thousands)

Balance — January 1, 2008	$	1,473,814		$	109,542		$	(1,419,382	)	$	(2,487	)	$	161,487
Net income		102,636			1,556			11,259			—			115,451
Other comprehensive income (loss):
Net unrealized losses on cash flow hedges		—			—			—			(10,373	)		(10,373	)
Reclassification into earnings of derivative instrument losses		—			—			—			1,259			1,259

Total other comprehensive loss														(9,114	)

Total comprehensive income														106,337
Cash distributions		(57,986	)		(4,025	)		(11,193	)		—			(73,204	)
Conversion of subordinated units into common		107,073			(107,073	)		—			—			—
Contributions pursuant to the omnibus agreement		—			—			1,636			—			1,636
Issuance of units to public		28,992			—			—			—			28,992
Repurchase of units from Williams		(28,992	)		—			—			—			(28,992	)
Other		(462	)		—			1,015			—			553


Balance — June 30, 2008	$	1,625,075		$	—		$	(1,416,665	)	$	(11,601	)	$	196,809

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

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

On June 28, 2007 we closed on the acquisition of an additional 20% interest in Discovery from Williams Energy, L.L.C. and Williams Energy Services, LLC, bringing our total ownership of Discovery to 60%. This transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was purchased from an affiliate of The Williams Companies, Inc. (Williams), the transaction was between entities under common control and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes have been recast to reflect the combined historical results of our investment in Discovery throughout the periods presented. The effect of recasting our financial statements to account for this common control exchange increased net income $2.6 million through June 30, 2007. This acquisition had no impact on earnings per unit as pre-acquisition earnings were allocated to our general partner.

On December 11, 2007, we acquired certain ownership interests in Wamsutter, consisting of 100% of the Class A limited liability company interests and 20 Class C units representing 50% of the initial Class C ownership interests (collectively the Wamsutter Ownership Interests). Because the Wamsutter Ownership Interests were purchased from an affiliate of Williams, the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes have been recast to reflect the combined historical results of our investment in Wamsutter throughout the periods presented. The effect of recasting our financial statements to account for this common control exchange increased net income $31.9 million through June 30, 2007. This acquisition does not impact earnings per unit as pre-acquisition earnings were allocated to our general partner.

The accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K, filed February 26, 2008, for the year ended December 31, 2007. The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at June 30, 2008, and results of operations for the three and six months ended June 30, 2008 and 2007 and cash flows for the six months ended June 30, 2008 and 2007. All intercompany transactions have been eliminated. Certain amounts have been reclassified to conform to the current classifications.

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

Note 2. Recent Accounting Standards

In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” currently establishes the disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 amends and expands the disclosure requirements of Statement 133 with enhanced quantitative, qualitative and credit risk disclosures. The Statement requires quantitative disclosure in a tabular format about the fair values of derivative instruments in the balance sheet, gains and losses on derivative instruments in the statement of income and information about where these items are reported in the financial statements. Also required in the tabular presentation is a separation of hedging and non-hedging activities. Qualitative disclosures include outlining objectives and strategies for using derivative instruments in terms of underlying risk exposures, use of derivatives for risk management and other purposes and accounting designation, and an understanding of the volume and purpose of derivative activity. Credit risk disclosures provide information about credit risk related contingent features included in derivative agreements. SFAS No. 161 also amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to clarify that disclosures about concentrations of credit risk should include derivative instruments. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We plan to apply this Statement beginning in 2009. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We will assess the application of this Statement on our disclosures in our consolidated financial statements.

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

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 six months ended June 30, 2008 and 2007 is as follows (in thousands):


	Three months ended						Six months ended
	June 30,						June 30,
	2008			2007			2008			2007

Allocation to general partner:
Net income	$	71,822		$	46,742		$	115,451		$	71,879
Net income applicable to pre-partnership operations allocated to general partner		—			(21,849	)		—			(34,488	)
Beneficial conversion of Class B units*		—			(5,308	)		—			(5,308	)
Reimbursable general and administrative costs charged directly to general partner		398			598			796			1,190


Income subject to 2% allocation of general partner interest		72,220			20,183			116,247			33,273
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		1,444			403			2,325			665
Incentive distributions paid to general partner**		5,499			965			9,730			1,568
Direct charges to general partner		(398	)		(598	)		(796	)		(1,190	)
Pre-partnership net income allocated to general partner		—			21,849			—			34,488


Net income allocated to general partner	$	6,545		$	22,619		$	11,259		$	35,531


Net income	$	71,822		$	46,742		$	115,451		$	71,879
Net income allocated to general partner		6,545			22,619			11,259			35,531


Net income allocated to limited partners	$	65,277		$	24,123		$	104,192		$	36,348


*		During the second quarter of 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 made a $5.3 million non-cash allocation of income to the Class B units representing the Class B unit beneficial conversion feature. 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). The conversion affects net income available to limited partners and should be excluded for calculation of earnings per limited partner unit; however, 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 months ended June 30, 2008 is $22.0 million and the assumed incentive distribution for the six months ended June 30, 2008 is $30.4 million. There were no assumed incentive distributions for the three and six months ended June 30, 2007.

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

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


									General Partner
											Incentive
	Per Unit		Common		Subordinated		Class B				Distribution		Total Cash
Payment Date	Distribution		Units		Units		Units		2%		Rights		Distribution
2/14/2007	$	0.4700	$	12,010	$	3,290	$	3,198	$	390	$	603	$	19,491
5/15/2007	$	0.5000	$	12,777	$	3,500	$	3,403	$	421	$	965	$	21,066
8/14/2007	$	0.5250	$	16,989	$	3,675		—	$	447	$	1,267	$	22,378
11/14/2007	$	0.5500	$	17,799	$	3,850		—	$	487	$	2,211	$	24,347
2/14/2008	$	0.5750	$	26,321	$	4,025		—	$	706	$	4,231	$	35,283
5/15/2008	$	0.6000	$	31,665		—		—	$	758	$	5,498	$	37,921
8/14/2008 (a)	$	0.6250	$	32,984		—		—	$	811	$	6,765	$	40,560


(a)		The board of directors of our general partner declared this cash distribution on July 28, 2008 to be paid on August 14, 2008 to unitholders of record at the close of business on August 7, 2008.

Note 4. Assets Held for Sale

Our right of way agreement with the Jicarilla Apache Nation (JAN), which covered certain gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006. We currently operate our gathering assets on the JAN lands pursuant to a special business license granted by the JAN which expires on August 31, 2008, and are negotiating with the JAN to sell them these gathering assets. Although the special business license required the execution of a purchase and sale agreement for these gathering assets on or before May 31, 2008, we continue to operate the gathering assets under the terms of the special business license and it is our expectation that we will continue to operate these assets past the completion date of negotiations with the JAN. It is anticipated that if this sale is completed, it will be completed during the fourth quarter of 2008 or the first quarter of 2009. As a result of the maturation of negotiations during the first quarter of 2008, these assets were classified as held for sale on the consolidated balance sheet and include property, plant and equipment. Our management believes the expected proceeds from the sale of these assets will substantially exceed their carrying value of $11.3 million. The gathering system assets being sold are part of the Gathering and Processing — West segment.

Note 5. Equity Investments

Wamsutter

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

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


	June 30,			December 31,
	2008			2007
	(Unaudited)
Current assets	$	30,104		$	27,114
Property, plant and equipment, net		275,820			275,163
Non-current assets		157			191
Current liabilities		(10,823	)		(13,016	)
Non-current liabilities		(3,015	)		(2,740	)


Members’ capital	$	292,243		$	286,712


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
	(Unaudited)
Revenues:
Affiliate	$	49,754	$	21,410	$	99,804	$	43,689
Third-party		20,468		19,124		38,043		37,018
Costs and expenses:
Affiliate		17,277		7,595		50,491		23,769
Third-party		15,465		12,381		28,682		25,052


Net income	$	37,480	$	20,558	$	58,674	$	31,886

Discovery Producer Services LLC

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


	June 30,			December 31,
	2008			2007
	(Unaudited)
Current assets	$	75,832		$	78,035
Non-current restricted cash and cash equivalents		3,658			6,222
Property, plant and equipment, net		357,963			368,228
Current liabilities		(32,988	)		(33,820	)
Non-current liabilities		(12,704	)		(12,216	)


Members’ capital	$	391,761		$	406,449


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Unaudited)
Revenues:
Affiliate	$	71,911		$	48,635		$	149,917		$	93,168
Third-party		10,972			14,869			20,122			22,817
Costs and expenses:
Affiliate		32,222			24,017			70,468			47,172
Third-party		36,559			32,414			63,179			56,534
Interest income		(186	)		(422	)		(450	)		(1,083	)
Loss on sale of operating assets		2			1,071			2			603
Foreign exchange loss (gain)		4			(36	)		(143	)		(252	)


Net income	$	14,282		$	6,460		$	36,983		$	13,011

Note 6. Long-Term Debt and Credit Facilities

Long-Term Debt

Long-term debt at June 30, 2008 and December 31, 2007 is as follows:


	Interest			June 30,		December 31,
	Rate			2008		2007
	(In millions)
Credit agreement term loan, adjustable rate, due 2012		(a	)	$	250	$	250
Senior unsecured notes, fixed rate, due 2017		7.25	%		600		600
Senior unsecured notes, fixed rate, due 2011		7.50	%		150		150


Total Long-term debt				$	1,000	$	1,000


(a)		3.225% at June 30, 2008.

Credit Facilities

We have a $450.0 million senior unsecured credit agreement with Citibank, N.A. as administrative agent, comprised initially of a $200.0 million revolving credit facility available for borrowings and letters of credit and a $250.0 million term loan. Under certain conditions, the revolving credit facility may be increased up to an additional $100.0 million. Borrowings under this agreement must be repaid by December 11, 2012. At June 30, 2008, we had a $250.0 million term loan outstanding under the term loan provisions and no amounts outstanding under the revolving credit facility.

We also have a $20.0 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the credit facility will mature on June 20, 2009. We are required to and have reduced 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 June 30, 2008, we had no outstanding borrowings under the working capital credit facility.

Note 7. Partners’ Capital

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

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

Note 8. Fair Value Measurements

Adoption of SFAS No.157

SFAS No. 157, “Fair Value Measurements” (1) establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, (2) provides guidance on the methods used to estimate fair value and (3) expands disclosures about fair value measurements. On January 1, 2008, we adopted SFAS No. 157 for our assets and liabilities, which are measured at fair value on a recurring basis, primarily our commodity derivatives. Upon applying SFAS No. 157, we changed our valuation methodology to consider our non-performance risk in estimating the fair value of our liabilities. Applying SFAS No. 157 had no material impact on

our consolidated financial statements. In February 2008, the FASB issued FSP No. FAS 157-2 permitting entities to delay application of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, we will apply SFAS No. 157 fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. We are evaluating the impact of this application on our consolidated financial statements. SFAS No. 157 requires two distinct transition approaches; (i) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (ii) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable. Upon adopting SFAS No. 157, we applied a prospective transition as we did not have financial instrument transactions that required a cumulative-effect adjustment to beginning retained earnings.

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

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

	•		Level 1 — Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

	•		Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured.

	•		Level 3 — Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued with valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

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

At June 30, 2008 all of our derivative liabilities which are valued at fair value are included in Level 3 and include $12.0 million of energy commodity derivative liabilities. These derivatives include commodity based financial swap contracts.

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

The following table sets forth a reconciliation of changes in the fair value of net derivatives classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2008.

Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Three Months Ended June 30, 2008
(In thousands)


	Net Derivative
	Asset (Liability)
Balance as of April 1, 2008	$	(33	)
Realized and unrealized gains (losses):
Included in net income		(357	)
Included in other comprehensive income		(12,832	)
Purchases, issuances, and settlements		1,244
Transfers in/(out) of Level 3		—

Balance as of June 30, 2008	$	(11,978	)


Unrealized gains (losses) included in net income relating to instruments still held at June 30, 2008	$	(377	)

Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Six Months Ended June 30, 2008
(In thousands)


	Net Derivative
	Asset (Liability)
Balance as of January 1, 2008	$	(2,487	)
Realized and unrealized gains (losses):
Included in net income		(357	)
Included in other comprehensive income		(10,373	)
Purchases, issuances, and settlements		1,239
Transfers in/(out) of Level 3		—

Balance as of June 30, 2008	$	(11,978	)


Unrealized gains (losses) included in net income relating to instruments still held at June 30, 2008	$	(377	)

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

Note 9. Commitments and Contingencies

Environmental Matters-Four Corners. Current federal regulations require that certain unlined liquid containment pits located near named rivers and catchment areas be taken out of use, and current state regulations 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 of our pits that were slated for closure under those regulations. We are presently awaiting agency approval of the closures for 40 to 50 of those pits.

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

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

In March 2008, the Environmental Protection Agency (EPA) proposed a penalty of $370,000 for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant and for alleged permit violations at our Ute “E” compressor station. We met with the EPA and are exchanging information in order to resolve the issues.

In July 2008, the NMED issued an NOV to Four Corners for alleged exceedances of volatile organic compounds at our Pump Mesa Central Delivery Point and proposed a penalty of approximately $100,000. We are investigating the matter and will respond to the NMED.

We have accrued liabilities totaling $1.5 million at June 30, 2008 for these environmental activities. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by governmental authorities, negotiations with the applicable agencies, and other factors.

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

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

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

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

Grynberg. In 1998, the Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries, and us. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg had 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 would not intervene in any of the Grynberg cases. 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 remained pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In 2005, the court-appointed special master entered a report which recommended that the claims against certain Williams’ subsidiaries, including us, be dismissed. In October 2006, the District Court dismissed all claims against us, and in November 2006, Grynberg filed his notice of appeals with the Tenth Circuit Court of Appeals.

GE Litigation. General Electric International, Inc. (GEII) worked on turbines at our Ignacio, New Mexico plant. We disagree with GEII on the quality of GEII’s work and the appropriate compensation. GEII asserts that it is entitled to additional extra work charges under the agreement, which we deny are due. In 2006 we filed suit in federal court in Tulsa, Oklahoma against GEII, GE Energy Services, Inc., and Qualified Contractors, Inc. We alleged, among other claims, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation and sought unspecified damages. In 2007, the defendants and GEII filed counterclaims in the amount of $1.9 million against us that alleged breach of contract and breach of the duty of good faith and fair dealing. Trial has been set for October 20, 2008.

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

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

Note 10. Segment Disclosures

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


				Gathering &
	Gathering &			Processing -			NGL
	Processing - West			Gulf			Services		Total
	(In thousands)
Three Months Ended June 30, 2008:

Segment revenues	$	158,563		$	546		$	19,136	$	178,245

Product cost and shrink replacement		61,144			—			4,865		66,009
Operating and maintenance expense		36,677			519			9,336		46,532
Depreciation, amortization and accretion		10,136			151			715		11,002
Direct general and administrative expense		2,058			—			700		2,758
Other, net		(750	)		—			106		(644	)


Segment operating income (loss)		49,298			(124	)		3,414		52,588
Equity earnings		37,480			8,570			—		46,050


Segment profit	$	86,778		$	8,446		$	3,414	$	98,638


Reconciliation to the Consolidated Statements of Income:
Segment operating income									$	52,588
General and administrative expenses:
Allocated-affiliate										(9,846	)
Third party-direct										(530	)


Combined operating income									$	42,212


*Three Months Ended June 30, 2007:**

Segment revenues	$	125,047		$	459		$	13,763	$	139,269

Product cost and shrink replacement		42,313			—			2,364		44,677
Operating and maintenance expense		29,487			361			4,395		34,243
Depreciation, amortization and accretion		10,203			303			728		11,234
Direct general and administrative expense		1,797			—			470		2,267
Other, net		2,624			—			200		2,824


Segment operating income (loss)		38,623			(205	)		5,606		44,024
Equity earnings		20,558			3,875			—		24,433


Segment profit	$	59,181		$	3,670		$	5,606	$	68,457


Reconciliation to the Consolidated Statements of Income:
Segment operating income									$	44,024
General and administrative expenses:
Allocated-affiliate										(7,430	)
Third party-direct										(1,136	)


Combined operating income									$	35,458


*		Recast as discussed in Note 1.


			Gathering &
	Gathering &		Processing -			NGL
	Processing - West		Gulf			Services		Total
	(In thousands)
Six Months Ended June 30, 2008:

Segment revenues	$	290,896	$	1,113		$	36,598	$	328,607

Product cost and shrink replacement		108,590		—			9,517		118,107
Operating and maintenance expense		77,570		1,043			15,003		93,616
Depreciation, amortization and accretion		20,435		304			1,489		22,228
Direct general and administrative expense		3,988		—			1,244		5,232
Other, net		1,804		—			390		2,194


Segment operating income (loss)		78,509		(234	)		8,955		87,230
Equity earnings		58,674		22,191			—		80,865


Segment profit	$	137,183	$	21,957		$	8,955	$	168,095


Reconciliation to the Consolidated Statements of Income:
Segment operating income								$	87,230
General and administrative expenses:
Allocated-affiliate									(17,508	)
Third party-direct									(1,198	)


Combined operating income								$	68,524


*Six Months Ended June 30, 2007:**

Segment revenues	$	245,475	$	1,020		$	26,589	$	273,084

Product cost and shrink replacement		81,988		—			4,884		86,872
Operating and maintenance expense		62,584		911			13,261		76,756
Depreciation, amortization and accretion		22,378		607			1,427		24,412
Direct general and administrative expense		3,618		—			968		4,586
Other, net		5,008		—			390		5,398


Segment operating income (loss)		69,899		(498	)		5,659		75,060
Equity earnings		31,886		7,806			—		39,692


Segment profit	$	101,785	$	7,308		$	5,659	$	114,752


Reconciliation to the Consolidated Statements of Income:
Segment operating income								$	75,060
General and administrative expenses:
Allocated-affiliate									(14,654	)
Third party-direct									(1,663	)


Combined operating income								$	58,743


*		Recast 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 NGLs. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into three business segments:

	•		Gathering and Processing — West. Our West segment includes Four Corners and ownership interests in Wamsutter, consisting of (i) 100% of the Class A limited liability company membership interests and (ii) 50% of the initial Class C limited liability company membership interests (together, the Wamsutter Ownership Interests). We account for the Wamsutter Ownership Interests as an equity investment.

	•		Gathering and Processing — Gulf. Our Gulf segment includes (1) our 60% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline off the coast of Alabama. We account for our ownership interest in Discovery as an equity investment.

	•		NGL Services. Our NGL Services segment includes three integrated NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas.

Executive Summary

Through the second quarter of 2008, we continued to realize exceptionally strong per-unit commodity margins at Four Corners and Wamsutter, which led to significantly higher segment profit for our Gathering and Processing — West segment. Additionally, during the second quarter, gathered and processed volumes for these businesses continued to recover following the impact of the first quarter’s severe winter weather and downtime related to the November 2007 fire at the Ignacio plant. Through the second quarter of 2008, our equity method investments in Wamsutter and Discovery made cash distributions totaling $49.3 million and $32.4 million respectively, as a result of their higher 2008 net income and cash flows. Based on this combined performance, we continued our record of consecutive unitholder distribution increases since our initial public offering (IPO) with our second-quarter 2008 distribution of $0.625 per unit, which is 19% higher than the second-quarter 2007 distribution.

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2008, compared to the three and six months ended June 30, 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion. All information in the following discussion and analysis of results of operations reflects the combined historical results of our investments in Discovery and Wamsutter throughout the periods presented following our acquisition of the additional 20% interest in Discovery and the Wamsutter Ownership Interests in June and December 2007, respectively.


	Three months ended									Six months ended
	June 30,									June 30,
	2008			2007			% Change from			2008			2007			% Change from
	(Thousands)						2007⁽¹⁾			(Thousands)						2007⁽¹⁾

Revenues	$	178,245		$	139,269			+28	%	$	328,607		$	273,084			+20	%

Costs and expenses:
Product cost and shrink replacement		66,009			44,677			-48	%		118,107			86,872			-36	%
Operating and maintenance expense		46,532			34,243			-36	%		93,616			76,756			-22	%
Depreciation, amortization and accretion		11,002			11,234			+2	%		22,228			24,412			+9	%
General and administrative expense		13,134			10,833			-21	%		23,938			20,903			-15	%
Taxes other than income		2,167			2,626			+17	%		4,672			4,740			+1	%
Other (income) expense — net		(2,811	)		198		NM				(2,478	)		658		NM


Total costs and expenses		136,033			103,811			-31	%		260,083			214,341			-21	%


Operating income		42,212			35,458			+19	%		68,524			58,743			+17	%
Equity earnings — Wamsutter		37,480			20,558			+82	%		58,674			31,886			+84	%
Equity earnings — Discovery		8,570			3,875			+121	%		22,191			7,806			+184	%
Interest expense		(16,683	)		(14,374	)		-16	%		(34,356	)		(28,744	)		-20	%
Interest income		243			1,225			-80	%		418			2,188			-81	%


Net income	$	71,822		$	46,742			+54	%	$	115,451		$	71,879			+61	%


(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 June 30, 2008 vs. three months ended June 30, 2007

Revenues increased $39.0 million, or 28%, due primarily to higher revenues in our Gathering and Processing — West segment and our NGL Services segment. Revenues in our Gathering and Processing — West segment increased due primarily to higher product sales resulting from significantly higher average NGL sales prices, higher sales of NGLs on behalf of third party producers, higher NGL sales volumes and higher condensate and LNG sales. Revenues in our NGL services segment increased due primarily to higher product sales and fractionation revenue. 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 $21.3 million, or 48%, due primarily to increases in both our Gathering and Processing — West segment and our NGL Services segment. Product cost and shrink replacement in our Gathering and Processing — West segment increased due primarily to increased purchases of NGLs from third party producers who elected to have us sell their NGLs, higher average natural gas prices and increased volumetric shrink requirements. Product cost and shrink replacement in our NGL Services segment increased due primarily to the higher product sales volumes and prices. 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 $12.3 million, or 36%, due primarily to higher system losses, gathering fuel and plant material and supplies cost in our Gathering and Processing — West segment, combined with unfavorable product imbalance adjustments and higher fractionation fuel costs 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.

General and administrative expense increased $2.3 million, or 21%, due primarily to higher expenses for technical support services and other support services allocated by Williams to us for administrative support functions.

Other (income) expense — net improved $3.0 million due primarily to a $3.2 million 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire and is explained further in the “— Results of Operations — Gathering and Processing — West” section.

Operating income increased $6.8 million, or 19%, due primarily to sharply higher per-unit NGL margins, higher NGL sales volumes, an involuntary conversion gain resulting from the November 2007 Ignacio plant fire and higher net condensate and LNG margins in our Gathering and Processing — West segment. Partially offsetting these favorable variances were higher operating and maintenance expenses in all our segments and higher general and administrative expenses.

Equity earnings from Wamsutter increased $16.9 million, or 82%, due primarily to higher per-unit NGL sales margins and higher NGL sales volumes and decreased operating and maintenance expense, partially offset by higher general and administrative expense. These variances are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements, for a discussion of how Wamsutter allocates its net income between its member owners including us.

Equity earnings from Discovery increased $4.7 million, or 121%, due primarily to higher per-unit NGL sales margins and slightly lower NGL sales volumes partially offset by higher general and administrative expenses. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

Interest expense increased $2.3 million, or 16% due primarily to interest on our $250.0 million term loan issued in December 2007 to finance a portion of our acquisition of the Wamsutter Ownership Interests.

Interest income decreased $1.0 million, or 80%, due primarily to lower average cash balances and lower daily interest rates on cash balances.

Six months ended June 30, 2008 vs. six months ended June 30, 2007

Revenues increased $55.5 million, or 20%, due primarily to higher revenues in our Gathering and Processing — West segment and our NGL Services segment. Revenues in our Gathering and Processing — West segment increased due primarily to higher product sales resulting from significantly higher average NGL sales prices, higher sales of NGLs on behalf of third-party producers and higher condensate sales revenues, partially offset by lower fee-based gathering revenues from lower gathering volumes and lower NGL sales volumes received under keep-whole and percent-of-liquids processing contracts. Revenues in our NGL Services segment increased due primarily to higher product sales, fractionation and storage revenues. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

Product cost and shrink replacement increased $31.2 million, or 36%, due primarily to increases in our Gathering and Processing — West segment and our NGL Services segment. Product cost and shrink replacement increased in our Gathering and Processing — West segment due primarily to increased cost of purchases from third-party producers who elected to have us sell their NGLs, higher average natural gas prices for shrink replacement and higher condensate product cost. Product cost increased in our NGL Services segment due primarily to higher related product sales volumes and prices. 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 $16.9 million, or 22%, due primarily to higher system losses and increased gathering fuel expense in our Gathering and Processing — West segment, combined with higher storage product losses and increased fractionation fuel cost in our NGL Services segment. These changes were partially offset by the absence in 2008 of a 2007 product imbalance valuation adjustment in our NGL Services segment. These fluctuations are

discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

The $2.2 million, or 9%, decrease in depreciation, amortization and accretion reflects the absence in 2008 of $2.0 million of unfavorable first-quarter 2007 adjustments in our Gathering and Processing — West segment. This fluctuation is discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.

General and administrative expense increased $3.0 million, or 15%, due primarily to higher expenses for technical support services and other charges allocated by Williams to us for various administrative support functions.

Other (income) expense — net improved $3.1 million due primarily to a $3.2 million second quarter 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire and is explained further in the “— Results of Operations — Gathering and Processing — West” section.

Operating income increased $9.8 million, or 17%, due primarily to sharply higher per-unit NGL margins on lower sales volumes, a $3.2 million second quarter 2008 involuntary conversion gain and higher condensate sales margins in our Gathering and Processing — West segment, combined with higher fractionation and storage revenues in our NGL Services segment. Partially offsetting these favorable variances were higher operating and maintenance expenses in all our segments, lower fee-based gathering revenues in our Gathering and Processing — West segment and higher general and administrative expenses.

Equity earnings from Wamsutter increased $26.8 million, or 84%, due primarily to sharply increased per-unit margins on higher NGL sales volumes, partially offset by higher general and administrative expenses and higher depreciation and accretion expenses. These variances are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements, for a discussion of how Wamsutter allocates its net income between its member owners including us.

Equity earnings from Discovery increased $14.4 million, or 184%, due primarily to higher per-unit NGL margins on higher NGL sales and plant inlet volumes and a favorable change in other (income) expense, net, partially offset by higher general and administrative expense. This increase is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

Interest expense increased $5.6 million, or 20%, due primarily to interest on our $250.0 million term loan issued in December 2007 to finance a portion of our acquisition of the Wamsutter Ownership Interests.

Interest income decreased $1.8 million, or 81%, due primarily to lower average cash balances and lower daily interest rates on cash balances.

Results of operations — Gathering and Processing — West

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


	Three months ended					Six months ended
	June 30,					June 30,
	2008			2007		2008			2007
	(Thousands)

Revenues	$	158,563		$	125,047	$	290,896		$	245,475

Costs and expenses, including interest:
Product cost and shrink replacement		61,144			42,313		108,590			81,988
Operating and maintenance expense		36,677			29,487		77,570			62,584
Depreciation and amortization		10,136			10,203		20,435			22,378
General and administrative expense — direct		2,058			1,797		3,988			3,618
Taxes other than income		2,061			2,426		4,281			4,350
Other (income) expense — net		(2,811	)		198		(2,477	)		658


Total costs and expenses, including interest		109,265			86,424		212,387			175,576


Segment operating income		49,298			38,623		78,509			69,899
Equity earnings — Wamsutter		37,480			20,558		58,674			31,886


Segment profit	$	86,778		$	59,181	$	137,183		$	101,785

Four Corners

Three months ended June 30, 2008 vs. three months ended June 30, 2007

Revenues increased $33.5 million, or 27%, due primarily to $34.0 million higher product sales, slightly offset by $0.9 million lower gathering and processing revenue. The significant components of the revenue fluctuations are addressed more fully below.

Product sales revenues increased due primarily to:

	•		$16.5 million related to a 41% increase in average NGL sales prices realized on the sales of NGLs which we received under keep-whole and percent of liquids processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods;

	•		$9.7 million higher sales of NGLs on behalf of third party producers for whom we purchase their NGLs for a fee under their contracts. Under these arrangements, we purchase the NGLs from the third party producers and sell them to an affiliate. This increase is offset by higher associated product costs of $9.7 million discussed below;

	•		$3.8 million related to an 11% increase in NGL volumes due to the absence in 2008 of plant maintenance outages that occurred in 2007; and

	•		$3.9 million higher condensate and LNG sales due primarily to higher prices.

Product cost and shrink replacement increased $18.8 million, or 45%, due primarily to:

	•		$9.7 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;

	•		$5.7 million increase from 33% higher average natural gas prices;

	•		$2.0 million increase from 13% higher volumetric shrink requirements associated with the increased NGL volumes received under Four Corners’ keep-whole processing contracts discussed above; and

•

$1.4 million increase in condensate and LNG product cost resulting primarily from increased prices.

Operating and maintenance expense increased $7.2 million, or 24%, due primarily to:

	•		$3.4 million higher system losses. During the second quarter of 2008 our volumetric loss, as a percentage of total volume received, was higher than in 2007;

	•		$1.6 million higher gathering fuel expense related to lower customer fuel reimbursements as a result of lower throughput volumes; and

	•		$1.3 million higher plant materials and supplies expense.

Other (income) expense — net improved $3.0 million due primarily to a $3.2 million 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire.

Segment operating income increased $10.7 million, or 28%, due primarily to $12.7 million higher NGL margins caused by increased per-unit NGL margins and higher NGL sales volumes, a $3.2 million 2008 involuntary conversion gain and $2.5 million increased net condensate and LNG margins, partially offset by $7.2 million higher operating and maintenance expense.

Six months ended June 30, 2008 vs. six months ended June 30, 2007

Revenues increased $45.4 million, or 19%, due primarily to $51.5 million higher product sales revenues, partially offset by $6.2 lower gathering revenues. The significant components of the revenue fluctuations are addressed more fully below.

Product sales revenues increased $51.5 million due primarily to:

	•		$34.2 million related to a 51% increase in NGL sales prices realized on sales of NGLs which we received under keep-whole and percent-of-liquids processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods;

	•		$17.1 million higher sales of NGLs on behalf of third party producers for whom we purchase their NGLs for a fee under their contracts. Under these arrangements, we purchase the NGLs from the third party producers and sell them to an affiliate. This increase is offset by higher associated product costs of $17.1 million discussed below; and

	•		$5.3 million higher condensate sales due primarily to higher prices.

These increases were partially offset by $4.7 million related to a 7% decrease in NGL volumes that Four Corners received under keep-whole and percent-of-liquids processing contracts. The decreased NGL volumes were due primarily to lower processing volumes caused by prolonged, severe weather during early 2008 and the impact of the fire at the Ignacio gas processing plant in November 2007. The plant was shut down until January 18, 2008.

Fee-based gathering revenues decreased $6.2 million, or 7%, due primarily to $5.7 million lower revenue from a 6% decrease in gathered volumes resulting from the prolonged, severe weather during early 2008 and the impact of the fire at the Ignacio gas processing plant in November 2007.

Product cost and shrink replacement increased $26.6 million, or 32%, due primarily to:

•

$17.1 million increase from third party producers who elected to have us purchase their NGLs, which was offset by the corresponding increase in product sales discussed above;

	•		$9.1 million increase from 28% higher average natural gas prices for shrink replacement; and

	•		$1.1 million increase in condensate cost of sales.

Operating and maintenance expense increased $15.0 million, or 24%, due primarily to:

	•		$8.4 million higher system losses. During 2008 our volumetric loss, as a percentage of total volume received, was significantly higher than in 2007. While our system losses are generally an unpredictable component of our operating costs, they can be higher during periods of prolonged, severe weather, such as those we experienced during early 2008. Additionally, operating inefficiencies caused by the fire at Ignacio plant unfavorably impacted our system losses;

	•		$2.7 million higher gathering fuel expense related to lower customer fuel reimbursements as a result of lower volumes;

	•		$1.7 million increased expense related to revaluation of product imbalances; and

	•		$1.2 million higher plant materials and supplies expense.

The $1.9 million, or 9%, decrease in depreciation, amortization and accretion expense results from the absence in 2008 of a $2.0 million unfavorable first-quarter 2007 adjustment for right-of-way amortization and asset retirement obligation.

Other (income) expense — net improved $3.1 million due primarily to a $3.2 million second quarter 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire.

Segment operating income increased $8.6 million, or 12%, due primarily to $23.4 million increased NGL margins resulting from sharply higher per-unit NGL margins, $4.1 million higher condensate sales margins, a $3.2 million second quarter 2008 involuntary conversion gain and $1.9 million lower depreciation expense. Partially offsetting these increases were $15.0 million higher operating and maintenance expenses, $6.2 million lower fee-based gathering revenues and $2.6 million decreased NGL sales margin resulting from 7% lower NGL sales volumes.

Outlook

	•		We anticipated that growth capital investments we completed in 2007 to support ConocoPhillips’ and other producer customers’ drilling activity, expansion opportunities and production enhancement activities would be sufficient to offset the historical decline and slightly increase 2008 average gathering and processing volumes above 2007 levels. However, first-quarter 2008 volumes were significantly impacted by severe weather conditions that inhibited both our and our customers’ ability to access facilities and maintain production. We currently expect average gathering and processing volumes for the remainder of 2008 will be slightly higher as compared with the same period in 2007 and full year 2008 gathering and processing volumes will be slightly lower than 2007.

	•		We have realized above average net liquids margins at our gas processing plants in recent years due primarily to increasing prices for NGLs. Based on 2008 prices for NGLs and natural gas through June 30, combined with the hedging program described below, per-unit margins in 2008 could meet or exceed record levels realized in 2007. The prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are outside of our control and, in particular, NGL pricing is typically impacted negatively by recessionary economic conditions. The fluctuations and impacts due to economic conditions could change the realized margins currently expected for the remainder of 2008.

	•		We currently have financial swap contracts to hedge 5.4 million gallons of our monthly forecasted NGL sales and fixed price natural gas purchase contracts to hedge the price of our natural gas shrink replacement associated with these NGL sales for July through December 2008. The 5.4 million gallons per month represents approximately 40% of our 2007 NGL sales for these same months. On average, the per-gallon margin for the remaining forecasted sales is $0.51 per gallon. The primary purpose of these hedges is to

mitigate risk associated with ethane sales derived from keep-whole processing arrangements. Of the 5.4 million gallons, 4.2 million are ethane gallons. The average hedged margin on these forecasted keep-whole NGL sales exceeds the average margin realized on keep-whole NGL sales for 2007.

	•		We are currently experiencing restrictions in the volume of NGLs we can deliver to third-party pipelines as a result of pipeline transportation allocations. These restrictions are caused by a lack of pipeline transportation capacity and impact Four Corners’ ability to recover and sell NGLs, primarily ethane, which might otherwise have been available from its Ignacio processing plant. These restrictions will likely continue until the Overland Pass Pipeline becomes operational, which we expect will occur in the late third or early fourth quarter of this year.

	•		We anticipate that operating costs, excluding compression, gathering fuel and system gains and losses, will remain stable as compared to 2007. Compression cost increases are dependent upon the extent and amount of additional compression needed to meet the needs of our customers and the cost at which compression can be purchased, leased and operated. System gains and losses are an unpredictable component of our operating costs. Gathering fuel costs are expected to be higher in 2008 due to lower customer fuel reimbursements in 2008 as the result of lower overall volumes in 2008.

	•		Our right of way agreement with the Jicarilla Apache Nation (JAN) which covered certain gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006. We currently operate our gathering assets on the JAN lands pursuant to a special business license granted by the JAN which expires August 31, 2008, and are negotiating with the JAN to sell them these gathering assets. Although the special business license required the execution of a purchase and sale agreement for these gathering assets on or before May 31, 2008, we continue to operate the gathering assets under the terms of the special business license and it is our expectation that we will continue to operate these assets past the completion date of negotiations with the JAN. It is anticipated that if this sale is completed, it will be completed during the fourth quarter of 2008 or first quarter of 2009. Current expectations are that the final terms of the sale will allow us to maintain partial revenues associated with gathering and processing services for gas produced from the JAN lands and continued operations of the gathering assets on the JAN lands through at least 2009. We believe the expected proceeds from the sale of these assets will substantially exceed their carrying value. Based on current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the JAN lands represents approximately $20 to $30 million of Four Corners’ annual gathering and processing revenue less related product costs.

Wamsutter

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


	Three months ended						Six months ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Thousands)

Revenues	$	70,219		$	40,535		$	137,847		$	80,707

Costs and expenses, including interest:
Product cost and shrink replacement		26,426			10,584			52,456			24,882
Operating and maintenance expense		(2,586	)		2,595			9,050			9,642
Depreciation and accretion		5,214			4,440			10,441			8,698
General and administrative expense		3,621			2,411			6,839			5,231
Taxes other than income		419			400			903			822
Other income, net		(355	)		(453	)		(516	)		(454	)


Total costs and expenses		32,739			19,977			79,173			48,821


Net income	$	37,480		$	20,558		$	58,674		$	31,886


Williams Partners’ interest – equity earnings per our Consolidated Statements of Income	$	37,480		$	20,558		$	58,674		$	31,886

Three months ended June 30, 2008 vs. three months ended June 30, 2007

Revenues increased $29.7 million, or 73%, due primarily to $28.3 million higher product sales.

Product sales revenues increased $28.3 million, or 132%, due primarily to:

	•		$21.3 million related to a 76% increase in average NGL sales prices realized on sales of NGLs which Wamsutter received under keep-whole processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods.

	•		$7.4 million related to a 36% increase in NGL volumes that Wamsutter received under keep-whole processing contracts. This increase was due primarily to higher plant utilization in 2008, a lower percentage of total gas delivered from Wamsutter’s fee-based customers and overall additional keep-whole gas processed at Colorado Interstate Gas Company’s (CIG) Rawlins natural gas processing plant.

Gathering and processing revenues increased $1.0 million, or 6%, related to a 6% increase in the average fee received for these services. The average fee increased as a result of fixed annual percentage or inflation-sensitive contractual escalation clauses and incremental fee revenues from completed gathering system expansion projects.

Product cost and shrink replacement increased $15.8 million, or 150%, due primarily to:

	•		$12.4 million increase from 91% higher average natural gas prices. Gas prices in 2007 were impacted by very low local shrink replacement natural gas costs compared with other natural gas markets. Natural gas prices have returned to more comparable levels in 2008 and we do not expect a near-term return to 2007 levels.

	•		$3.8 million increase from 39% higher volumetric shrink requirements due to higher volumes processed under Wamsutter’s keep-whole processing contracts.

Operating and maintenance expense decreased $5.2 million, or 200%, due primarily to $3.5 million higher system gains and $1.8 million lower gathering fuel costs related to an increase in customer fuel reimbursement rates.

General and administrative expenses increased $1.2 million, or 50% due primarily to higher charges allocated by Williams to us for various administrative support functions.

Depreciation and accretion expense increased $0.8 million, or 17%, due primarily to new assets placed into service.

Net income increased $16.9 million, or 82%, due primarily to:

•

$12.3 million higher product sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes; and

•

$5.2 million decrease in operating and maintenance expense due to higher system gains and lower gathering fuel costs.

These increases to net income were slightly offset by $1.2 million higher general and administrative expenses.

Six months ended June 30, 2008 vs. six months ended June 30, 2007

Revenues increased $57.1 million, or 71%, due primarily to $56.1 million higher product sales. Product sales revenues increased $56.1 million, or 128%, due primarily to:

	•		$37.4 million related to a 64% increase in average NGL sales prices realized on sales of NGLs which Wamsutter received under keep-whole processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods.

	•		$16.8 million related to a 41% increase in NGL volumes that Wamsutter received under keep-whole processing contracts. This increase was primarily due to a lower percentage of total gas delivered from Wamsutter’s fee-based customers in the first quarter of 2008 due to inclement weather and additional keep-whole gas processed at Colorado Interstate Gas Company’s (CIG) Rawlins natural gas processing plant in the second quarter of 2008 compared to the second quarter of 2007.

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

Product cost and shrink replacement increased $27.6 million, or 111%, due primarily to:

	•		$19.3 million increase from 59% higher average natural gas prices. Gas prices in 2007 were impacted by very low local shrink replacement natural gas costs compared with other natural gas markets. Natural gas prices have returned to more comparable levels in 2008 and we do not expect a near-term return to 2007 levels.

	•		$9.7 million increase from 42% higher volumetric shrink requirements due to higher volumes processed under Wamsutter’s keep-whole processing contracts.

General and administrative expenses increased $1.6 million, or 31% due primarily to higher charges allocated by Williams to us for various administrative support functions and higher labor and employee related expenses.

Depreciation and accretion expense increased $1.7 million, or 20%, due primarily to new assets placed into service.

Net income increased $26.8 million, or 84%, due primarily to $28.3 million higher product sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes. Partially offsetting these increases were $1.6 million higher general and administrative expenses and $1.7 million higher depreciation and accretion expense.

Outlook

	•		Wamsutter anticipated that sustained drilling activity, expansion opportunities and production enhancement activities by producers would be sufficient to offset production declines and to increase 2008 average gathering volumes above 2007 levels. However, first-quarter 2008 volumes were significantly impacted by severe weather conditions that inhibited both Wamsutter’s and their customers’ abilities to access facilities and maintain production, resulting in lower than expected volumes. Wamsutter currently expects average gathering and processing volumes for the remainder of 2008 will be slightly higher as compared with the same period in 2007, and full year 2008 gathering and processing volumes will be approximately the same as in 2007.

	•		Total gas available for processing has increased in recent years; however, due to limited plant capacity, not all of this increased volume could be processed, resulting in gas being bypassed around the Echo Springs plant. Under normal operating conditions, this results in lower NGL volumes being received under keep- whole processing agreements relative to the volume of NGLs being received by customers under fee

			processing agreements. In 2008, Wamsutter anticipates that an agreement for processing gas at Colorado Interstate Gas Company’s (CIG) Rawlins natural gas processing plant will increase the processing capacity available to Wamsutter up to 80 million cubic feet per day (MMcf/d) or approximately 20%. The processing agreement with CIG is expected to add approximately $4.0 million in operating costs, which will be more than offset by the incremental value of the propane, butane and natural gasoline volumes sold by Wamsutter as a result of the agreement.

	•		In 2007, Wamsutter realized very high net liquids margins at its Echo Springs plant. The 2007 net liquids margins were significantly impacted by very low local shrink replacement natural gas costs as compared with other natural gas markets. Local natural gas prices have returned to more comparable levels in 2008. However, based on continued high 2008 prices for NGLs through June 30, per-unit margins in 2008 could meet or exceed record levels realized in 2007. The prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are outside of our control and, in particular, NGL pricing is typically impacted negatively by recessionary economic conditions. The fluctuations and impacts due to economic conditions could change the realized margins currently expected for the remainder of 2008.

	•		Wamsutter is currently experiencing restrictions in the volume of NGLs it can deliver to third-party pipelines as a result of higher pressures and pipeline transportation allocations. These restrictions are caused by a lack of pipeline transportation capacity and impact Wamsutter’s ability to recover and sell NGLs, primarily ethane, which might otherwise have been available from its Echo Springs processing plant. These restrictions will likely continue until the Echo Springs plant is able to deliver NGLs to Overland Pass Pipeline, which we expect will occur in the late third or early fourth quarter of this year. During the month of July, we estimate that the higher pressures and pipeline allocations resulted in a loss of approximately 2.0 million ethane gallons which Wamsutter might have otherwise extracted and sold. Wamsutter has executed agreements for an alternative delivery option, starting in July, for a portion of the NGL volumes lost due to the capacity constraints. However, NGLs utilizing this alternative delivery will likely realize lower pricing than NGLs being delivered into the traditional third-party markets. Transition to the Overland Pass Pipeline is expected to lower transportation costs by approximately 8.5 cents per gallon based on July 2008 rates to Mont Belvieu, Texas.

	•		Operating costs, excluding system gains and losses and processing fees at CIG’s Rawlins plant, are expected to approximate those in 2007. System gains and losses are an unpredictable component of Wamsutter’s operating costs.

Results of Operations – Gathering and Processing — Gulf

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


	Three months ended						Six months ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Thousands)

Segment revenues	$	546		$	459		$	1,113		$	1,020

Costs and expenses:
Operating and maintenance expense		519			361			1,043			911
Depreciation		151			303			304			607


Total costs and expenses		670			664			1,347			1,518


Segment operating loss		(124	)		(205	)		(234	)		(498	)
Equity earnings — Discovery		8,570			3,875			22,191			7,806


Segment profit	$	8,446		$	3,670		$	21,957		$	7,308

Carbonate Trend

Segment operating loss for the three and six months ended June 30, 2008 declined $0.1 million and $0.3 million, respectively, as compared to the three and six months ended June 30, 2007 due primarily to lower depreciation following the property impairment recognized in the fourth quarter of 2007.

Outlook

We are currently evaluating strategic options related to our ownership of the Carbonate Trend gathering pipeline, which include the possible sale of this asset. This asset does not contribute materially to the segment profit or cash flows of our Gathering and Processing — Gulf segment.

Discovery Producer Services — 100 %


	Three months ended						Six months ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Thousands)

Revenues	$	82,883		$	63,504		$	170,039		$	115,985

Costs and expenses, including interest:
Product cost and shrink replacement		51,359			39,889			103,599			73,407
Operating and maintenance expense		8,411			9,099			15,419			15,514
Depreciation and accretion		6,802			6,508			13,785			12,991
General and administrative expense		1,750			579			3,500			1,123
Interest income		(186	)		(422	)		(450	)		(1,083	)
Other (income) expense, net		465			1,391			(2,797	)		1,022


Total costs and expenses, including interest		68,601			57,044			133,056			102,974


Net income	$	14,282		$	6,460		$	36,983		$	13,011


Williams Partners’ 60% interest – Equity earnings per our Consolidated Statements of Income	$	8,570		$	3,875		$	22,191		$	7,806

Three months ended June 30, 2008 vs. three months ended June 30, 2007

Revenues increased $19.4 million, or 31%, due primarily to $18.9 million higher product sales resulting from:

	•		$14.8 million related to a 60% increase in average NGL sales prices realized on sales of NGLs which Discovery received under certain processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods.

	•		$5.6 million higher sales of NGLs on behalf of third party producers for whom Discovery purchases their NGLs for a fee under their contracts. This increase is offset by higher associated product costs of $5.5 million discussed below.

Product cost and shrink replacement increased $11.5 million, or 29%, due primarily to:

	•		$5.5 million higher product purchase cost for the processing customers who elected to have Discovery purchase their NGLs.

	•		$4.7 million increase from higher average natural gas prices.

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

Net income increased $7.8 million, or 121%, due primarily to $7.5 million higher NGL sales margins resulting primarily from increased per-unit margins on slightly lower NGL sales volumes, partially offset by $1.2 million higher general and administrative expense.

Six months ended June 30, 2008 vs. Six months ended June 30, 2007

Revenues increased $54.1 million, or 47%, due primarily to $52.5 million higher product sales resulting from:

	•		$26.6 million related to a 41% increase in average NGL sales prices realized on sales of NGLs which Discovery received under certain processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods.

	•		$18.7 million from 41% higher NGL volumes due primarily to an increase in volumes processed under keep-whole and percent-of-liquids processing arrangements and 7% higher plant inlet volumes.

	•		$9.2 million higher sales of NGLs on behalf of third party producers for whom Discovery purchases their NGLs for a fee under their contracts. This increase is offset by higher associated product costs of $9.2 million discussed below.

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

Product cost and shrink replacement increased $30.2 million, or 41%, due primarily to:

	•		$12.9 million from higher volumetric natural gas shrink requirements from increased keep-whole and percent-of-liquids processing activity;

	•		$9.2 million higher product purchase cost for the processing customers who elected to have Discovery purchase their NGLs;

	•		$6.0 million increase from higher average natural gas prices; and

	•		$4.2 million increase in payments to producers for the rights to process their gas.

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

General and administrative expense increased $2.4 million due primarily to a proposed increase in Discovery’s management fee charged by Williams. The management fee is in the process of being re-negotiated effective January 1, 2008 as discussed below.

Other (income) expense, net improved $3.8 million due primarily to the first quarter 2008 adjustment of $3.5 million related to the reversal of amounts previously reserved from 1998 through 2003 for system fuel and lost and unaccounted for gas in connection with the recently approved Federal Energy Regulatory Commission (FERC) settlement filing.

Net income increased $24.0 million, or 184%, due primarily to $22.4 million higher NGL sales margins resulting from increased per-unit margins on higher NGL sales and plant inlet volumes and $3.8 million favorable change in other (income) expense, net, partially offset by $2.4 million higher general and administrative expense.

Outlook

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

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

	•		Discovery’s Tahiti pipeline lateral was installed on the sea bed in February 2007. Chevron is currently working on the installation of their production facilities indicating their ongoing progress toward first production. During June 2008, Discovery connected its pipeline to Chevron’s production facility. Chevron announced that it expects first production by the third quarter of 2009. Discovery’s revenues from the Tahiti project are dependent on receiving throughput from Chevron. Therefore, delays Chevron experiences in bringing their production online impact the initial timing of revenues for Discovery.

	•		Gross processing margins have been at record high levels due to commodity prices for NGLs and natural gas, Discovery’s mix of processing contract types and its operation and optimization activities. We expect that 2008 gross processing margins will remain favorable to historical averages. However, the prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are impossible to control and, in particular, NGL pricing is typically impacted negatively by recessionary economic conditions.

	•		Discovery’s Larose gas processing plant has been operating at near capacity. We expect that additional processing volumes from the Tennessee Gas Pipeline (TGP) system in 2008 along with new month-to-month agreements with several shippers on Texas Eastern Transmission Company (TETCO) will replace most of the processing volumes previously coming from the TETCO system; therefore, the Larose plant will continue to remain at near capacity throughout 2008. In addition, Discovery has compression projects that are expected to be completed by the end of 2008, which will increase the inlet capacity of the TGP connection.

	•		In February 2008, Discovery executed agreements with LLOG Exploration Company to provide production handling, transportation, processing and fractionation services for its production from the MC 705 and 707 areas.

	•		We expect Discovery’s 2008 results will be favorably impacted by approximately $3.0 million per year due to its recently approved FERC rate filing pertaining to the regulated portion of its business.

	•		Discovery has recently received an additional dedication in four blocks of new natural gas reserves with ATP Oil and Gas Corporation (ATP) around its Gomez facility.

	•		Discovery recently contracted with ATP for three blocks in the Mirage, Morgas and Telemark areas. The capital requirements to connect these blocks to Discovery’s facilities will be funded entirely by ATP.

	•		Discovery is currently renegotiating the management fee it is charged by Williams for providing senior management guidance, legal, marketing, financial analysis, information technology, accounting and other management services to Discovery. Discovery expects an increase of approximately $1.0 million per quarter and the increase has been accrued as part of Discovery’s June year-to-date results.

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				Six months ended
	June 30,				June 30,
	2008		2007		2008		2007
	(Thousands)
Segment revenues	$	19,136	$	13,763	$	36,598	$	26,589

Costs and expenses:
Product cost		4,865		2,364		9,517		4,884
Operating and maintenance expense		9,336		4,395		15,003		13,261
Depreciation and accretion		715		728		1,489		1,427
General and administrative expense — direct		700		470		1,244		968
Other expense, net		106		200		390		390


Total costs and expenses		15,722		8,157		27,643		20,930


Segment profit	$	3,414	$	5,606	$	8,955	$	5,659

Three months ended June 30, 2008 vs. three months ended June 30, 2007

Segment revenues increased $5.4 million, or 39%, due primarily to higher product sales and fractionation revenues. The significant components of the revenue fluctuations are addressed more fully below.

	•		Product sales increased $2.7 million due to higher sales volumes combined with a 57% increase in average propane rates. This product sales increase was substantially offset by the related increase in product cost discussed below.

	•		Fractionation revenues increased $2.2 million due primarily to 74% higher average fractionation rate and a slight increase in fractionation volumes. The higher average rate is due primarily to the expiration of a fractionation contract with a cap on the per-unit fee, which limited our ability to pass through increases in fractionation fuel expense to this customer.

Product cost increased $2.5 million, or 106%, due primarily to higher product sales volumes and rates discussed above.

Operating and maintenance expense increased $4.9 million, or 112%, due primarily to $0.8 million of product losses in the second quarter of 2008 compared to $1.9 million of gains in the second quarter of 2007 and higher fractionation fuel costs of $0.9 million related to increased natural gas prices and slightly higher fractionation volumes.

Segment profit decreased $2.2 million, or 39%, due primarily to $4.9 million increase in operating and maintenance expense discussed above, partially offset by $2.2 million increase in fractionation revenues.

Six months ended June 30, 2008 vs. six months ended June 30, 2007

Segment revenues increased $10.0 million, or 38%, due primarily to higher product sales, fractionation and storage revenues. The significant components of the revenue fluctuations are addressed more fully below.

	•		Product sales increased $4.6 million due to higher sales volumes and a 35% increase in average propane prices. This increase was offset by the related increase in product cost discussed below.

	•		Fractionation revenues increased $3.6 million due primarily to a 68% higher average fractionation rate and slight increase in fractionation volumes. The higher average rate is due primarily to the expiration of a fractionation contract with a cap on the per-unit fee, which limited our ability to pass through increases in fractionation fuel expense to this customer.

	•		Storage revenues increased $1.2 million due primarily to higher average storage revenues from additional storage leases.

Product cost increased $4.6 million, or 95%, due to the higher product sales volumes and prices discussed above.

Operating and maintenance expense increased $1.7 million, or 13%, due primarily to the following:

	•		$1.5 million higher storage product losses on compared to 2007; and

	•		$1.5 million higher fractionation fuel costs related to increased natural gas prices and slightly higher fractionation volumes.

These increases were partially offset by the absence in 2008 of an unfavorable $1.4 million 2007 product imbalance valuation adjustment.

Segment profit increased $3.3 million, or 58%, due primarily to higher fractionation and storage revenues, partially offset by higher operating and maintenance expenses.

Outlook

	•		We expect 2008 storage revenues will be consistent with 2007 due to continued strong demand for NGL storage and specialty storage services.

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

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 2008 will include:

	•		cash and cash equivalents on hand;

	•		cash generated from operations, including cash distributions from Wamsutter and Discovery;

	•		insurance recoveries related to the fire at the Ignacio gas processing plant;

	•		proceeds from the sale of gathering assets to the Jicarilla Apache Nation;

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

	•		credit facilities, as needed.

We anticipate our more significant uses of cash for the remainder of 2008 to be:

	•		maintenance and expansion capital expenditures for our Four Corners and Conway assets;

	•		contributions we must make to Wamsutter LLC to fund certain of its capital expenditures;

	•		completion of the Four Corners repair expenditures related to the fire at Ignacio gas processing plant, which generally should be reimbursed by insurance approximately as they are incurred;

	•		interest on our long-term debt; and

	•		quarterly distributions to our unitholders and general partner.

Wamsutter Distributions

Wamsutter expects to make quarterly distributions of available cash to its members pursuant to the terms of its limited liability company agreement. Wamsutter made the following 2008 distributions to its members (all amounts in thousands):


	Total Distribution to
Date of Distribution	Members	Our Share
3/28/08	$25,000	$21,438
6/30/08	$30,500	$24,325

Wamsutter’s distributions in March and June included payments of approximately $7.1 million and $12.4 million, respectively, to the Class C membership interests, which are currently 50% owned by us and 50% owned by Williams. However, the Wamsutter LLC agreement provides that to the extent at the end of the fourth quarter of a distribution year, the Class A member has received less than $70.0 million, the Class C members will be required to repay any distributions received in that distribution year such that the Class A member receives $70.0 million for that distribution year. Thus, our Class A membership interest will ultimately receive the first $70.0 million of cash for any distribution year. Additionally, during the first and second quarters of 2008 Wamsutter paid us $1.3 million and $2.3 million, respectively, in transition support payments related to the amount by which Wamsutter’s general and administrative expenses exceeded a certain cap.

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 2008 distributions to its members (all amounts in thousands):


	Total Distribution to
Date of Distribution	Members	Our 60% Share
1/30/08	$28,000	$16,800
4/30/08	26,000	15,600
7/30/08	22,000	13,200

Insurance Recoveries

On November 28, 2007 the Ignacio gas processing plant sustained significant damages from a fire. The estimated total cost for fire-related repairs is approximately $32.0 million, including $31.0 million in potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, $22.0 million has been incurred through June 30, 2008. We are funding these repairs with cash flows from operations, are seeking reimbursement from our insurance carrier, and have received $12.0 million of insurance proceeds to date. Future property damage insurance proceeds will relate to the replacement of capital assets destroyed by the fire. Since the destroyed assets have been fully written off, these proceeds will result in additional involuntary conversion gains. Additionally, we will seek reimbursement from our insurance carrier for lost profits under our business interruption policy.

Sale of Gathering Assets to the Jicarilla Apache Nation

As previously discussed, we may receive a significant amount of proceeds from the potential sale of our gathering assets on the JAN lands in the fourth quarter of 2008 or first quarter of 2009. Cash proceeds resulting from this capital transaction would not be considered in the determination of the amount of subsequent quarterly distributions of available cash to our unitholders. We expect these cash proceeds would be reinvested in internal projects and/or acquisition transactions in part to offset the loss of future earnings and cash flows associated with these assets.

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 June 30, 2008, we have received $6.2 million from Williams for indemnified items since inception of the agreement in August 2005. Thus, approximately $7.8 million remains available for reimbursement of our costs not subject to the three-year limitation.

	•		Additionally, under the omnibus agreement, we will receive (1) an annual credit for general and administrative expenses of $1.6 million in 2008 and $0.8 million in 2009 and (2) 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 June 30, 2008 we have received $1.6 million from Williams for the Tahiti-related indemnification since inception.

Although in 2007 we acquired an additional 20% ownership interest in Discovery, Tahiti-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 have a $200.0 million revolving credit facility with Citibank, N.A. as administrative agent available for borrowings and letters of credit. Under certain conditions, the revolving credit facility may be increased up to an additional $100.0 million. Borrowings under this agreement must be repaid within five years. There were no amounts outstanding at June 30, 2008 under the revolving credit facility.

We also have a $20.0 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. We are required to and have reduced 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 June 30, 2008 we had no outstanding borrowings under the working capital credit facility.

Wamsutter has a $20.0 million revolving credit facility with Williams as the lender. The credit facility is available exclusively to fund working capital requirements. Wamsutter is required to reduce all borrowings under the credit facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the credit facility. As of June 30, 2008, Wamsutter 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, Wamsutter’s and Discovery’s expected capital expenditures for 2008 and actual spending through June 30, 2008 (millions):


	Maintenance				Expansion				Total
			Through				Through				Through
Company	Total Year Estimate		June 30, 2008		Total Year Estimate		June 30, 2008		Total Year Estimate		June 30, 2008
Four Corners	$	20.9	$	9.8	$	14.8	$	2.6	$	35.7	$	12.4
Conway		4.3		1.2		9.5		3.4		13.8		4.6
Wamsutter – (our share)		20.0		9.5		8.3		.9		28.3		10.4
Discovery — (our share)		4.1		0.3		9.0		1.3		13.1		1.6

The table above does not include capital expenditures related to the replacement of capital assets destroyed by the November 2007 fire at Four Corners’ Ignacio gas processing plant. We expect these expenditures to be reimbursed by insurance approximately as they are incurred. Our statement of cash flows through June 30, 2008 includes $12.1 million of these reimbursed or reimbursable capital expenditures.

We expect to fund Four Corners’ and Conway’s maintenance and expansion capital expenditures with cash flows from operations. For 2008, Four Corners’ estimate of maintenance capital expenditures includes approximately $10.0 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. Four Corners’ 2008 expansion capital expenditures relate primarily to plant and gathering system expansion projects. Both Four Corners’ actual maintenance expenditures through June 2008 and total year estimated maintenance expenditures have been reduced by $3.5 million for reimbursed prior-year well connect charges. Conway’s 2008 expansion capital expenditures relate to various small projects.

Wamsutter’s 2008 maintenance capital expenditures include approximately $18.0 million related to well connections necessary to connect new sources of throughput for the Wamsutter system which serve to offset the historical decline in throughput volumes. We expect Wamsutter will fund its maintenance capital expenditures through its cash flows from operations.

Wamsutter funds its expansion capital expenditures through capital contributions from its members as specified in its limited liability company agreement. This agreement specifies that expansion capital projects with expected

total expenditures in excess of $2.5 million at the time of approval and well connections that increase gathered volumes beyond current levels be funded by contributions from its Class B membership, which we do not own. However, our ownership of the Class A membership interest requires us to provide capital contributions related to expansion projects with expected total expenditures less than $2.5 million at the time of approval.

Discovery will fund its 2008 maintenance and expansion capital expenditures either by cash calls to its members or from its cash flows from operations.

Cash Distributions to Unitholders

We paid quarterly distributions to unitholders and our general partner interest after every quarter since our IPO on August 23, 2005. Our most recent quarterly distribution of $40.6 million will be paid on August 14, 2008 to the general partner interest and common unitholders of record at the close of business on August 7, 2008. This distribution includes an additional incentive distribution to our general partner of approximately $6.8 million.

Results of Operations — Cash Flows


	Six months ended
	June 30,
Williams Partners L.P.	2008			2007
	(Thousands)

Net cash provided by operating activities	$	106,890		$	95,441

Net cash used by investing activities		(13,880	)		(84,309	)

Net cash used by financing activities		(71,492	)		(47,829	)

The $11.4 million increase in net cash provided by operating activities for the first six months of 2008 as compared to the first six months of 2007 is due primarily to $66.3 million higher distributions from Wamsutter and Discovery. Partially offsetting this increase in net cash provided by operating activities are the following:

	•		$27.3 million decrease in cash provided by working capital excluding accrued interest. Cash provided by working capital decreased due primarily to changes in accounts receivable, product imbalance and accounts payable; and

	•		$27.8 million higher cash interest payments for the interest on our $600.0 million senior unsecured notes issued in December 2006 to finance a portion of our acquisition of Four Corners and on our $250.0 million term loan issued in December 2007 to finance a portion of our acquisition of Wamsutter.

Net cash used by investing activities in 2008 includes $12.1 million of capital expenditures for the replacement of capital assets destroyed by the November 2007 fire at Four Corners’ Ignacio gas processing plant and $6.2 million of the related insurance proceeds received for some of those capital expenditures. Additionally, net cash used by investing activities in both years 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, as well as cumulative distributions in excess of equity earnings from Discovery. Net cash used by investing activities in 2007 includes the acquisition of an additional 20% ownership interest in Discovery in June 2007.

Net cash used by financing activities is primarily comprised of quarterly distributions to unitholders which have increased 80%.


	Six months ended
	June 30,
Wamsutter 100 percent	2008			2007
	(Thousands)

Net cash provided by operating activities	$	64,935		$	37,136

Net cash used by investing activities		(11,792	)		(19,806	)

Net cash used by financing activities		(53,143	)		(17,330	)

The $27.8 million increase in net cash provided by operating activities in the first six months of 2008 as compared to the first six months of 2007 is due primarily to $28.6 million increase in operating income, as adjusted for non-cash expenses.

Net cash used by investing activities in the first six months of 2008 and 2007 is primarily comprised of capital expenditures related to the connection of new wells. Severe winter weather during the first quarter of 2008 reduced the ability to connect new wells.

Net cash used by financing activities in the first six months of 2008 is almost entirely related to cash distributions to Wamsutter’s members pursuant to the distribution provisions of Wamsutter’s limited liability company agreement. Net cash used by financing activities in the first six months of 2007 is primarily distributions of Wamsutter’s net cash flows to Williams pursuant to its participation in Williams’ cash management program.


	Six months ended
	June 30,
Discovery 100 %	2008			2007
	(Thousands)

Net cash provided by operating activities	$	55,377		$	26,139

Net cash used by investing activities		(4,505	)		(5,137	)

Net cash used by financing activities		(51,672	)		(32,252	)

The $29.2 million increase in net cash provided by operating activities in 2008 as compared to 2007 is due primarily to $25.4 million increase in operating income, as adjusted for non-cash expenses, and $5.1 million increase in cash provided by working capital.

Net cash used by financing activities increased $19.4 million in 2008 due primarily to $17.8 million higher distributions paid to members.

Fair Value Measurements

On January 1, 2008 we adopted Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements”, for our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy commodity derivatives. See Note 8 of Notes to Consolidated Financial Statements for disclosures regarding SFAS No. 157, including discussion of the fair value hierarchy levels and valuation methodologies.

At June 30, 2008, our energy derivative assets and liabilities are valued using unobservable inputs and included in Level 3. They consist of financial swap contracts that hedge future sales of NGL volumes that our Four Corners operation receives as compensation under certain processing agreements. The model used to value these financial swap contracts applies an internally developed forecast of future NGL prices at Four Corners. The forward NGL yield curve used in our pricing model is an unobservable input as comparable market data is not available. The change in the overall fair value of these transactions included in Level 3 results primarily from changes in NGL prices. The financial swap contracts are designated as cash flow hedges and reduce our exposure to and revenue impact from declining NGL prices. As such, the effective portion of net unrealized gains and losses from changes in fair value are recorded in other comprehensive income and subsequently impact earnings when the underlying hedged NGLs are sold. Our net energy derivative liability increased $11.9 million and $9.5 million during the three and six months ending June 30, 2008, respectively. The effective portion of the net unrealized loss from the change in fair value recorded in other comprehensive income was $12.8 million and $10.4 million during the three and six month periods ending June 30, 2008, respectively.


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

We are exposed to the impact of fluctuations in the market price of natural gas liquids and natural gas, as well as other market factors, such as market volatility and commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets and our long-term energy-related contracts. We manage a portion of the risks associated with these market fluctuations using various derivative contracts. The fair value of derivative contracts is subject to changes in energy-commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio.

Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95% probability that the one-day loss in fair value of the portfolio will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints. Our derivative contracts are contracts held for nontrading purposes that hedge a portion of our commodity price risk exposure from natural gas liquid sales and natural gas purchases. Certain of our derivative contracts have been designated as normal purchases or sales under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and, therefore, have been excluded from our estimation of value at risk.

The value at risk for our derivative contracts was $0.7 million at June 30, 2008, and $1.0 million at December 31, 2007.

All of the derivative contracts included in our value-at-risk calculation are accounted for as cash flow hedges under SFAS No. 133. Any change in the fair value of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

Interest Rate Risk

Our interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first six months of 2008. See Note 6 of Notes to Consolidated Financial Statements.

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 15d — (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.

Changes in Internal Control Over Financial Reporting

There have been no changes during the second quarter of 2008 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 9, 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, 2007, includes certain risk factors that could materially affect our business, financial condition or future results. Those risk factors have not materially changed except as set forth below:

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

In December 2007, we borrowed $250.0 million under the term loan portion of our new $450.0 million five-year senior unsecured credit facility. Our total outstanding long-term debt as of June 30, 2008 was $1.0 billion, representing approximately 84% of our total book capitalization.

Our debt service obligations and restrictive covenants in the indentures governing our senior unsecured notes could have important consequences. For example, they could:

	•		make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes;

	•		impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;

	•		adversely affect our ability to pay cash distributions to unitholders;

	•		diminish our ability to withstand a downturn in our business or the economy generally;

	•		require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes; limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

	•		place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance existing debt obligations will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our senior notes.

We may not be able to grow or effectively manage our growth.

A principal focus of our strategy is to continue to grow by expanding our business. Our future growth will depend upon a number of factors, some of which we can control and some of which we cannot. These factors include our ability to:

	•		identify businesses engaged in managing, operating or owning pipeline, processing, fractionation and storage assets, or other midstream assets for acquisitions, joint ventures and construction projects;

	•		control costs associated with acquisitions, joint ventures or construction projects;

	•		consummate acquisitions or joint ventures and complete construction projects;

	•		integrate any acquired or constructed business or assets successfully with our existing operations and into our operating and financial systems and controls;

	•		hire, train and retain qualified personnel to manage and operate our growing business; and

	•		obtain required financing for our existing and new operations.

A failure to achieve any of these factors would adversely affect our ability to achieve anticipated growth in the level of cash flows or realize anticipated benefits. Furthermore, competition from other buyers could reduce our acquisition opportunities or cause us to pay a higher price than we might otherwise pay.

We may acquire new facilities or expand our existing facilities to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, our new or expanded facilities may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into our operations may result in unforeseen operating difficulties, may absorb significant management attention and may require financial resources that would otherwise be available for the ongoing development and expansion of our existing operations. Future acquisitions or construction projects may require substantial new capital and could result in the incurrence of indebtedness and additional liabilities and excessive costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders. If we issue additional common units in connection with future acquisitions, unitholders’ interest in us will be diluted and distributions to unitholders may be reduced. Further, any limitations on our access to capital, including limitations caused by illiquidity in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all.


Item 6.		Exhibits

The following documents are included as exhibits to 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.

Exhibit 99.1		Williams Partners GP LLC Financial Statements.

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)

August 7, 2008

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.

Exhibit 99.1		Williams Partners GP LLC Financial Statements.