UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2009

~~For the quarterly period ended September 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		20-2485124

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

ONE WILLIAMS CENTER
TULSA, OKLAHOMA		74172-0172

(Address of principal executive offices)		(Zip Code)

(918) 573-2000

(Registrant’s telephone number, including area code)

NO CHANGE

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yeso Noo

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~~definition of “accelerated filer,” “large accelerated ~~filer,” “accelerated~~ filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filerþ		Accelerated filero		Non-accelerated filero		Smaller reporting companyo


		(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). Yeso Noþ

The registrant had 52,777,452 common units outstanding as of ~~November 5, 2008.~~April 29, 2009.

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;

	•		Financial condition and liquidity;

	•		Business strategy;

	•		Cash flow from operations and results of operations;

	•		The levels of cash distributions to unitholders;

	•		Seasonality of certain business segments; and

	•		Natural gas ~~liquids~~ and natural gas liquids 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.~~report. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The reader should carefully consider the risk factors discussed below in addition to the other information in this report. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and unitholders could lose all or part of their investment. Many of the factors that ~~will determine these~~

could adversely affect our business, results of operations and financial condition 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~~Whether we have sufficient cash from operations to enable us to maintain current levels of cash distributions or to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general ~~partner.~~partner;

	•		~~Because~~Availability of supplies (including the ~~natural decline~~uncertainties inherent in ~~production from existing wells~~assessing and ~~competitive factors, the success of our gathering and transportation businesses depends on our ability to connect new sources of~~estimating future natural gas ~~supply, which is dependent on factors beyond our control. Any decrease in supplies~~reserves), market demand, volatility of ~~natural gas could adversely affect our business~~prices, and ~~operating results.~~the availability and cost of capital;

	•		~~Lower natural gas~~Inflation, interest rates and ~~oil prices could adversely affect~~general economic conditions (including the current economic slowdown and the disruption of global credit markets and the impact of these events on our ~~fractionation~~customers and ~~storage businesses.~~suppliers);

	•		The strength and financial resources of our competitors;

	•		Development of alternative energy sources;

	•		The impact of operational and development hazards;

	•		Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation and rate proceedings;

	•		Changes in maintenance and construction costs;

	•		Changes in the current geopolitical situation;

	•		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~~exposure to the ~~price~~credit risks of ~~natural gas.~~our customers;

	•		~~We depend on certain key customers~~Risks related to strategy and ~~producers for a significant portion of~~financing, including restrictions stemming from our ~~revenues and supply of natural gas and NGLs. The loss of any of these key customers or producers could result in a decline~~debt agreements, future changes in our ~~revenues~~credit ratings and ~~cash available to pay distributions.~~the availability and cost of credit;

	•		~~The failure of counterparties to perform their contractual obligations could adversely affect our operating results, financial condition and cash available to pay distributions.~~Risks associated with future weather conditions;

	•		~~If third-party pipelines~~Acts of terrorism; 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 (Wamsutter), 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.~~

	•		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.~~

	•		Recent events in the global financial crisis have made equity and debt markets less accessible and created a shortage in the availability of credit, which could disrupt our financing plans and limit our ability to grow.

	•		~~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.~~

	•		Additional risks described in our filings with the Securities and Exchange Commission.

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.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

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 IA1A. “Risk Factors” in our annual report on Form 10-K for the year ended December 31, ~~2007,~~2008, and Part II, Item 1A. ~~Risk Factors~~“Risk Factors” of this quarterly report on Form 10-Q.

PART I — FINANCIAL INFORMATION

~~Item 1. Financial Statements~~


Item 1.		Financial Statements

WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per-unit amounts)

(Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2008			2007*			2008			2007*			2009			2008
Revenues:
Product sales:
Affiliate	$	92,421		$	75,519		$	264,677		$	194,190		$	30,872		$	78,122
Third-party		6,430			4,297			20,392			15,680			2,291			4,221
Gathering and processing:
Affiliate		9,480			9,178			28,117			27,412			10,610			8,790
Third-party		50,721			51,721			146,479			154,246			47,255			46,210
Storage		8,264			7,404			22,699			20,632			8,361			7,333
Fractionation		5,484			2,723			13,580			7,256			2,557			3,292
Other		2,913			(1,266	)		8,376			3,244			3,522			2,394


Total revenues		175,713			149,576			504,320			422,660			105,468			150,362

Costs and expenses:
Product cost and shrink replacement:
Affiliate		22,358			18,806			72,077			59,051			8,866			22,033
Third-party		35,391			30,043			103,779			76,670			11,296			30,065
Operating and maintenance expense (excluding depreciation):
Affiliate		21,220			15,275			60,901			40,087			11,759			23,133
Third-party		29,257			25,259			83,192			77,203			28,147			23,951
Depreciation, amortization and accretion		11,735			10,345			33,963			34,757			11,184			11,226
General and administrative expense:
Affiliate		10,620			10,816			32,881			29,866			11,587			9,876
Third-party		664			925			2,341			2,778			893			928
Taxes other than income		2,314			2,474			6,986			7,214			2,436			2,505
Other (income) expense — net		(5,822	)		134			(8,300	)		792

Other expense — net														1,679			333

Total costs and expenses		127,737			114,077			387,820			328,418			87,847			124,050


Operating income		47,976			35,499			116,500			94,242			17,621			26,312

Equity earnings-Wamsutter		20,801			18,472			79,475			50,358			15,321			21,194
Equity earnings-Discovery Producer Services		8,244			7,902			30,435			15,708
Interest expense:
Affiliate		(15	)		(16	)		(55	)		(46	)
Third-party		(16,422	)		(14,268	)		(50,738	)		(43,038	)
Discovery investment income														812			13,621
Interest expense														(15,116	)		(17,673	)
Interest income		249			312			667			2,556			34			175


Net income	$	60,833		$	47,901		$	176,284		$	119,780		$	18,672		$	43,629


Allocation of net income:
Allocation of net income for calculation of earnings per unit:
Net income	$	60,833		$	47,901		$	176,284		$	119,780		$	18,672		$	43,629
Allocation of net income to general partner		17,455			23,409			49,374			58,738
Allocation of net income (loss) to general partner														(372	)		5,981	(a)

Allocation of net income to limited partners	$	43,378		$	24,492		$	126,910		$	61,042		$	19,044		$	37,648	(a)


Basic and diluted net income per limited partner common unit	$	0.82		$	0.62		$	2.40		$	1.41

Weighted average number of common units outstanding		52,775,912			39,359,555	(b)		52,775,126	(b)		39,359,053	(a)(b)
Basic and diluted net income per limited partner unit:
Common units													$	0.36		$	0.71	(a)
Subordinated units													$	—		$	0.71	(a)
Weighted average number of units outstanding:
Common units														52,777,452			49,005,497
Subordinated units														—			3,769,231

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


	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
OPERATING ACTIVITIES:
Net income	$	18,672		$	43,629
Adjustments to reconcile to cash provided by operations:
Depreciation, amortization and accretion		11,184			11,226
Equity earnings of Wamsutter		(15,321	)		(21,194	)
Equity (earnings) losses of Discovery Producer Services		3,211			(13,621	)
Distributions related to equity earnings of Wamsutter		15,321			22,703
Distributions related to equity earnings of Discovery Producer Services		—			13,621
Cash provided (used) by changes in assets and liabilities:
Accounts receivable		(4,291	)		(20,212	)
Prepaid expense		(5,466	)		467
Reimbursable projects		(1,166	)		—
Other current assets		1,077			5,282
Accounts payable		(625	)		16,596
Product imbalance		(3,355	)		(835	)
Accrued liabilities		(4,729	)		(7,214	)
Deferred revenue		(4,155	)		(3,364	)
Other, including changes in non-current liabilities		2,175			1,120

Net cash provided by operating activities		12,532			48,204

INVESTING ACTIVITIES:
Capital expenditures		(6,972	)		(11,556	)
Cumulative distributions in excess of equity earnings of Discovery Producer Services		—			3,179
Cumulative distributions in excess of equity earnings of Wamsutter		322			—
Change in accrued liabilities and accounts payable-capital expenditures		(61	)		(6,574	)
Proceeds from sale of property, plant and equipment		162			—
Contributions to Wamsutter		(485	)		(22	)
Contributions to Discovery Producer Services		(3,086	)		(437	)

Net cash used by investing activities		(10,120	)		(15,410	)

FINANCING ACTIVITIES:
Distributions to unitholders		(41,617	)		(35,283	)
Proceeds from sale of common units		—			28,992
Redemption of common units from general partner		—			(28,992	)
Contributions per omnibus agreement		327			771
Other		—			76

Net cash used by financing activities		(41,290	)		(34,436	)

Decrease in cash and cash equivalents		(38,878	)		(1,642	)
Cash and cash equivalents at beginning of period		116,165			36,197

Cash and cash equivalents at end of period	$	77,287		$	34,555

See accompanying notes to consolidated financial statements.

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

~~CONSOLIDATED BALANCE SHEETS~~

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

Current assets:
Cash and cash equivalents $ 81,846 $ 36,197
Accounts receivable:
Trade 20,166 12,860
Affiliate 32,794 20,402
Other 3,233 2,543
Product imbalance 15,492 20,660
Prepaid expense 5,135 4,056
Derivative assets — affiliate 3,724 231
Reimbursable projects 954 8,989
Other current assets 3,665 3,574

Total current assets 167,009 109,512

Investment in Wamsutter 287,889 284,650
Investment in Discovery Producer Services 199,797 214,526

Gross property, plant and equipment 1,269,720 1,239,792
Less accumulated depreciation (619,536 ) (597,503 )

Property, plant and equipment, net 650,184 642,289

Other noncurrent assets 28,838 32,500

Total assets $ 1,333,717 $ 1,283,477

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities:
Accounts payable:
Trade $ 31,161 $ 35,947
Affiliate 10,011 17,676
Product imbalance 15,132 21,473
Deferred revenue 10,320 4,569
Derivative liabilities — affiliate 86 2,718
Accrued interest 10,963 19,500
Other accrued liabilities 7,715 8,243

Total current liabilities 85,388 110,126

Long-term debt 1,000,000 1,000,000
Other noncurrent liabilities 15,246 11,864
Commitments and contingent liabilities (Note 9)
Partners’ capital 233,083 161,487

Total liabilities and partners’ capital $ 1,333,717 $ 1,283,477


	Limited						Total
	Partners			General			Partners'
	Common			Partner			Capital

Balance — January 1, 2009	$	1,619,954		$	(1,416,344	)	$	203,610
Net income		11,772			6,900			18,672
Cash distributions		(33,513	)		(8,104	)		(41,617	)
Contributions pursuant to the omnibus agreement		—			327			327
Other		20			—			20

Balance — March 31, 2009	$	1,598,233		$	(1,417,221	)	$	181,012

See accompanying notes to consolidated financial statements.

~~WILLIAMS PARTNERS L.P.~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Nine Months Ended
September 30,
2008 2007*
(In thousands)
OPERATING ACTIVITIES:
Net income $ 176,284 $ 119,780
Adjustments to reconcile to cash provided by operations:
Depreciation, amortization and accretion 33,963 34,757
Amortization of gas purchase contract — affiliate — 3,566
Gain on involuntary conversion (9,276 ) —
Equity earnings of Wamsutter (79,475 ) (50,358 )
Equity earnings of Discovery Producer Services (30,435 ) (15,708 )
Distributions related to equity earnings of Wamsutter 78,296 —
Distributions related to equity earnings of Discovery Producer Services 30,435 13,106
Cash provided (used) by changes in assets and liabilities:
Accounts receivable (24,871 ) (4,056 )
Prepaid expense (1,079 ) (1,500 )
Other current assets 9,504 35
Accounts payable (12,451 ) 7,675
Product imbalance (1,173 ) 2,840
Deferred revenue 5,544 4,347
Accrued liabilities (8,544 ) 10,257
Derivative assets and liabilities 14 —
Other, including changes in noncurrent assets and liabilities 2,525 4,324

Net cash provided by operating activities 169,261 129,065

INVESTING ACTIVITIES:
Purchase of equity investment — (69,061 )
Capital expenditures (36,996 ) (33,029 )
Cumulative distributions in excess of equity earnings of Discovery Producer Services 15,165 4,964
Receipt of insurance proceeds 7,718 —
Insurance proceeds related to affiliate accounts receivable 4,483 —
Change in accrued liabilities-capital expenditures (125 ) (4,779 )
Contributions to Wamsutter (2,059 ) —
Contributions to Discovery Producer Services (437 ) —
Other — 536

Net cash used by investing activities (12,251 ) (101,369 )

FINANCING ACTIVITIES:
Distributions to unitholders (113,765 ) (62,935 )
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 2,328 2,726
Other 76 —

Net cash used by financing activities (111,361 ) (69,148 )

Increase (decrease) in cash and cash equivalents 45,649 (41,452 )
Cash and cash equivalents at beginning of period 36,197 57,541

Cash and cash equivalents at end of period �� $ 81,846 $ 16,089


*		~~Retrospectively adjusted as discussed in Note 1.~~

~~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~~similar language 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~~60% ownership interest 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 retrospectively adjusted to reflect the historical results of our total investment in Discovery throughout the periods presented. The effect of retroactively adjusting our financial statements to account for this common control exchange increased net income $2.6 million through September 30, 2007. This acquisition had no impact on earnings per unit because we allocated pre-acquisition earnings 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 retrospectively adjusted to reflect the historical results of our investment in Wamsutter throughout the periods presented. The effect of retrospectively adjusting our financial statements to account for this common control exchange increased net income $50.4 million through September 30, 2007. This acquisition does not impact earnings per unit because we allocated pre-acquisition earnings 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,~~2009, for the year ended December 31, ~~2007.~~2008. The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at ~~September 30, 2008,~~March 31, 2009, and results of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~ and cash flows for the ~~nine~~three months ended ~~September 30, 2008~~March 31, 2009 and ~~2007.~~2008. We eliminated all intercompany accounts and transactions and reclassified certain amounts 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. 161 amends and expands the disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”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. The Statement also requires a separation of hedging and non-hedging activities in tabular presentation. 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. Application of this Statement will increase the 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,~~Previously, under ~~current~~ generally accepted accounting principles, we ~~calculate~~calculated earnings per unit as if all the earnings for the period had been ~~distributed. This results~~distributed, which resulted 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~~exceeded 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,~~We adopted EITF Issue No. 07-4 in January 2009, and ~~must be~~have retrospectively applied it to all periods presented. ~~Early application is prohibited. Retrospective~~The retrospective application of this guidance ~~will result in a decrease in~~decreased the income allocated to the general partner and ~~an increase in~~increased the income allocated to limited partners for the amount that any assumed incentive distribution exceeded the actual incentive distribution ~~paid~~calculated during that period. ~~Application~~Certain of our historical periods’ earnings per unit have been revised as a result of this ~~Statement is not expected~~change. Earnings per unit for the three months ended March 31, 2008 increased from $0.66 per unit to ~~have a material~~$0.71 per unit. Adoption of this new standard only impacts the allocation of earnings for purposes of calculating our earnings per limited partner unit and has no impact on our ~~Consolidated~~results of operations, allocation of earnings to capital accounts, or distributions of available cash to unitholders and our general partner.

In April 2009, the FASB issued FASB Staff Position FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial ~~Statements.~~Instruments” (FSP FAS 107-1 and APB 28-1) that would amend FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments”(SFAS No. 107),to require disclosures about the fair value of financial instruments in interim financial statements as well as in annual financial statements. This FSP applies to all financial instruments and entities within the scope of SFAS No. 107. An entity is required to disclose the fair value of all financial instruments, whether recognized or not recognized in the statement of financial position, along with the related carrying amount. An entity is also required to disclose the method(s) and significant

We paid or have authorized payment of the following cash distributions during ~~2007~~2008 and ~~2008~~2009 (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 $ 5,499 $ 37,922
8/14/2008 $ 0.6250 $ 32,984 — — $ 811 $ 6,765 $ 40,560
11/14/2008 (a) $ 0.6350 $ 33,514 — — $ 832 $ 7,272 $ 41,618


							General Partner
									Incentive
	Per Unit		Common		Subordinated				Distribution		Total Cash
Payment Date	Distribution		Units		Units		2%		Rights		Distribution
2/14/2008	$	0.5750	$	26,321	$	4,025	$	706	$	4,231	$	35,283
5/15/2008	$	0.6000	$	31,665		—	$	758	$	5,499	$	37,922
8/14/2008	$	0.6250	$	32,984		—	$	811	$	6,765	$	40,560
11/14/2008	$	0.6350	$	33,513		—	$	832	$	7,272	$	41,617
2/13/2009	$	0.6350	$	33,513		—	$	832	$	7,272	$	41,617
5/15/2009 (a)	$	0.6350	$	33,513		—	$	684		—	$	34,197


(a)		The board of directors of our general partner declared this cash distribution on ~~October 27, 2008~~April 23, 2009 to be paid on ~~November 14, 2008~~May 15, 2009 to unitholders of record at the close of business on ~~November 7, 2008.~~May 8, 2009. In April 2009, The Williams Companies, Inc. (Williams) waived the incentive distribution rights related to 2009 distribution periods. The IDRs paid in February 2009 relate to the fourth-quarter 2008 distribution to unitholders.

~~Note 4. Reclassification of Assets Previously Held for Sale~~

Effective April 1, 2008, we classified our gathering system assets located in Rio Arriba County of northern New Mexico on land owned by the Jicarilla Apache Nation (JAN) as held for sale. This classification resulted from active negotiations to sell these assets to the JAN following the expiration of our right-of-way agreement with them on December 31, 2006. During the third quarter of 2008, negotiations with the JAN changed focus from an asset sale to other alternative arrangements; therefore, we determined that it was no longer appropriate to classify these assets as held for sale, and the net book value of these assets of $11.3 million at September 30, 2008 is now presented within Property, plant and equipment, net. Concurrently, during the third quarter we recognized depreciation expense of $0.5 million on these assets, including $0.2 million pertaining to the second quarter of 2008. We currently operate these gathering assets pursuant to a special business license granted by the JAN which expires February 28, 2009. These gathering system assets are part of the Gathering and Processing — West segment.

128

Note 4. Related Party Transactions

In 2009, our omnibus agreement with Williams was amended to increase the aggregate amount of the credit we can receive related to certain general and administrative expenses for 2009. Consequently, for 2009, Williams will provide up to an additional $10.0 million credit, in addition to the $0.8 million annual credit previously provided under the original omnibus agreement, to the extent that all 2009 non-segment profit general and administrative expenses exceed $36.0 million. We will record total general and administrative expenses (including those expenses that are subject to the credit by Williams) as an expense, and we will record any credits as capital contributions from Williams. Accordingly, our net income will not reflect the benefit of the credit received from Williams. However, the cost subject to this credit will be allocated entirely to our general partner. As a result, the net income allocated to limited partners on a per-unit basis will reflect the benefit of this credit. For the three months ended March 31, 2009, the total general and administrative credit received from Williams was $0.8 million.

Note 5. Equity Investments

~~Wamsutter~~

Wamsutter allocates net income (equity earnings) to us 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~~membership 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~~member to any distributions made to the Class C ~~interest~~member until the Class A ~~interest~~member has received $70.0 million in distributions for the year. The Class B ~~interest~~member receives no income or loss allocation. As the owner of 100% of the Class A ~~ownership~~membership 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~~member and Class C ~~interest,~~member, of which we currently own ~~50%~~65%. 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, our share of Wamsutter’s net income will vary by quarter and will be higher in quarters prior to reaching the $70.0 million net income threshold. Beginning in the third quarter of 2008, having exceeded $70.0 million in net income for the 12-month distribution period which began December 1, 2007, Wamsutter’s net income is shared between the Class A interest and Class C interest. Accordingly, the Class A and Class C interests were allocated net income of $9.6 million and $22.4 million, respectively, for the third quarter of 2008 and our total equity earnings from Wamsutter was $20.8 million. Wamsutter’s net income allocation does 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):

September 30, December 31,
2008 2007
(Unaudited)
Current assets $ 23,656 $ 27,114
Property, plant and equipment, net 293,287 275,163
Other non-current assets 4 191
Current liabilities (10,039 ) (13,016 )
Non-current liabilities (4,003 ) (2,740 )

Members’ capital $ 302,905 $ 286,712

Wamsutter

Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(Unaudited)
Revenues:
Affiliate $ 38,764 $ 20,076 $ 138,568 $ 63,765
Third-party 19,056 18,075 57,099 55,093
Costs and expenses:
Affiliate 11,031 7,440 61,510 31,198
Third-party 14,782 12,239 43,476 37,302

Net income $ 32,007 $ 18,472 $ 90,681 $ 50,358

Williams Partners’ interest — equity earnings $ 20,801 $ 18,472 $ 79,475 $ 50,358


	March 31,			December 31,
	2009			2008
	(Unaudited)
Current assets	$	16,414		$	17,147
Property, plant and equipment, net		331,657			318,072
Non-current assets		782			468
Current liabilities		(15,424	)		(16,960	)
Non-current liabilities		(4,413	)		(4,353	)

Members’ capital	$	329,016		$	314,374


	Three Months Ended
	March 31,
	2009		2008
	(Unaudited)
Revenues:
Product sales:
Affiliate	$	18,377	$	45,016
Third-party		3,025		5,034
Gathering and processing services		19,384		15,015
Other revenues		2,445		2,560
Costs and expenses excluding depreciation and accretion:
Affiliate		12,611		33,214
Third-party		9,852		7,989
Depreciation and accretion		5,447		5,228

Net income	$	15,321	$	21,194


Williams Partners’ interest — equity earnings	$	15,321	$	21,194

139

~~Discovery Producer Services LLC~~

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

September 30, December 31,
2008 2007
(Unaudited)
Current assets $ 60,204 $ 78,035
Non-current restricted cash and cash equivalents 3,471 6,222
Property, plant and equipment, net 359,719 368,228
Current liabilities (23,605 ) (33,820 )
Non-current liabilities (16,287 ) (12,216 )

Members’ capital $ 383,502 $ 406,449

Discovery

Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(Unaudited)
Revenues:
Affiliate $ 53,037 $ 51,829 $ 202,954 $ 144,997
Third-party 8,243 8,281 28,365 31,098
Costs and expenses:
Affiliate 17,249 24,973 87,717 72,145
Third-party 30,224 22,452 93,403 78,986
Interest income (143 ) (389 ) (593 ) (1,472 )
Loss on sale of operating assets — — 2 603
Foreign exchange loss (gain) 208 (94 ) 65 (346 )

Net income $ 13,742 $ 13,168 $ 50,725 $ 26,179

Williams Partners’ interest — equity earnings $ 8,244 $ 7,902 $ 30,435 $ 15,708


	March 31,			December 31,
	2009			2008
	(Unaudited)
Current assets	$	61,356		$	50,978
Non-current restricted cash and cash equivalents		799			3,470
Property, plant and equipment, net		370,732			370,482
Current liabilities		(54,237	)		(45,234	)
Non-current liabilities		(20,743	)		(19,771	)

Members’ capital	$	357,907		$	359,925


	Three Months Ended
	March 31,
	2009			2008
	(Unaudited)
Revenues:
Affiliate	$	12,791		$	78,006
Third-party		7,243			9,150
Costs and expenses:
Affiliate		7,070			38,246
Third-party		18,156			26,620
Interest income		(8	)		(264	)
Foreign exchange (gain) loss		168			(147	)

Net income (loss)	$	(5,352	)	$	22,701


Discovery investment income:
Williams Partners’ interest — equity earnings (losses)	$	(3,211	)	$	13,621
Business interruption proceeds		4,023			—

Discovery investment income	$	812		$	13,621

In March 2009, we funded a $3.1 million cash call from Discovery for the Tahiti project. During the second quarter, we will receive a $1.8 million reimbursement of those funds pursuant to the requirements of our omnibus agreement with Williams. In April 2009, we funded $6.3 million representing our portion of Discovery’s cash call to partners for repair costs in excess of the deductible, net of any insurance prepayments. Once Discovery receives the remaining insurance proceeds, we expect it to make special distributions back to its members.

Note 6. Long-Term Debt and Credit Facilities

Long-Term Debt

Long-term debt at ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007~~2008 is as follows:


	Interest			September 30,		December 31,		Interest			March 31,		December 31,
	Rate			2008		2007		Rate			2009		2008
	(In millions)										(In millions)
Credit agreement term loan, adjustable rate, due 2012		(a	)	$	250	$	250		(a	)	$	250	$	250
Senior unsecured notes, fixed rate, due 2017		7.25	%		600		600		7.25	%		600		600
Senior unsecured notes, fixed rate, due 2011		7.50	%		150		150		7.50	%		150		150


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

borrowings under ~~this agreement~~the Credit Agreement by December 11, 2012. At ~~September 30, 2008,~~March 31, 2009, we had a $250.0 million term loan outstanding under the term loan provisions and no amounts outstanding under the revolving credit facility.

The Credit Agreement contains various covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur indebtedness, grant certain liens supporting indebtedness, merge, consolidate, sell all or substantially all of our assets or make distributions or other payments other than distributions of available cash under certain conditions. Significant financial covenants under the Credit Agreement include the following:

	•		We are required to maintain a ratio of consolidated indebtedness to consolidated EBITDA (each as defined in the Credit Agreement) of no greater than 5.00 to 1.00 as of the last day of any fiscal quarter. This ratio may be increased in the case of an acquisition of $50.0 million or more, in which case the ratio will be 5.50 to 1.00 for the fiscal quarter in which the acquisition occurs and three fiscal quarter-periods following such acquisition. At March 31, 2009, our ratio of consolidated indebtedness to consolidated EBITDA, as calculated under this covenant, of approximately 3.22 is in compliance with this covenant.

	•		Our ratio of consolidated EBITDA to consolidated interest expense (each as defined in the Credit Agreement) must be not less than 2.75 to 1.00 as of the last day of any fiscal quarter, unless we obtain an investment grade rating from Standard and Poor’s Ratings Services or Moody’s Investors Service and the rating from the other agency is not less than Ba1 or BB+, as applicable. At March 31, 2009, our ratio of consolidated EBITDA to consolidated interest expense, as calculated under this covenant, of approximately 4.94 is in compliance with this covenant.

Inasmuch as the ratios are calculated on a rolling four-quarter basis, these ratios do not reflect a full-year impact of the lower earnings we experienced in the fourth quarter of 2008 and the first quarter of 2009. In the event that, despite our efforts, we breach our financial covenants causing an event of default, the lenders could, among other things, accelerate the maturity of any borrowings under the facility (including our $250.0 million term loan) and terminate their commitments to lend.

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.~~requirements. Borrowings under the credit facility ~~will~~ mature on June 20, 2009. We are required to ~~and have reduced~~reduce all borrowings under ~~this~~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 ~~September 30, 2008,~~March 31, 2009, 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. 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 we had satisfied the financial test contained in our partnership agreement required for conversion of all of our outstanding subordinated units into common units. 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.

Pursuant to Williams Partners GP LLC Long-Term Incentive Plan, on August 22, 2008, our general partner granted 2,724 restricted units to members of our general partner’s board of directors who are not officers or employees of our general partner or its affiliates.

~~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, our commodity derivatives. Upon applying SFAS No. 157, we changed our valuation methodology to consider our nonperformance risk in estimating the fair value of our liabilities. Applying SFAS No. 157 did not materially impact our consolidated financial statements. In February 2008, the FASB issued Financial Staff Position (FSP) 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 at fair value 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 in the sale of 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 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.

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 September 30, 2008 all of our derivative assets and liabilities which are valued at fair value are included in Level 3 and include $3.7 million of energy commodity derivative assets and $0.1 million of energy commodity derivative liabilities. These derivatives are contracted entirely with Williams, and include commodity based financial swap contracts.

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 nine months ended September 30, 2008.

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

Net Derivative
Asset (Liability)
Balance as of July 1, 2008 $ (11,978 )
Realized and unrealized gains:
Included in net income 143
Included in other comprehensive income 10,015
Purchases, issuances, and settlements 5,458
Transfers in/(out) of Level 3 —

Balance as of September 30, 2008 $ 3,638

Unrealized gains included in net income relating to instruments still held at September 30, 2008 $ 4,962

~~Level 3 Fair-Value Measurements Using Significant Unobservable Inputs~~
~~Nine Months Ended September 30, 2008~~
~~(In thousands)~~

Net Derivative
Asset (Liability)
Balance as of January 1, 2008 $ (2,487 )
Realized and unrealized losses:
Included in net income (214 )
Included in other comprehensive income (358 )
Purchases, issuances, and settlements 6,697
Transfers in/(out) of Level 3 —

Balance as of September 30, 2008 $ 3,638

Unrealized gains included in net income relating to instruments still held at September 30, 2008 $ 4,585

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

Note 9.7. Commitments and Contingencies

Environmental Matters-Four Corners.Current federal regulations require that certain unlined liquid containment pits located near named rivers and catchment areas be taken out of use, and current state regulations 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 four 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 seven years.

In April 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued a Notice of Violation (NOV) that alleges various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. ~~The~~In December 2007, the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV that alleged air emissions permit exceedances for three glycol dehydrators at one of our ~~Pump Mesa central delivery point~~ compressor ~~facility~~facilities and proposed a penalty of approximately $103,000. We are discussing ~~the basis for and scope of the calculation of~~ the proposed penalties 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 in Colorado and for alleged permit violations at ~~our Ute “E”~~a compressor station. We met with the EPA and are exchanging information in order to resolve the issues.

We have accrued liabilities totaling $1.5 million at ~~September 30, 2008~~March 31, 2009 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

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 six years. At ~~September 30, 2008,~~March 31, 2009, we had accrued liabilities totaling $3.2 million for these costs. It is reasonably possible that we will incur ~~losses~~costs 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.

In 2004, we purchased an insurance policy that covered up to $5.0 million of remediation costs until an active remediation system was in place or April 30, 2008, whichever was earlier, excluding operation and maintenance costs and ongoing monitoring costs for these projects to the extent such costs exceeded a $4.2 million deductible. We incurred $3.1 million in costs from the onset of the policy through its termination; hence, we did not submit any claims under this insurance policy prior to its expiration. In addition, underUnder an omnibus agreement with Williams entered into at the closing of our initial public offering, Williams agreed to indemnify us for ~~the~~certain Conway environmental remediation costs, excluding costs of project management and soil and groundwater monitoring, to the extent they were not reimbursed under the insurance policy. There is a $14.0 million cap on the total amount of indemnity coverage for environmental and other items under the omnibus agreement. Of this, $7.5costs. At March 31, 2009, approximately $7.2 million remains available for future indemnification. Payments received under this indemnification are accounted for as a capital contribution to us by Williams as the costs are reimbursed.

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 ~~U. S.~~U.S. Department of Justice (DOJ) 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~~against Williams, certain of its subsidiaries (including us) and approximately 300 other energy companies. Grynberg alleged violations of the False Claims Act ~~against Williams~~in connection with the measurement, royalty valuation and ~~certain~~purchase of ~~its wholly owned subsidiaries and us.~~hydrocarbons. 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~~DOJ 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, theThe District Court dismissed all claims against ~~us,~~Williams and ~~in November 2006, Grynberg filed his notice of appeals with~~its subsidiaries, including us. On March 17, 2009, the Tenth Circuit Court of ~~Appeals. The Court held oral argument on September 25, 2008.~~Appeals affirmed the District Court’s dismissal. On April 14, 2009, Grynberg filed a petition for rehearing of the Tenth Circuit’s judgment.

GEII 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 ~~April 20,~~July 2009.

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

Note ~~10.~~8. Segment Disclosures

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


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

Three Months Ended March 31, 2009:
Segment revenues	$	155,217		$	537		$	19,959	$	175,713		$	90,778	$	486		$	14,204	$	105,468

Product cost and shrink replacement		53,902			—			3,847		57,749			18,461		—			1,701		20,162
Operating and maintenance expense		42,129			148			8,200		50,477			33,014		575			6,317		39,906
Depreciation, amortization and accretion		10,811			153			771		11,735			10,344		32			808		11,184
Direct general and administrative expense		2,188			—			631		2,819			2,161		—			756		2,917
Other, net		(3,703	)		—			195		(3,508	)		3,809		—			306		4,115


Segment operating income		49,890			236			6,315		56,441
Equity earnings		20,801			8,244			—		29,045

Segment operating income (loss)													22,989		(121	)		4,316		27,184
Investment income													15,321		812			—		16,133

Segment profit	$	70,691		$	8,480		$	6,315	$	85,486		$	38,310	$	691		$	4,316	$	43,317


Reconciliation to the Consolidated Statements of Income:
Segment operating income									$	56,441									$	27,184
General and administrative expenses:
Allocated-affiliate										(7,908	)									(8,882	)
Third party-direct										(557	)									(681	)


Combined operating income									$	47,976									$	17,621


*Three Months Ended September 30, 2007:**

Three Months Ended March 31, 2008:
Segment revenues	$	134,035		$	521		$	15,020	$	149,576		$	132,333	$	567		$	17,462	$	150,362

Product cost and shrink replacement		45,791			—			3,058		48,849			47,446		—			4,652		52,098
Operating and maintenance expense		34,267			443			5,824		40,534			40,893		524			5,667		47,084
Depreciation, amortization and accretion		8,564			304			1,477		10,345			10,299		153			774		11,226
Direct general and administrative expense		1,839			—			510		2,349			1,930		—			544		2,474
Other, net		2,414			—			194		2,608			2,554		—			284		2,838


Segment operating income (loss)		41,160			(226	)		3,957		44,891			29,211		(110	)		5,541		34,642
Equity earnings		18,472			7,902			—		26,374			21,194		13,621			—		34,815


Segment profit	$	59,632		$	7,676		$	3,957	$	71,265		$	50,405	$	13,511		$	5,541	$	69,457


Reconciliation to the Consolidated Statements of Income:
Segment operating income									$	44,891									$	34,642
General and administrative expenses:
Allocated-affiliate										(8,670	)									(7,662	)
Third party-direct										(722	)									(668	)


Combined operating income									$	35,499									$	26,312

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


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.

~~Business~~ Overview

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

	•		Gathering and Processing — ~~West.~~West (West).Our West segment includes ~~(1) the~~ Four Corners ~~gathering~~ and ~~processing system and (2)~~ ownership interests in Wamsutter, ~~which owns a gathering~~consisting of (i) 100% of the Class A limited liability company membership interests and ~~processing system in Wyoming.~~(ii) 65% of the Class C limited liability company membership interests (together, the Wamsutter Ownership Interests). We account for ~~our ownership interests in~~the Wamsutter Ownership Interests as an equity investment.

	•		Gathering and ~~Processing—Gulf.~~Processing — Gulf (Gulf).Our Gulf segment includes (1) our 60% ownership interest in Discovery ~~which owns a transportation, gathering and processing system extending from offshore in the Gulf of Mexico to a natural gas processing plant and a natural gas liquids fractionator in Louisiana~~ 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~~Our results for the ~~third~~first quarter of ~~2008, we continued to realize exceptionally strong per-unit~~2009 reflect the continuing impact of low NGL commodity prices. For example, our average NGL margins ~~in our gathering~~at Four Corners and ~~processing businesses, which led to significantly higher segment profit. We expect lower per-unit commodity margins in~~Wamsutter for the ~~fourth~~first quarter of 2008 as NGL prices, especially ethane, decline along with the price of crude oil. During the third quarter, gathered and processed volumes for these businesses continued to recover following the impact of2009 have declined approximately 57% from the first ~~quarter’s severe winter weather~~quarter of 2008. However, given the current energy commodity price and ~~downtime related~~NGL margin environment, together with our cash balance, we expect to ~~the November 2007 fire at the Ignacio plant. As~~maintain our current level of cash distributions throughout 2009. Additionally as discussed further below, ~~Hurricanes Gustav~~Williams, which owns our general-partner interest, will provide us with significant, additional support for 2009 which will enable us to maintain a higher level of cash retention and ~~Ike severely disrupted Discovery’s operations in September and will limit its operations throughout the fourth quarter until significant repairs are completed.~~a stronger overall liquidity position. We ~~continued~~maintained our ~~record of consecutive~~first-quarter unitholder distribution ~~increases since our initial public offering (IPO) with our third-quarter 2008 distribution of~~at $0.635 per unit which ~~is 15%~~equaled our fourth-quarter 2008 distribution and was 6% higher than ~~the third-quarter 2007~~our first-quarter 2008 distribution.

Recent Events

~~During September 2008, Discovery’s offshore gathering system sustained hurricane damage~~In 2009, Williams waived the incentive distribution rights (IDRs) related to 2009 distribution periods. The IDRs represent approximately $29.0 million, on an annual basis, at the partnership’s current per-unit cash distribution level.

In 2009, our omnibus agreement with Williams was amended to increase the aggregate amount of the credit we can receive related to certain general and ~~is currently not accepting gas from producers while repairs are being made. Inspections revealed that~~administrative expenses for 2009. Consequently, for 2009, Williams will provide up to an ~~18-inch lateral was severed from its connection~~additional $10.0 million credit, in addition to the ~~30-inch mainline in 250 feet of water. Discovery expects~~$0.8 million annual credit previously provided under the ~~30-inch mainline~~original omnibus agreement, to ~~be repaired~~the extent that all 2009 non-segment profit general and ~~returned~~administrative expenses exceed $36.0 million. We will record total general and administrative expenses (including those expenses that are subject to ~~service~~the credit by ~~early December. Due to ongoing damage assessments, the repair schedule for the 18-inch lateral has not yet been finalized. We estimate that hurricane-related damages~~Williams) as an expense, and ~~downtime reduced third-quarter 2008 equity earnings~~we will record any credits as capital contributions from Discovery by approximately $5.0 million. For fourth-quarter 2008, we expect Discovery’s equity earnings to range from $0 to a loss of $10 million. These estimates consider Discovery’s property insurance deductible, but doWilliams. Accordingly, our net income will not reflect ~~any potential future recoveries under~~the benefit of the credit received from Williams. However, the costs subject to this credit will be allocated entirely to our ~~business interruption insurance policy. Both~~general partner. As a result, the ~~Larose processing plant and~~net income allocated to limited partners on a per-unit basis will reflect the ~~Paradis fractionator are fully operational and running at 40 percent capacity from onshore gas sources.~~

~~The recent instability in financial markets has created global concerns about the liquidity~~benefit of ~~financial institutions and is having overarching impacts on the economy as a whole. In~~ this volatile economic environment, many financial markets, institutions and other businesses remain under considerable stress. In addition, oil and gas prices have recently experienced significant declines. These events are impacting our business. However, we note the following:credit.

2115

	•		~~We have no debt maturities until 2011.~~

	•		As of September 30, 2008, we have approximately $81.8 million of cash and cash equivalents and $220 million of available capacity under our credit facilities. (See further discussion in Management’s Discussion and Analysis of Financial Condition — Available Liquidity.)

To the extent that a continued downturn in the economy as a whole drives sustained lower NGL prices, it will negatively impact our future results of operations and cash flow from operations and could result in a reduction in capital expenditures.

Results of Operations

Consolidated Overview

The following table and discussion ~~summarizes~~is a summary of our consolidated results of operations for the three ~~and nine~~ months ended ~~September 30, 2008,~~March 31, 2009, compared to the three ~~and nine~~ months ended ~~September 30, 2007.~~March 31, 2008. The results of operations by segment are discussed in further detail following this consolidated overview. This discussion and analysis of results of operations reflects the historical results of our investments in Discovery and Wamsutter throughout the periods presented as retrospectively adjusted for our acquisition of the additional 20% interest in Discovery and ownership interests in Wamsutter in June and December 2007, respectively.overview discussion.


	Three months ended									Nine months ended									Three months ended
	September 30,						% Change from			September 30,						% Change from			March 31,						% Change from
	2008			2007 ⁽¹⁾			2007 ⁽¹⁾			2008			2007			2007 ⁽¹⁾			2009			2008			2008(1)
	(Thousands)									(Thousands)									(Thousands)
Revenues	$	175,713		$	149,576			+17	%	$	504,320		$	422,660			+19	%	$	105,468		$	150,362			(30	)%

Costs and expenses:
Product cost and shrink replacement		57,749			48,849			-18	%		175,856			135,721			-30	%		20,162			52,098			+61	%
Operating and maintenance expense		50,477			40,534			-25	%		144,093			117,290			-23	%		39,906			47,084			+15	%
Depreciation, amortization and accretion		11,735			10,345			-13	%		33,963			34,757			+2	%		11,184			11,226			—
General and administrative expense		11,284			11,741			+4	%		35,222			32,644			-8	%		12,480			10,804			(16	)%
Taxes other than income		2,314			2,474			+6	%		6,986			7,214			+3	%		2,436			2,505			+3	%
Other (income) expense — net		(5,822	)		134		NM				(8,300	)		792		NM

Other expense — net																				1,679			333		NM

Total costs and expenses		127,737			114,077			-12	%		387,820			328,418			-18	%		87,847			124,050			+29	%


Operating income		47,976			35,499			+35	%		116,500			94,242			+24	%		17,621			26,312			(33	)%
Equity earnings — Wamsutter		20,801			18,472			+13	%		79,475			50,358			+58	%		15,321			21,194			(28	)%
Equity earnings — Discovery		8,244			7,902			+4	%		30,435			15,708			+94	%
Discovery investment income																				812			13,621			(94	)%
Interest expense		(16,437	)		(14,284	)		-15	%		(50,793	)		(43,084	)		-18	%		(15,116	)		(17,673	)		+14	%
Interest income		249			312			-20	%		667			2,556			-74	%		34			175			(81	)%


Net income	$	60,833		$	47,901			+27	%	$	176,284		$	119,780			+47	%	$	18,672		$	43,629			(57	)%

	•		Revenues in our Gathering and Processing — West segment increased due primarily to higher NGL sales resulting from higher average NGL sales prices, higher sales of NGLs on behalf of third-party producers and higher condensate and LNG sales. These increases were partially offset by lower NGL sales volumes.

	•		~~Revenues in our NGL services segment increased due primarily to higher fractionation revenue and higher storage~~third-party producers, partially offset by higher fee-based revenues.

Product cost and shrink replacement ~~increased $8.9~~decreased $31.9 million, or ~~18%~~61%, due primarily to ~~higher~~lower product cost and shrink replacement in our West segment related primarily to decreased purchases of NGLs from third-party producers who elected to have us sell their NGLs and ~~higher~~lower average natural gas ~~prices in our Gathering and Processing — West segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West.”~~prices.

Operating and maintenance expense increased $9.9 million, or 25%, due primarily to higher system imbalance costs, material and supplies cost and gathering fuel in our Gathering and Processing — West segment, combined with 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.

~~Depreciation, amortization and accretion~~ increased $1.4 million, or 13%, due primarily to fluctuations in our Gathering and Processing — West segment which are discussed in detail in the “— Results of Operations — Gathering and Processing — West.”

~~Other (income) expense — net~~ improved $6.0 million due primarily to a $6.0 million third-quarter 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire which is explained further in the “— Results of Operations — Gathering and Processing — West” section.

~~Operating income~~ increased $12.5 million, or 35%, due primarily to higher per-unit NGL margins and an involuntary conversion gain resulting from the November 2007 Ignacio plant fire in our Gathering and Processing — West segment, combined with higher fractionation revenue in our NGL Services segment. Partially offsetting these favorable variances were higher operating and maintenance expenses and higher depreciation, amortization and accretion expense.

~~Equity earnings — Wamsutter~~ increased $2.3 million, or 13%, due to a 76% increase in Wamsutter’s net income. The net income variances are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section, and Note 5 Equity Investments of our Notes to Consolidated Financial Statements discusses how Wamsutter allocates its net income between its member owners including us.

~~Equity earnings — Discovery~~ increased $0.3 million, or 4%, due primarily to higher per-unit NGL sales margins, lower depreciation and accretion and lower general and administrative expenses, substantially offset by lower NGL sales volumes due to Hurricanes Ike and Gustav, lower transportation, gathering and fractionation revenues and higher operating and maintenance expenses. This increase is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

~~Interest expense~~ ~~increased $2.2~~decreased $7.2 million, or 15%, due primarily to ~~interest on our $250.0 million term loan issued in December 2007 to finance a portion of our acquisition of ownership interests in Wamsutter.~~

~~Nine months ended September 30, 2008 vs. nine months ended September 30, 2007~~

~~Revenues~~ ~~increased $81.7 million, or 19%, due primarily to higher revenues~~lower system and imbalance losses in our ~~Gathering and Processing —~~ West ~~segment and 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 and are summarized below:

	•		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. These increases were partially offset by lower NGL sales volumes received under keep-whole and percent-of-liquids processing contracts and lower fee-based gathering revenues on lower volumes.

	•		~~Revenues in our NGL Services segment increased due primarily to higher fractionation, product sales and storage revenues.~~

~~Product cost and shrink replacement~~ increased $40.1 million, or 30%, due primarily to increases in our Gathering and Processing — West segment and 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 and are summarized below:

	•		Product cost and shrink replacement increased in our Gathering and Processing — West segment due primarily to higher 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 product sales volumes and prices.~~

~~Operating and maintenance expense~~ increased $26.8 million, or 23%, due primarily to higher system losses and increased gathering fuel expense in our Gathering and Processing — West segment, combined with higher fractionation fuel cost 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 expenseincreased ~~$2.6~~$1.7 million, or 8%16%, due primarily to higher expenses for technical support services and other ~~charges~~support services allocated by Williams to us for ~~various~~ administrative support functions.

Other ~~(income)~~ expense—net ~~improved $9.1~~in 2009 reflects a $1.7 million ~~due primarily to a $9.3 million 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire which is explained further in the “— Results~~loss recognized on property taken out of ~~Operations — Gathering and Processing — West” section.~~service.

Operating income ~~increased $22.3~~decreased $8.7 million, or ~~24%~~33%, due primarily to ~~sharply higher~~substantially lower average per-unit NGL ~~margins on lower sales volumes, a $9.3 million 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~~partially offset by lower operating and maintenance ~~expenses~~expense and higher fee-based revenue in our ~~Gathering and Processing —~~ West ~~segment and our NGL Services segment, lower fee-based gathering revenues in our Gathering and Processing — West segment and higher general and administrative expenses.~~segment.

Equity earnings —from Wamsutter ~~increased $29.1~~decreased $5.9 million, or ~~58%~~28%, due primarily to ~~an 80% increase in Wamsutter’s net income from sharply higher~~lower per-unit NGL sales margins on ~~higher~~lower NGL sales ~~volumes. These variances are discussed in detail in the “— Results of Operations — Gathering~~volumes, partially offset by lower operating and ~~Processing — West” section,~~maintenance expense and ~~Note 5 Equity Investments of our Notes to Consolidated Financial Statements discusses how Wamsutter allocates its net income between its member owners including us.~~higher fee-based revenue.

~~Equity earnings —~~ Discovery investment income ~~increased $14.7~~decreased $12.8 million, or 94%, due primarily to ~~higher~~lower equity earnings resulting from lower NGL sales margins from both lower volumes and lower average per-unit ~~NGL~~ margins for both keep-whole and percentage-of-liquids processing agreements, partially offset by ~~lower plant inlet volumes that were reduced by Hurricanes Ike and Gustav. This increase is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.~~

~~Interest expense~~ ~~increased $7.7~~$4.0 million ~~or 18%, due primarily to interest on~~hurricane-related receipts under our ~~$250.0 million term loan issued in December 2007 to finance a portion of our acquisition of ownership interests in Wamsutter.~~

~~Interest income~~ ~~decreased $1.9 million, or 74%, due primarily to lower average cash balances and lower daily interest rates on cash balances.~~Discovery-related business interruption policy.

2416

These product ~~cost and shrink replacement increases~~sales decreases were partially offset by ~~a decrease of $1.5 million from 9% lower shrink replacement volumes associated with the lower NGL sales volumes received under Four Corners’ keep-whole processing contracts discussed above.~~

~~Operating and maintenance expense~~ ~~increased $7.9 million, or 23%, due primarily to:~~

	•		~~$3.4 million higher expense related to unfavorable price changes on system imbalances;~~

	•		~~$2.5 million higher materials and supplies expense; and~~

	•		~~$1.5 million higher gathering fuel expense caused primarily by higher natural gas prices.~~

~~Depreciation, amortization and accretion~~ ~~increased $2.2 million, or 26% due primarily to the absence of a $1.4 million third-quarter 2007 correction.~~

~~Other (income) expense — net~~ ~~improved $6.0 million due primarily to a $6.0 million third-quarter 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire.~~

~~Segment operating income~~ ~~increased $8.7 million, or 21%, due primarily to:~~

	•		~~$10.8 million from 40% higher per-unit NGL margins;~~

	•		~~$6.0 million third-quarter 2008 involuntary conversion gain;~~

	•		~~the absence of a $2.0 million third-quarter 2007 net out-of-period correction; and~~

	•		~~$1.6 million higher net condensate and LNG margins.~~

~~These increases were partially offset by $7.9~~$3.6 million higher ~~operating and maintenance expense and $2.2 million lower~~revenues from an 8% increase in NGL ~~margin from 8% lower NGL sales volumes.~~

~~Nine months ended September 30, 2008 vs. nine months ended September 30, 2007~~

~~Revenues~~ increased $66.6 million, or 18%, due primarily to $69.8 million higher product sales revenues and $4.0 million improved other fee revenue, partially offset by $6.9 million lower gathering revenues. The significant components of the revenue fluctuations are addressed more fully below.

~~Product sales revenues increased $69.8 million due primarily to:~~

	•		$49.3 million from 45% higher average per-unit NGL sales prices 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;

	•		$21.6 million higher sales of NGLs on behalf of third-party producers. Under these arrangements, we purchase NGLs from the third-party producers and sell them to an affiliate. This increase is offset by higher associated product costs of $21.7 million discussed below; and

	•		~~$6.2 million higher condensate sales resulting primarily from higher prices.~~

~~These increases were partially offset by $8.1 million related to 7% lower NGL sales~~ volumes that Four Corners received under keep-whole and percent-of-liquids processing contracts. The ~~decrease in~~2008 first-quarter NGL processing volumes ~~was due primarily to:~~

Product cost and shrink replacement ~~increased $34.7~~decreased $29.0 million, or ~~27%~~61%, due primarily to:

	•		$~~21.7~~15.7 million ~~higher NGL purchases~~decrease from third-party producers who elected to have us purchase their NGLs, which was offset by the corresponding ~~increase~~decrease in product sales discussed above;

	•		$~~13.9~~10.7 million decrease from ~~29% higher~~58% lower average natural gas ~~prices for shrink replacement;~~prices; and

	•		$~~1.3~~2.5 million ~~increase~~decrease in condensate ~~cost of sales.~~and LNG related product cost.

~~These increases were partially offset by a decrease of $2.1 million from 4% lower shrink replacement volumes on lower NGL sales volumes.~~

Operating and maintenance expense ~~increased $22.8~~decreased $7.9 million, or ~~24%~~19%, due primarily ~~to:~~to $8.2 million lower system and imbalance losses resulting from lower volumetric losses and lower gas prices. While our system losses are generally an unpredictable component of our operating costs, they can be higher during periods of prolonged, severe winter weather, such as those we experienced during January and February of 2008. Additionally, operational inefficiencies caused by the fire at the Ignacio plant impacted our system losses in 2008.

Other expense—netin 2009 reflects a $1.7 million loss recognized on property taken out of service.

Segment operating incomedecreased $6.2 million, or 21%, due primarily to $14.2 million lower product sales margins resulting primarily from a 57% decrease in average per-unit NGL margins, partially offset by $7.9 million lower operating and maintenance expense and $2.9 million higher fee-based gathering and processing revenue.

Outlook for 2009

	•		~~$8.5 million higher system losses. During 2008 our volumetric loss, as~~NGL and natural gas commodity prices.Because NGL prices, especially ethane, have declined, we expect significantly lower per-unit NGL margins in 2009 compared to 2008. As evidenced by recent events, NGL, crude and natural gas prices are highly volatile. Natural gas prices in the San Juan Basin have been lower than other areas of the country, and we expect this trend to continue. Because natural gas cost is 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~~NGL margins, we expect that per-unit NGL margins may be higher ~~during~~in the Four Corners area than some other areas of the country. Four Corners may experience 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~~when it is not economical to recover ethane, which will reduce our ~~system losses;~~margins. We have no hedges in place in 2009 for either our NGL sales or our natural gas shrink replacement purchases.

	•		~~$4.2 million higher~~Gathering and processing volumes.Despite lower projected well connects in 2009 which result in lower projected maintenance capital expenditures, we expect average gathering ~~fuel expense related~~and processing volumes for 2009 to ~~lower fuel reimbursements from customers as a result of lower volumes,~~be only slightly below 2008. Drilling activity by producers is expected to decline in 2009 due to the current credit crisis and ~~higher natural gas prices;~~economic downturn, together with the low commodity price environment. However, when drilling activity increases, we anticipate that recent capital investments will support producer customers’ drilling activity, expansion opportunities and production enhancement activities.

	•		~~$4.1 million higher expense related to revaluation of product imbalances;~~Operating costs.We expect and will pursue reductions in certain costs as demand for contractors, equipment and supplies decline.

	•		~~$3.7~~Assets on Jicarilla land.We concluded our negotiations with the Jicarilla Apache Nation (JAN) during February 2009 with the execution of a 20-year right-of-way agreement. We expect our total-year 2009 right-of-way expense to be approximately $8.4 million, which is significantly higher ~~materials and supplies expense.~~than the total-year 2008 cost of $3.5 million for our special business licenses with the JAN.

~~Other (income) expense — net~~ ~~improved $9.1 million due primarily to a $9.3 million 2008 involuntary conversion gain related to the November 2007 Ignacio plant fire.~~

~~Segment operating income~~ ~~increased $17.3 million, or 16%, due primarily to:~~

	•		~~$34.1 million higher NGL margins resulting from 54% higher per-unit NGL margins;~~

	•		~~$9.3 million of 2008 involuntary conversion gains;~~

	•		~~$4.9 million higher condensate sales margins; and~~

	•		~~the absence of a $2.0 million third-quarter 2007 net out-of-period correction.~~

Partially offsetting these increases were $22.8 million higher operating and maintenance expenses, $6.9 million lower fee-based gathering revenues and $4.7 million decreased NGL sales margin resulting from 7% lower NGL sales volumes.

~~Outlook~~

~~NGL margins.~~We expect lower per-unit commodity margins in the fourth quarter of 2008 as NGL prices, especially ethane, decline along with the price of crude oil. However, we still expect total-year 2008 per-unit margins to exceed levels realized in 2007 because of the NGL margins we have experienced through September 30, combined with our hedging program described below. 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.

~~NGL hedges.~~We have entered into contracts on a portion of our fourth-quarter 2008 NGL sales to realize a per-unit margin that exceeds the average margin realized on keep-whole NGL sales for 2007. 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 October through December 2008. The 5.4 million gallons per month represent approximately 45% of our 2007 NGL sales for these same months. On average, the per-gallon margin for the remaining forecasted sales is $0.50 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.

~~Gathering and processing volumes.~~We currently expect average gathering and processing volumes for the remainder of 2008 will be slightly higher than the same period in 2007 and full-year 2008 gathering and processing volumes will be lower than 2007. The full-year 2008 expected decline reflects the first-quarter 2008 impact of severe weather conditions that inhibited both our and our customers’ abilities to access facilities, connect new wells and maintain production.

~~Operating costs.~~We anticipate that operating costs, excluding gathering fuel and system gains and losses, will increase slightly as compared to 2007. 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 fuel reimbursements from customers in 2008 as the result of lower overall volumes in 2008 and higher gas prices.

~~Assets on Jicarilla land.~~Final resolution of our negotiations with the Jicarilla Apache Nation (JAN) concerning our gathering system assets located on JAN-owned land will impact our future operating results and could impact our liquidity requirements. During the third quarter of 2008, negotiations with the JAN, which have been ongoing since the expiration of our right-of-way agreement with them on December 31, 2006, expanded to include discussions of other alternative arrangements. Although the ultimate outcome is unknown at this time, the alternative arrangements could allow us to retain revenue associated with these gathering assets, although it may also increase annual operating expense.

2818

~~Nine months ended September 30, 2008 vs. nine months ended September 30, 2007~~

~~Revenues~~ ~~increased $76.8 million, or 65%, due primarily to $74.8 million, or 117%, higher product sales which Wamsutter received under keep-whole processing contracts. This increase reflects:~~

	•		~~$52.1~~22.2 million related to a ~~64% increase~~54% decrease in average NGL sales prices ~~resulting~~realized on sales of NGLs which Wamsutter received under keep-whole processing contracts. This decrease resulted from general ~~increases~~decreases in market prices for these commodities between the two periods.

	•		$~~20.7~~5.7 million related to a ~~34% increase~~12% decrease in ~~volumes. This increase was primarily due~~NGL volumes that Wamsutter received under keep-whole processing contracts. Severe winter weather conditions in 2008 lowered volumes received under some of Wamsutter’s larger fee-based processing agreements thus allowing Wamsutter to aprocess greater volumes under keep-whole processing arrangements. In addition, lower ~~percentage of total gas delivered by Wamsutter’s fee-based customers~~NGL volumes were produced in the first quarter of ~~2008~~2009 due to ~~inclement weather and additional keep-whole gas processed at CIG’s Rawlins natural gas processing plant.~~operational issues.

	•		$3.1 million related to favorable adjustments to the margin-sharing provisions of one of Wamsutter’s significant ~~contracts.~~contracts in the first quarter of 2008.

These product sales decreases were partially offset by $2.6 million higher sales of NGLs on behalf of third-party producers. Under these arrangements, Wamsutter purchases NGLs from the third-party producers and sells them to an affiliate. This decrease is offset by higher associated product costs of $2.6 million discussed below.

Gathering and processing fee-based revenues increased $4.4 million, or 29%, due primarily to a 24% increase in average volumes. The increase in average volumes was due primarily to production problems in 2008 caused by severe winter weather conditions and new wells connected in 2009.

Product cost and shrink replacement ~~increased $35.2~~decreased $13.6 million, or ~~107%~~52%, due primarily to:

	•		$~~25.6~~11.6 million ~~increase~~decrease from ~~62% higher~~54% lower average natural gas ~~prices. Gas prices in 2007 were impacted by very low local natural gas costs compared with other natural gas markets.~~

	•		~~$11.0 million increase from 36% higher volumetric shrink requirements due to higher volumes processed under Wamsutter’s keep-whole processing contracts.~~

~~Operating and maintenance expense~~ ~~decreased $2.2 million, or 17%, due primarily to $5.4 million higher system gains, partially offset by:~~

	•		~~$1.9 million higher gathering fuel costs related to higher average natural gas prices and weather-related operational problems in first-quarter 2008;~~prices; and

	•		$~~1.2~~4.6 million ~~higher third-party~~decrease from 18% lower volumetric shrink requirements due to lower volumes processed under Wamsutter’s keep-whole processing ~~and compression services costs.~~contracts.

These decreases were partially offset by $2.6 million higher product cost related to higher sales of NGLs on behalf of third-party producers who sell their NGLs to Wamsutter under their contracts as discussed above.

~~Depreciation~~Operating and ~~accretion~~maintenance expense ~~increased $2.5~~decreased $5.8 million, or ~~18%~~50%, due primarily to ~~new assets placed into service.~~$3.5 million lower gathering fuel costs and $1.3 million lower system gains between the two periods. Gathering fuel costs were higher in 2008 due to weather-related operational problems.

~~General and administrative expenses~~Net income ~~increased $1.6~~decreased $5.9 million, or ~~19%~~28%, due primarily to ~~higher charges allocated by Williams to us for various administrative support functions and higher labor and employee-related expenses.~~

~~Net income~~ ~~increased $40.3~~$14.8 million ~~or 80%, due primarily to $39.3 million higher~~lower product sales margins resulting primarily from sharply ~~increased~~decreased per-unit margins on ~~higher~~lower NGL sales volumes.

~~As described in Note 5 of our Notes to Consolidated Financial Statements, Wamsutter’s net income is allocated based upon the allocation, distribution,~~ Partially offsetting this increase were $5.8 million lower operating and ~~liquidation provisions of its limited liability company agreement. The following table presents the allocation of Wamsutter’s 2008 net income to its unitholders:~~

Wamsutter Net Income Allocation Our Share Other Wamsutter
(Dollars in millions) Class A Class C WPZ Total Class C Net Income
Net income, beginning December 1, 2007 up to $70.0 million.* $ 62.6 $ — $ 62.6 $ — $ 62.6
Net income allocation related to transition support payments paid to us 5.7 — 5.7 — 5.7
Remainder net income allocated to Class C members — 11.2 11.2 11.2 22.4

Totals $ 68.3 $ 11.2 $ 79.5 $ 11.2 $ 90.7


*		~~$7.4 million of the $70.0 million was recognized in 2007.~~

~~Outlook~~

~~NGL margins.~~Wamsutter expects lower per-unit commodity margins in the fourth quarter of 2008 as NGL prices, especially ethane, decline along with the price of crude oil. However, Wamsutter still expects total-year 2008 per-unit margins to exceed levels realized in 2007 because of the NGL margins they have experienced through September 30. The prices of NGLsmaintenance expenses 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.

~~Gathering and processing volumes.~~~~Wamsutter currently expects average~~$4.4 million higher fee-based gathering and processing ~~volumes~~revenues.

Outlook for fourth-quarter 2008 will be slightly higher than fourth-quarter 2007, and full-year 2008 gathering and processing volumes will be slightly lower than 2007. The full-year 2008 expected decline reflects the first-quarter 2008 impact of severe weather conditions that reduced both Wamsutter’s and their customers’ abilities to access facilities and maintain production.2009

~~Pipeline capacity restrictions.~~In October 2008, Wamsutter’s Echo Springs processing plant began transporting NGLs on the new Overland Pass Pipeline and this transition is expected to lower transportation costs and allow increased NGL production. This access to the Overland Pass Pipeline substantially relieved the restrictions in the volumes of NGLs transported in a separate third-party pipeline.

	•		NGL margins.We expect significantly lower cash distributions from Wamsutter in 2009 as compared to 2008, primarily as a result of lower per-unit NGL margins. As evidenced by recent events, NGL, crude and natural gas prices are highly volatile. Natural gas prices in the Rockies’ basins have been lower than other areas of the country, and we expect this trend to continue. Because natural gas cost is a component of Wamsutter’s NGL margins, Wamsutter expects that per-unit NGL margins may be higher at Wamsutter than some other areas of the country. However, Wamsutter may still experience periods when it is not economical to recover ethane which will reduce its margins.

	•		Gathering and processing volumes.We anticipate that our 2009 average gathering volumes will increase slightly over 2008 levels as a result of our well connect activity, producers’ sustained drilling activity, expansion opportunities and production enhancement activities that should be sufficient to more than offset the historical production decline. Gathering volumes reached record levels in March 2009.

	•		Third-party processing.In 2008, we executed a new agreement that extended our ability to send excess unprocessed gas to Colorado Interstate’s Rawlins natural gas processing plant through October 2010. This agreement provides Wamsutter with third-party processing of 80 MMcf/d. We expect a full year of natural gas processing in 2009 under this agreement. As a result, total gas processed will increase, Wamsutter will be able to sell higher volumes of NGLs, and operating costs will increase approximately $2.0 million. The increased operating costs will be more than offset by the sale of increased volumes of NGLs.

	•		Operating ~~costs.~~~~Wamsutter expects operating costs, excluding system gains and losses, to increase slightly from 2007. System gains and losses are an unpredictable component of Wamsutter’s operating~~ costs.We expect and will pursue reductions in certain costs as demand for contractors, equipment and supplies decline.

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					Nine months ended					Three months ended
	September 30,					September 30,					March 31,
	2008		2007			2008		2007			2009			2008
	(Thousands)										(Thousands)
Segment revenues	$	537	$	521		$	1,650	$	1,541		$	486		$	567

Costs and expenses:
Operating and maintenance expense		148		443			1,191		1,354			575			524
Depreciation		153		304			457		911

Depreciation, amortization and accretion												32			153

Total costs and expenses		301		747			1,648		2,265			607			677


Segment operating income (loss)		236		(226	)		2		(724	)
Equity earnings — Discovery		8,244		7,902			30,435		15,708

Segment operating loss												(121	)		(110	)
Discovery investment income												812			13,621

Segment profit	$	8,480	$	7,676		$	30,437	$	14,984		$	691		$	13,511

Discovery ~~Producer Services — 100 %~~

Three months ended Nine months ended
September 30, September 30,
2008 2007 2008 2007
(Thousands)
Revenues $ 61,280 $ 60,110 $ 231,319 $ 176,095

Costs and expenses, including interest:
Product cost and shrink replacement 35,491 34,538 139,090 107,945
Operating and maintenance expense 8,079 5,751 23,498 21,265
Depreciation and accretion 3,726 6,243 17,511 19,234
General and administrative expense (125 ) 579 3,375 1,702
Interest income (143 ) (389 ) (593 ) (1,472 )
Other (income) expense, net 510 220 (2,287 ) 1,242

Total costs and expenses, including interest 47,538 46,942 180,594 149,916

Net income $ 13,742 $ 13,168 $ 50,725 $ 26,179

Williams Partners’ 60% interest — Equity Earnings per our Consolidated Statements of Income $ 8,244 $ 7,902 $ 30,435 $ 15,708

Discovery is accounted for using the equity method of accounting. As such, our interest in Discovery’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Discovery.


	Three months ended
	March 31,
	2009			2008
	(Thousands)
Revenues	$	20,034		$	87,156
Costs and expenses, including interest:
Product cost and shrink replacement		10,231			52,240
Operating and maintenance expense		8,471			7,008
Depreciation and accretion		3,929			6,983
General and administrative expense		1,500			1,750
Interest income		(8	)		(264	)
Other (income) expense, net		1,263			(3,262	)

Total costs and expenses, including interest		25,386			64,455

Net income (loss)	$	(5,352	)	$	22,701


Williams Partners’ interest — equity earnings (losses)	$	(3,211	)	$	13,621
Business interruption proceeds		4,023			—

Discovery investment income	$	812		$	13,621

Three months ended ~~September 30, 2008~~March 31, 2009 vs. three months ended ~~September 30, 2007~~March 31, 2008

Revenues ~~increased $1.2~~decreased $67.1 million, or 2%77%, due primarily to ~~$10.6~~$64.3 million ~~higher~~lower product sales ~~related to a 45% higher average NGL~~and $2.6 million lower fee-based transportation and fractionation revenue. The lower product sales price 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 and was substantially offset by:are due primarily to:

	•		$~~6.5~~34.5 million from 67% lower ~~third-party~~ NGL ~~sales on behalf~~volumes from gas processed under keep-whole and percent-of-liquids arrangements. NGL volumes recovered declined due primarily to ethane rejection for two months in the first quarter of ~~third-party producers. This decrease results primarily~~2009 resulting from unfavorable ethane margins, reduced volumes as a result of 2008 hurricane damages and the absence of volumes from the ~~impact of Hurricanes Ike and Gustav and is offset by lower product costs of $6.5 million discussed below;~~Texas Eastern Transmission Company (TETCO) system after our processing arrangement with them expired in June 2008.

	•		$~~1.9~~20.7 million lower sales of NGLs on 8%behalf of third-party producers resulting from both lower ~~product sales volumes caused by reduced percent-of-liquids~~ volumes and ~~including an estimated 8 million~~ lower NGL ~~equity~~ sales ~~gallons caused~~prices. The lower volumes are due primarily to the absence of gas volumes processed from the TETCO system and other third-party producers. These decreases are offset by ~~the effects~~lower associated product costs of ~~Hurricanes Ike and Gustav; and~~$20.7 million discussed below.

	•		$~~1.4~~9.2 million from 54% lower ~~transportation, gathering~~average per-unit NGL prices on volumes recovered under keep-whole and ~~fractionation revenue primarily resulting from the impact of Hurricanes Ike and Gustav.~~

~~Product cost and shrink replacement~~ increased $1.0 million, or 3%, due primarily to $5.2 million higher shrink replacement resulting from 62% higher average natural gas prices and $2.7 million from 20% higher shrink volumes on higher keep-whole volumes. These increases were substantially offset by $6.5 million lower product purchased from third-party producers, which was offset by the corresponding decrease in product sales discussed above.

~~Operating and maintenance expense~~ increased $2.3 million, or 40%, due primarily to initial repair expenses of $1.5 million resulting from Hurricanes Ike and Gustav, which we expect will apply toward the $6.4 million property insurance deductible, and $1.3 million higher fuel costs.

~~Depreciation and accretion~~ ~~decreased $2.5 million, or 40%, due primarily to a change in the estimated lives of the Larose processing plant and the regulatory pipeline and gathering system.~~

~~General and administrative expense~~ ~~improved $0.7 million due primarily to a true-up following the finalization of negotiations between Discovery and Williams for the cost of the management services provided by Williams to Discovery.~~

~~Net income~~ increased $0.6 million, or 4%, due primarily to $1.2 million higher NGL gross margins, lower depreciation and accretion and lower general and administrative expenses, substantially offset by lower transportation, gathering and fractionation revenues and higher operating and maintenance expenses.

~~Nine months ended September 30, 2008 vs. nine months ended September 30, 2007~~

~~Revenues~~ ~~increased $55.2 million, or 31%, due primarily to $54.7 million higher product sales resulting from:~~

	•		~~$36.7 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~~percent-of-liquids arrangements. These price decreases resulted from general ~~increases~~decreases in market prices for these commodities between the two periods.

Fee-based transportation and fractionation revenues decreased $2.6 million due primarily to the absence of gas volumes from the TETCO system discussed above and reductions in other gas volumes impacted by the 2008 hurricanes.

Product cost and shrink replacementdecreased $42.0 million, or 80%, due primarily to a $20.7 million decrease in NGL purchases from third-party producers who elected to have us purchase their NGLs (offset by the corresponding decrease in product sales discussed above) combined with an $11.7 million decrease from 49% lower prices for natural gas purchased for shrink replacement and a $7.8 million decrease from 66% lower volumes of natural gas required for shrink replacement.

Operating and maintenance expenseincreased $1.5 million, or 21%, due primarily to a 2009 turbine overhaul at the Larose plant.

Depreciation and accretiondecreased $3.1 million, or 44%, due primarily to a 2008 change in the estimated remaining useful lives of the Larose processing plant and the regulated pipeline and gathering system.

Other (income) expense, netchanged unfavorably by $4.5 million due to the absence of a 2008 $3.5 million favorable one-time adjustment for a Federal Energy Regulatory Commission (FERC) settlement, combined with higher property taxes on the plants following the end of the tax abatement period.

Net income (loss)changed from $22.7 million net income in the first quarter of 2008 to $5.4 million net loss in the first quarter of 2009 due primarily to $23.0 million lower NGL sales margins resulting from lower volumes and lower average per-unit margins on NGL processing agreements, $4.5 million unfavorable other (income) expense, net and $2.6 million lower fee-based revenue. These decreases were slightly offset by $3.1 million lower depreciation and accretion expense.

Outlook for 2009

	•		~~$17.3 million~~Gross processing margins.We expect significantly lower cash distributions from ~~24% higher~~Discovery in 2009 compared to 2008 primarily as a result of lower per-unit NGL ~~volumes processed under keep-whole~~margins. As evidenced by recent events, NGL, crude and ~~percent-of-liquids arrangements, including an estimated 8 million~~natural gas prices are highly volatile. As NGL prices, especially ethane, have declined, Discovery is experiencing significantly lower ~~NGL equity sales gallons caused by the effects of Hurricanes Ike and Gustav.~~gross processing margins in 2009 compared to 2008. We anticipate periods when it may not be economical to recover ethane, which would reduce Discovery’s margins.

	•		~~$2.7 million higher sales of NGLs on behalf of third-party producers.~~Plant inlet volumes.Discovery’s Larose gas processing plant is currently processing approximately 520 BBtu/d from all sources and we expect this volume to be similar through the second quarter due to the current marginal economic processing environment. This ~~increase is net of~~represents a decrease from the ~~impact of lower third-party sales volumes caused by the hurricanes~~600 BBtu/d being processed prior to Hurricanes’ Gustav and ~~is offset by higher associated product costs of $2.7 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 $31.1 million, or 29%, due primarily to:~~

	•		~~$15.8 million on 38% higher natural gas volumes from higher keep-whole volumes;~~Ike in 2008.

	•		~~$11.0 million~~Tahiti Production.Discovery expects to begin receiving revenues from ~~36% higher average natural~~its Tahiti pipeline lateral by mid-2009 based on Chevron’s announcement regarding expected timing of first production. Discovery’s lateral line is completed and tied in, has been commissioned and gas ~~prices;~~is able to flow through it. Any delays Chevron experiences in bringing their production online will further impact the initial timing of revenues for Discovery. Discovery expects approximately 50 BBtu/d to 75 BBtu/d from Tahiti.

	•		~~$6.0 million increase in payments~~Other new supplies.In the second half of 2009, Discovery expects to ~~producers for~~receive approximately 50 BBtu/d of new gas production from the ~~rights~~Clipper and Daniel Boone prospects. During the first quarter of 2009, Discovery began receiving new gas production from the Pegasus and Yosemite prospects and expects total gas volumes to ~~process their gas;~~reach 20 BBtu/d. Prior to the 2008 hurricanes, Discovery began receiving gas from the Valley Forge prospect and expects gas volumes to reach 15 BBtu/d.

	•		~~$2.7~~Uninsured hurricane cost recovery.Under Discovery’s current FERC approved tariff, Discovery is permitted to recover certain natural disaster related costs, including property damage insurance deductibles, through a transportation rate surcharge. Discovery recently received FERC approval to increase its hurricane mitigation relief surcharge effective April 1, 2009 to its maximum allowable rate of $0.05/MMBtu to expedite Discovery’s recovery of any Hurricane Ike-related expenses which should contribute approximately $4.5 million ~~higher product purchased from third-party producers, which was substantially offset~~to Discovery’s net income.

	•		Operating costs.Discovery’s current property damage insurance policies expire in June 2009. As a result of damage caused by the ~~corresponding increase in product sales discussed.~~2008 hurricanes, Discovery expects insurance for named wind storms for its offshore assets will be significantly reduced or perhaps be unavailable at reasonable terms. Additionally, insurance premiums for its onshore assets could be higher along with higher deductibles and lower coverage limits.

~~These increases were partially offset by $2.0 million lower product cost for sales of excess fuel and shrink replacement gas discussed above.~~

~~Operating and maintenance expense~~ increased $2.2 million, or 11%, due primarily to $2.6 million higher fuel costs and $1.5 million repair expense resulting from Hurricanes Ike and Gustav, partially offset by $1.0 million lower costs from the 2007 decommissioning of a pipeline and $0.9 million lower property insurance expense.

~~Depreciation and accretion~~ ~~decreased $1.7 million, or 9%, due primarily to a change in the estimated lives of the Larose processing plant and the regulatory pipeline and gathering system.~~

~~General and administrative expense~~ ~~increased $1.7 million, or 98%, due to an increase in Discovery’s management fee charged by Williams.~~

~~Other (income) expense, net~~ improved $3.5 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 $24.5 million, or 94%, due primarily to $22.7 million higher NGL sales margins resulting from higher per-unit margins on NGL sales and plant inlet volumes that were reduced by Hurricanes Ike and Gustav, a $3.5 million favorable change

in other (income) expense, net, and $1.7 million lower depreciation and accretion expense, partially offset by $2.2 million higher operating and maintenance expense and $1.7 million higher general and administrative expense.

~~Outlook~~

~~Hurricane damage impact.~~As a result of damage suffered by Discovery during Hurricane Ike, we expect our fourth-quarter equity earnings from Discovery to range from $0 to a loss of $10 million and we expect a significantly reduced cash distribution in January 2009. Discovery’s 18-inch lateral was severed from its connection to the 30-inch mainline in 250 feet of water; hence, Discovery is currently unable to accept offshore gas from producers while repairs are being made. Discovery expects that the damage to the 30-inch mainline will be repaired and returned to service by early December. Due to ongoing damage assessments, the repair schedule for the 18-inch lateral has not yet been finalized.

In addition, we expect Discovery’s onshore gas processing volumes to decrease because of damage sustained to third-party onshore gathering systems. These volumes are not expected to reach pre-hurricanes flows until early next year. We expect to continue to process volumes from the Tennessee Gas Pipeline (TGP) system along with new month-to-month agreements with several shippers on Texas Eastern Transmission Company for the remainder of 2008.

~~Uninsured hurricane cost recovery.~~Under Discovery’s current Federal Energy Regulatory Commission-approved tariff, Discovery is permitted to recover certain natural-disaster related costs, including property damage insurance deductibles, through a transportation rate surcharge. Recovery of any Hurricane Ike-related repairs via this surcharge would occur in 2009 and 2010.

~~New throughput volumes.~~In August 2008, Discovery received a dedication of eight blocks located in the Walker Ridge area which is expected to contribute new throughput volumes beginning in 2010. The capital requirements to connect these blocks will be funded entirely by the working interest owners; however, Discovery is obligated to provide a new downstream interconnect which is estimated to cost $4.0 million.

~~Tahiti production delay.~~Construction complications experienced by Chevron have delayed the initial revenue stream on Discovery’s Tahiti pipeline lateral, which 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.

~~NGL margins.~~Discovery expects lower per-unit gross processing margins in the fourth quarter of 2008 as NGL prices, especially ethane, decline along with the price of crude oil. However, Discovery expects total-year 2008 per-unit margins will exceed record levels realized in 2007 because of the higher margins we have experienced through September 30 resulting from commodity prices for NGLs and natural gas, Discovery’s mix of processing contract types and its operation and optimization activities. 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. The fluctuations and impacts due to economic conditions could change the realized margins currently expected for the remainder of 2008.

~~Compression projects increase capacity.~~Discovery has completed the first of three compression projects which will increase the inlet capacity of the TGP connection. This first project has increased the capacity by 20 MMcf/d. The remaining two projects are expected to be completed by the end of 2008.

~~Management fees~~Management fees paid to Williams for senior management guidance, legal, marketing, financial analysis, information technology, accounting and other management services will increase from $2.3 million in 2007 to $4.5 million and $6.0 million in 2008 and 2009, respectively. This annual amount will be adjusted each April thereafter based on a published industry rate.

3422

~~Operating and maintenance expense~~ ~~increased $4.1 million, or 22%, due primarily to the following:~~

	•		~~$2.3 million higher~~a 29% decrease in average fractionation ~~fuel costs related to increased natural gas prices and~~price per barrel on slightly higher ~~fractionation volumes; and~~volumes.

	•		~~$1.9~~Storage revenues increased $1.0 million ~~unfavorable storage product losses.~~due primarily to higher overstorage revenue.

~~These increases were partially offset by $1.8~~Product costdecreased $3.0 million, ~~favorable fractionation blending gains.~~or 63%, due to the lower product sales prices and volumes discussed above.

Segment profit ~~increased $5.7~~decreased $1.2 million, or ~~59%~~22%, due primarily to ~~higher~~unfavorable variances in fractionation revenues, operating and ~~storage~~maintenance expenses and other revenues, partially offset by higher ~~operating and maintenance expenses.~~storage revenues.

Outlook for 2009

~~Storage and fractionation revenues.~~We expect 2008 storage and fractionation revenues will be higher than 2007 due to continued strong demand for NGL storage and specialty storage services and a change in pricing on a fractionation contract that previously had a fee cap.

	•		We expect 2009 storage revenues will approximate 2008 due to continued strong demand for propane and natural gasoline storage as well as higher priced specialty storage services.

	•		We continue to perform a large number of storage cavern workovers and wellhead modifications to comply with Kansas Department of Health and Environment regulatory requirements. We expect outside service costs to continue at current levels throughout 2009 to ensure that we meet the regulatory compliance requirements.

~~Cavern workovers and wellhead modifications.~~We expect outside service costs for storage cavern workovers and wellhead modifications to continue at current levels throughout 2008. These are necessary to ensure that we meet the KDHE regulatory compliance requirements.

Financial Condition and Liquidity

The global recession and resulting drop in demand and prices for NGLs has significantly reduced the profitability and cash flows of our gathering and processing businesses, including Four Corners, Wamsutter and Discovery. We expect lower NGL margins during 2009 than 2008, and there may be periods when it is not economical to recover ethane which will further reduce our margins. As a result, we expect cash flow from operations, including cash distributions from Wamsutter and Discovery, to be significantly lower in 2009 than 2008. Additionally, instability in financial markets has created global concerns about the liquidity of financial institutions and is having overarching impacts on the economy as a whole. However, we have no debt maturities until 2011, and as of March 31, 2009, we have approximately $77.3 million of cash and cash equivalents and $208.0 million of available capacity under our credit facilities. The availability of the capacity under the credit facilities may be restricted under certain circumstances as discussed below under “ — Credit Facilities.” 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 oursources of liquidityfor the remainder of 2009 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;~~

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

	•		~~Credit~~Use of credit facilities, as ~~needed.~~needed and available.

~~We anticipate our more significant uses of cash to be:~~


•		~~Possible payments~~We anticipate our more significantuses of cashfor the remainder of 2009 to ~~the Jicarilla Apache Nation;~~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 expansion capital ~~expenditures;~~expenditures as defined by the Wamsutter LLC agreement;

•	Cash calls from Discovery for hurricane damage repairs, ~~which generally should be reimbursed by insurance;~~

•	~~Completion of the Four Corners repair expenditures related to the fire at Ignacio gas processing plant,~~ which generally should be reimbursed by insurance;

•	Interest on our long-term debt; and

•	Quarterly distributions to our unitholders ~~and~~and/or general partner. Our general partner has waived its IDRs with respect to 2009 distribution periods which will reduce our 2009 use of cash.

Additionally, we plan to continue pursuing select value-adding growth opportunities in a prudent manner.

Available Liquidity at ~~September 30, 2008~~March 31, 2009(in millions):


Cash and cash equivalents	$	81.8	$	77.3
Available capacity under our $450 million five-year senior unsecured credit facility (1)		188.0
Available capacity under our $450 million five-year senior unsecured credit facility(1)				188.0
Available capacity under our $20 million revolving credit facility with Williams as lender		20.0		20.0

Total	$	289.8	$	285.3

Wamsutter Distributions

Wamsutter expects to make quarterly distributions of available cash to its members pursuant to the terms of its limited liability company agreement. Available cash is defined as cash generated from Wamsutter’s business less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law and/or debt instruments or other agreements to which it is a party. Wamsutter ~~has~~ made the following 2009 distributions to its members ~~for the distribution year that began December 1, 2007~~ (all amounts in thousands):

Total Distribution Our Share
Date of Distribution to Members Class A Class C Other Class C
3/28/08 $ 25,000 $ 17,874 $ 3,563 $ 3,563
6/30/08 30,500 18,150 6,175 6,175
9/30/08 35,500 18,400 8,550 8,550

Total $ 91,000 $ 54,424 $ 18,288 $ 18,288


			Our Share
Date of Distribution	Total Distribution to Members		Class A		Class C		Other Class C

3/30/09	$	13,500	$	13,500	$	—	$	—

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 ~~second~~quarter of 2009 Williams paid Wamsutter and ~~third quarters of 2008~~ Wamsutter paid us ~~$1.3~~$2.1 million ~~$2.3 million and $2.0 million, respectively,~~ in transition support payments related to the amount by which Wamsutter’s general and administrative expenses exceeded a certain cap.

Discovery Distributions

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
10/30/08 $18,000 $10,800

As a result of ~~the~~disruptions and damage from ~~Hurricane~~Hurricanes Gustav and Ike, Discovery did not make a distribution for the fourth quarter of 2008 in January 2009. Discovery also did not make a distribution for the first quarter of 2009 in April 2009 as a result of sharply lower NGL margins combined with the reduced volumes resulting from the 2008 hurricane damage to ~~Discovery’s~~the gathering ~~system, we expect Discovery’s first-quarter 2009 cash distribution will be significantly reduced.~~system.

Insurance Recoveries

On September 13, 2008, Hurricane Ike hit the Gulf Coast area, and Discovery’s offshore gathering system sustained damage. Inspections revealed that an 18-inch lateral was severed from its connection to the 30-inch mainline in 250 feet of water. The repair of the gathering system has been completed and the total repair cost incurred through March 31, 2009, was approximately $56.6 million, including $47.8 million in potentially reimbursable expenditures in excess of the insurance deductible and $2.4 million in unreimbursable expenditures. Discovery funded the $6.4 million deductible amount with cash on hand and filed for and received a prepayment of $38.7 million from the insurance provider. In April 2009, we funded $6.3 million representing our portion of Discovery’s cash call to partners for repair costs in excess of the deductible, net of any insurance prepayments. Once Discovery receives the remaining insurance proceeds, we expect it to make special distributions back to its members. Discovery does not anticipate any further need for cash calls to fund hurricane repair costs. We have also filed for reimbursement from our insurance carrier for lost profits under our Discovery-related business interruption policy, which has a 60-day deductible period, and have received $5.9 million to date.

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 ~~$34.8~~$38.2 million, including ~~$33.8~~$37.2 million in potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, ~~$21.9~~$25.4 million has been incurred through ~~September 30, 2008.~~March 31, 2009. We are funding these repairs with cash flows from operations, are seeking reimbursement from our insurance carrier and have received ~~$18.2~~$22.8 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. We have also filed for reimbursement from our insurance carrier for lost profits under our business interruption ~~policy.~~

~~On September 13, 2008, Hurricane Ike hit the Gulf Coast area~~policy and ~~Discovery’s offshore gathering system sustained hurricane damage. Inspections revealed that an 18-inch lateral was severed from its connection~~have received $4.4 million to the 30-inch mainline in 250 feet of water. The estimated total cost to repair the gathering system is approximately $46.0 million, including $39.6 million in potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, $1.5 million has been incurred through September 30, 2008. Discovery will fund the $6.4 million deductible amount with cash on hand and has also filed for a prepayment from the insurance provider. Repair costs in excess of the deductible and any insurance prepayments will be funded with cash calls from its members, including us. Once Discovery receives the related insurance proceeds, it will make special distributions back to its members. We will also seek reimbursement from our insurance carrier for lost profits under our Discovery-related business interruption policy. This policy has a 60-day deductible period.date.

3825

~~Capital Contributions from~~Modification of Omnibus Agreement with Williams

~~Capital~~In 2009, our omnibus agreement with Williams was amended to increase the aggregate amount of the credit we can receive related to certain general and administrative expenses for 2009. Consequently, for 2009, Williams will provide up to an additional $10.0 million credit, in addition to the $0.8 million annual credit previously provided under the original omnibus agreement, to the extent that all 2009 non-segment profit general and administrative expenses exceed $36.0 million. We will record total general and administrative expenses (including those expenses that are subject to the credit by Williams) as an expense, and we will record any credits as capital contributions from ~~Williams required under~~Williams. Accordingly, our net income will not reflect the ~~omnibus agreement consist~~benefit of the ~~following:~~

	•		Approximately $7.5 million remains available for indemnification of environmental and related expenditures not subject to a time limitation. These include indemnification for Conway plumes and required wellhead control equipment and well meters.

	•		~~An annual credit for general and administrative expenses of $1.6 million in 2008 and $0.8 million in 2009; and~~

	•		Up to $3.4 million to fund our initial 40% share of the expected total cost of Discovery’s Tahiti pipeline lateral expansion project in excess of the $24.4 million we contributed during September 2005. As of September 30, 2008 we have received $1.6 million from Williams for this 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 received from Williams. However, the costs subject to this credit will be allocated entirely to our general partner. As a result, the net income allocated to limited partners on a per-unit basis will reflect the benefit of this credit.

Credit Facilities

WeUnder our $450.0 million senior unsecured credit agreement (Credit Agreement) with Citibank, N.A., we have a $200.0 million revolving credit facility ~~with Citibank, N.A. as administrative agent~~ available for borrowings and letters of ~~credit.~~credit and a $250.0 million term loan. The parent company and certain affiliates of Lehman, ~~Brothers Commercial Bank,~~ who is committed to fund up to $12.0 million of ~~our revolving~~this credit facility, ~~have~~ filed for ~~bankruptcy.~~bankruptcy in September 2008. We expect that our ability to borrow under this facility is reduced by ~~these~~this committed ~~amounts.~~amount. The committed amounts of the other participating banks ~~under this agreement~~ remain in effect and are not impacted by this reduction. ~~Borrowings~~However, debt covenants may restrict the full use of the credit facility as discussed below. We must repay borrowings under ~~this agreement must be repaid within five years. There were~~the Credit Agreement by December 11, 2012. At March 31, 2009, we had a $250.0 million term loan outstanding under the term loan provisions and no amounts outstanding ~~at September 30, 2008~~ under the revolving credit facility.

	•		We are required to maintain a ratio of consolidated indebtedness to consolidated EBITDA (each as defined in the Credit Agreement) of no greater than 5.00 to 1.00 as of the last day of any fiscal quarter. This ratio may be increased in the case of an acquisition of $50.0 million or more, in which case the ratio will be 5.50 to 1.00 for the fiscal quarter in which the acquisition occurs and three fiscal quarter-periods following such acquisition. At March 31, 2009, our ratio of consolidated indebtedness to consolidated EBITDA, as calculated under this covenant, of approximately 3.22 is in compliance with this covenant.

	•		Our ratio of consolidated EBITDA to consolidated interest expense (each as defined in the Credit Agreement) must be not less than 2.75 to 1.00 as of the last day of any fiscal quarter, unless we obtain an investment grade rating from Standard and Poor’s Ratings Services or Moody’s Investors Service and the rating from the other agency is not less than Ba1 or BB+, as applicable. At March 31, 2009, our ratio of consolidated EBITDA to consolidated interest expense, as calculated under this covenant, of approximately 4.94 is in compliance with this covenant.

Although it is difficult to predict future commodity pricing, we expect to remain in compliance with the Credit Agreement ratios described above throughout 2009 given the current energy commodity price and NGL margin environment. Inasmuch as the ratios are calculated on a rolling four-quarter basis, the ratios at March 31, 2009, do not reflect a full-year impact of the lower earnings we experienced in late 2008 and the first quarter of 2009. If unexpected events happen or economic conditions or energy commodity prices and NGL margins decline further for a prolonged period of time, our financial covenant ratios may fall below required levels. If such a situation appeared likely, we would take actions necessary to avoid a breach of our covenants, including seeking covenant relief through waivers or the restructuring or replacement of our facility, reducing our indebtedness or seeking assistance from our general partner. Market conditions could make these alternatives challenging, and no assurances can be given that we would be successful in our efforts. Even if successful, we could experience increased borrowing costs and reduced liquidity which could limit our ability to fund capital expenditures and make cash distributions to unitholders. In the event that despite our efforts we breach our financial covenants causing an event of default, the lenders could, among other things, accelerate the maturity of any borrowings under the facility (including our $250.0 million term loan) and terminate their commitments to lend.

In addition, our ability to borrow the remaining $188.0 million currently available under the Credit Agreement could be restricted by the impact of weaker energy commodity prices or future borrowings. Either could limit our ability to borrow the full amount under the Credit Agreement to the extent such new borrowing would cause us to be out of compliance at the end of the fiscal quarter with either of the financial ratios discussed above.

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.~~requirements. 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. Borrowings under the credit facility mature on June 20, 2009. We expect that Williams will renew this revolving credit facility upon maturity. As of ~~September 30, 2008,~~March 31, 2009, 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 Wamsutter’s working capital requirements. ~~Wamsutter is required to and has reduced all borrowings~~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.~~mature on December 12, 2009 with four, one-year automatic extensions unless terminated by either party. As of ~~September 30, 2008,~~March 31, 2009, Wamsutter had no outstanding borrowings under the ~~working capital~~ credit facility.

~~Negotiation with the Jicarilla Apache Nation~~Credit Ratings

~~As previously discussed,~~The table below presents our ~~negotiations~~current credit ratings on our senior unsecured long-term debt.


			Senior Unsecured
Rating Agency	Date of Last Change	Outlook	Debt Rating
Standard & Poor’s.	November 9, 2007	Stable	BBB-
Moody’s Investor Service	November 6, 2008	Negative	Ba2
Fitch Ratings	May 8, 2008	Stable	BB+

At March 31, 2009, the evaluation of our credit rating is “stable outlook” from Standard and Poor’s and Fitch Ratings agencies. On November 6, 2008, Moody’s Investors Service (Moody’s) changed the ratings outlook for Williams and each of Williams’ rated subsidiaries, including WPZ, from “stable” to “negative” following the announcement that Williams’ management and board of directors were evaluating a variety of structural changes to Williams. On February 26, 2009, Moody’s revised Williams, and certain Williams’ rated subsidiaries, excluding us, to “stable” from “negative.”

With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.

With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor’s may modify its ratings with ~~JAN have expanded~~a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from ~~an asset sale~~Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to ~~discussing other alternative arrangements. Entering into an alternative arrangement could require an upfront cash payment~~allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the ~~JAN and~~obligor’s relative standing within a major rating category.

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might ~~also require ongoing~~increase our future ~~periodic payments to the JAN.~~cost of borrowing.

The following table provides summary information related to our, Wamsutter’s and Discovery’s expected capital expenditures for ~~2008~~2009 and actual spending through ~~September 30, 2008 (millions)~~March 31, 2009 (in millions):

Maintenance Expansion Total
Through Through Through
Company Total Year Estimate September 30, 2008 Total Year Estimate September 30, 2008 Total Year Estimate September 30, 2008
Four Corners $ 22.8 $ 14.7 $ 7.3 $ 3.6 $ 30.1 $ 18.3
Conway 2.7 1.6 7.3 4.7 10.0 6.3
Wamsutter — (our share) 19.2 15.4 7.9 2.3 27.1 17.7
Discovery — (our share) 3.5 0.7 7.7 2.3 11.2 3.0

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 nor repairs to Discovery’s offshore-gathering system damaged by Hurricane Ike. We expect those expenditures that exceed the property insurance deductible will be reimbursed by insurance. Our Statement of Cash Flows through September 30, 2008 includes $12.4 million of these reimbursed or reimbursable capital expenditures for the Ignacio plant.


	Maintenance				Expansion				Total
			Through				Through				Through
Company	Total Year Estimate		Mar. 31, 2009		Total Year Estimate		Mar. 31, 2009		Total Year Estimate		Mar. 31, 2009
Four Corners	$	15 - 20	$	5.0	$	5 - 10	$	.2	$	20 - 30	$	5.2
Conway		3 - 6		.2		8 - 12		1.6		11 - 18		1.8
Wamsutter (our share)		20 - 25		5.4		1 - 2		.5		21 - 27		5.9
Discovery (our share)		1 - 3		—		4 - 7		1.9		5 - 10		1.9

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~~estimated maintenance capital expenditures ~~includes approximately $11.0~~for 2009 include a range of $12.0 million to $14.0 million related to well connections necessary to connect new sources of throughput for the Four Corners’ system which will serve to partially offset the historical decline in throughput volumes. Four Corners’ ~~2008~~2009 expansion capital expenditures relate primarily to ~~plant and~~ gathering system expansion projects. Both Four Corners’ actual maintenance expenditures through September 2008 and total year estimated maintenance expenditures have been reduced $3.5 million for amounts reimbursed by producers for prior-year well connect costs. Conway’s ~~2008~~ expansion capital expenditures relate to ~~various small projects.~~two projects: first, the drilling of two new ethane/propane mix caverns and conversion of certain ethane/propane caverns for use as propane storage caverns and second, the completion of a project to improve our flexibility and storage capabilities with respect to refinery grade butane.

Wamsutter’s ~~2008~~estimated maintenance capital expenditures for 2009 include ~~approximately $18.0~~a range of $20.0 million to $22.0 million related to well connections necessary to connect new sources of throughput for the Wamsutter system which will 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. Wamsutter will issue Class C units to us for the expansion capital projects we fund.

Discovery will fund its ~~2008~~2009 maintenance and expansion capital expenditures either by cash calls to its members or from its cash flows from operations. We funded a cash call from Discovery for $3.1 million in March 2009 for the Tahiti project and in second-quarter 2009, we will receive a $1.8 million reimbursement of those costs pursuant to the requirements of our omnibus agreement with Williams.

Cash Distributions to Unitholders

We paid quarterly distributions to common and subordinated unitholders and our general partner interest after every quarter since our ~~IPO~~initial public offering on August 23, 2005. Our ~~most recent~~next quarterly distribution of ~~$41.6~~$34.2 million will be paid on ~~November 14, 2008~~May 15, 2009 to the general partner interest and common unitholders of record at the close of business on ~~November 7, 2008. This distribution includes an incentive distribution to our general partner of approximately $7.3 million.~~May 8, 2009.

~~The $40.2~~Net cash provided by operating activitiesdecreased $35.7 million ~~increase~~for first-quarter 2009 as compared to first-quarter 2008 due primarily to $21.0 million lower distributions related to equity earnings in Discovery and Wamsutter, $11.8 million decrease from changes in working capital excluding accrued interest and $8.2 million lower operating income excluding non-cash items. These decreases in net cash provided by operating activities ~~for the first nine months~~were partially offset by $4.0 million of ~~2008 as compared to the first nine months of 2007 is due primarily to $95.6 million higher distributions from Wamsutter and Discovery and an $8.6 million increase in operating~~2009 hurricane-related income ~~net of non-cash items. Largely offsetting this increase in net cash provided by operating activities are the following:~~

	•		$38.1 million decrease in cash provided by working capital excluding accrued interest. Cash provided by working capital decreased due primarily to changes in accounts payable and accounts receivable; and

	•		$24.2 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.

under our Discovery-related business interruption policy.

Net cash used by investing activities indecreased $5.3 million for first-quarter 2009 as compared to first-quarter 2008 ~~includes $12.4~~due primarily to $11.1 million oflower capital expenditures, ~~for the replacement of capital assets destroyed~~partially offset by ~~the November 2007 fire at Four Corners’ Ignacio gas processing plant and $12.2~~$3.2 million of the related insurance proceeds received for some of those capital expenditures. Additionally, net cash used by investing activities in both years includes (1) 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, and (2) cumulativelower distributions in excess of equity earnings from ~~Discovery. Net~~Discovery and $2.6 million higher contributions to Discovery for cash ~~used by investing activities in 2007 includes~~calls related to the ~~acquisition of an additional 20% ownership interest in Discovery in June 2007.~~hurricane damage repair and expansion project funding.

Net cash used by financing activities isincreased $6.9 million for first-quarter 2009 as compared to first-quarter 2008 due primarily ~~comprised of~~to an increase in quarterly distributions to unitholders ~~which have increased 81% for~~and our general partner.


	Three months ended
	March 31,
*Wamsutter — 100 percent*	2009			2008
	(Thousands)
Net cash provided by operating activities	$	19,166		$	28,625
Net cash used by investing activities		(18,487	)		(4,089	)
Net cash used by financing activities		(679	)		(24,536	)

Net cash provided by operating activitiesdecreased $9.5 million in the first ~~nine months~~quarter of ~~2008~~2009 as compared to the first ~~nine months~~quarter of ~~2007.~~

Nine months ended
September 30,
Wamsutter 100% 2008 2007
(Thousands)

Net cash provided by operating activities $ 107,903 $ 66,837

Net cash used by investing activities (33,415 ) (26,293 )

Net cash used by financing activities (74,488 ) (40,544 )

~~The $41.1 million increase in net cash provided by operating activities in the first nine months of~~ 2008 ~~as compared to the first nine months of 2007 is~~ due primarily to ~~$42.8~~a $5.5 million ~~increase~~decrease in operating income, as adjusted for non-cash ~~expenses.~~expenses, and a $3.9 million decrease related to changes in working capital.

Net cash used by investing activitiesin the first quarter of 2009 is primarily comprised of capital expenditures related to plant expansion projects and connection of new wells. The plant expansion projects include $10.1 million which was funded by Williams in accordance with Wamsutter’s limited liability company (LLC) agreement. Net cash used by investing activities in the first ~~nine months~~quarter of 2008 ~~and 2007~~ is primarily comprised of capital expenditures related to the connection of new wells.

Net cash used by financing activitiesin the first ~~nine months~~quarter of ~~2008~~2009 is ~~almost entirely~~ related to cash distributions to Wamsutter’s members pursuant to the distribution provisions of Wamsutter’s ~~limited liability company agreement.~~LLC agreement substantially offset by capital contributions received from Wamsutter’s members for certain capital projects. Net cash used by financing activities in the first ~~nine months~~quarter of ~~2007~~2008 is primarily related to cash distributions to Wamsutter’s members pursuant to the distribution provisions of Wamsutter’s ~~net~~LLC agreement.


	Three months ended
	March 31,
*Discovery — 100 percent*	2009			2008
	(Thousands)
Net cash provided (used) by operating activities	$	(928	)	$	32,043
Net cash used by investing activities		(7,551	)		(3,882	)
Net cash provided (used) by financing activities		3,332			(25,672	)

Net cash ~~flows to Williams pursuant to its participation in Williams’ cash management program.~~

Nine months ended
September 30,
Discovery 100 % 2008 2007
(Thousands)

Net cash provided by operating activities $ 84,818 $ 39,557

Net cash used by investing activities (5,715 ) (7,444 )

Net cash used by financing activities (73,672 ) (41,252 )

~~The $45.3~~provided (used) by operating activitieschanged unfavorably from $32.0 million ~~increase in~~ net cash provided ~~by operating activities~~ in the first quarter of 2008 ~~as compared~~ to ~~2007 is~~$0.9 million net cash used in the first quarter of 2009 due primarily to ~~$24.1~~$31.1 million ~~increase in operating~~lower net income as adjusted for non-cash ~~expenses,~~items.

Net cash used by investing activitiesincludes $10.2 million and ~~$22.9~~$6.5 million ~~increase~~of capital spending in the first quarters of 2009 and 2008, respectively, for the Tahiti lateral and other smaller projects. These expenditures were partially offset by changes in Tahiti-related restricted cash ~~provided by working capital. The increase~~ in cash provided by working capital is due primarily to significantly lower receivable balances at September 30, 2008 resulting from substantially reduced processing caused by the Hurricanes Ike and Gustav.both quarters.

4129

Net cash ~~used~~provided (used) by financing activities ~~increased $32.4~~changed from $25.7 million net cash used in the first quarter of 2008 to $3.3 million net cash provided in the first quarter of 2009 due primarily to ~~$30.8~~the lack of $28.0 million ~~higher~~cash distributions ~~paid~~ to ~~members.~~the partners in 2009.

~~Fair Value Measurements~~Contractual Obligations

~~On January 1,~~Our contractual obligations changed from our 2008 ~~we adopted Statement~~Form 10-K as a result of ~~Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements”, for~~ our ~~assets and liabilities that are measured at fair value on~~February 2009 execution of 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~~20-year right-of-way agreement with the ~~fair value hierarchy levels and valuation methodologies.~~JAN by the following amounts:

At September 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 decreased $15.6 million and $6.1 million during the three and nine months ending September 30, 2008, respectively, which resulted in an ending net energy derivative asset at September 30, 2008. The effective portion of the net unrealized gain (loss) from the change in fair value recorded in other comprehensive income was $10.0 million and $(0.4) million during the three and nine month periods ending September 30, 2008, respectively.


	2009		2010-2011		2012-2013		2014+		Total
	(in thousands)
Operating leases(a)	$	7,340	$	15,056	$	15,056	$	112,920	$	150,372


(a)		Each year from 2010 through 2029 will also include an additional annual payment, which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by Four Corners’ gathering facilities subject to the agreement. The table above does not include any such variable amounts related to this agreement.

~~Item 3. Quantitative and Qualitative Disclosures About Market Risk~~


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 NGLs 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. WeDuring 2009, we are not party to any derivative contracts to 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.fluctuations.

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 NGL 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 $0.3 million at September 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 ~~nine~~three months of ~~2008.~~2009. See Note 6, Long-Term Debt and Credit Facilities, 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.


Item 4.		Controls and Procedures

Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that our ~~Disclosure Controls~~disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (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~~Williams Partners L.P. 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.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our 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 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.

First-Quarter 2009 Changes in Internal ~~Control~~Controls Over Financial Reporting

There have been no changes during the ~~third~~first quarter of ~~2008~~2009 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~~


Item 1.		Legal Proceedings

The information required for this item is provided in Note 9,7, Commitments and Contingencies, included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which information is incorporated by reference into this item.

~~Item 1A. Risk Factors~~


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,~~2008, 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~~We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases may be ~~adversely affected by restrictions~~linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of greenhouse gases have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, and all of which can create financial risks.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities and could exceed current expectations.

The risk of substantial environmental costs and liabilities is inherent in natural gas gathering, transportation, processing and treating, and in the fractionation and storage of NGLs, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. For a description of these laws and regulations, please read “Business and Properties — Environmental Regulation” in our ~~debt agreements~~Annual Report on Form 10-K for the year ended December 31, 2008.

Various governmental authorities, including the U.S. Environmental Protection Agency and ~~by our leverage.~~

~~In December 2007, we borrowed $250.0 million~~analogous state agencies and the United States Department of Homeland Security, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the ~~term loan portion~~assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our new $450.0 million five-year senior unsecured credit facility. Our total outstanding long-term debt as of September 30, 2008 was $1.0 billion, representing approximately 81% of our total book capitalization.operations.

4331

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we gather, transport, process, fractionate and store, air emissions related to our operations, historical industry operations, waste disposal practices, and the prior use of flow meters containing mercury. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including the Federal Comprehensive Environmental Response, Compensation, and Liability Act, the Federal Resource Conservation and Recovery Act, and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary.

Our ~~debt service obligations~~insurance may not cover all environmental risks and ~~restrictive covenants~~costs or may not provide sufficient coverage if an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change. In addition, new environmental laws and regulations might adversely affect our products and activities, including processing, fractionation, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability. In addition, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the earth’s atmosphere, and various governmental bodies have considered legislative and regulatory responses in this area.

Legislative and regulatory responses related to greenhouse gases and climate change create the potential for financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. There have also been international efforts seeking legally binding reductions in emissions of greenhouse gases. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate the emission of greenhouse gases.

Several bills have been introduced in the ~~indentures governing~~United States Congress that would compel carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of greenhouse gases that can be emitted (so-called “caps”), together with systems of emissions allowances. These actions could result in increased costs to (i) operate and maintain 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~~facilities, (ii) install new emission controls on our ~~operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business~~facilities, and ~~other factors, many~~(iii) administer and manage any greenhouse gas emissions program. Numerous states have also announced or adopted programs to stabilize and reduce greenhouse gases, and similar federal legislation has been introduced in both houses 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.~~Congress. If we are unable to ~~meet~~recover or pass through all costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our ~~debt service obligations or obtain future credit on favorable terms, if at all,~~results of operations and our ability to make distributions to unitholders. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively impact our cost of and access to capital.

Our assets and operations can be affected by weather and other natural phenomena.

Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we ~~could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We~~ may be unable to obtain ~~financing~~insurance on commercially reasonable terms, if at all. A significant disruption in operations or ~~sell assets on satisfactory terms, or at all.~~

~~We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of~~a 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~~liability for 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~~were 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 thatfully insured could have a material adverse effect on our business, results of operations and 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.

Recent events in the global financial crisis have made equity and debt markets less accessible and created a shortage in the availability of credit, which could disrupt our financing plans and limit our ability to grow.

Public equity markets have recently experienced significant declines, and global credit markets have experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. Under current market conditions, it is unclear whether we could issue additional equity or debt securities or, even if we were able, whether we could do so at prices and pursuant to terms that would be acceptable to us. We have availability under our credit facility, but our ability to borrow under the facility could be impaired if one or more of our lenders fail to honor its contractual obligation to lend to us. Continuing or additional disruptions in the global financial marketplace, including the bankruptcy or restructuring of certain financial institutions, could make equity and debt markets inaccessible and adversely affect the availability of credit already arranged and the availability and cost of credit in the future.

~~As a publicly traded partnership, these developments could significantly impair~~ our ability to make ~~acquisitions~~distributions to unitholders.

Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or ~~finance growth projects. We distribute all~~demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of ~~our available cash~~the changes, leading either to ~~our unitholders on a quarterly basis. We typically rely upon external financing sources, including the issuance of debt and equity securities and bank borrowings, to fund acquisitions~~increased investment or expansion capital expenditures. Any limitations on our access to external 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. As a result, we may be at a competitive disadvantage as compared to businesses that reinvest all of their available cash to expand ongoing operations, particularly under current economic conditions.

~~The failure of counterparties to perform their contractual obligations could adversely affect our operating results, financial condition and cash available to pay distributions.~~

Despite performing credit analysis prior to extending credit, we are exposed to the credit risk of our contractual counterparties in the ordinary course of business even though we monitor these situations and attempt to take appropriate measures to protect ourselves. In addition to credit risk, counterparties to our commercial agreements, such as product sales, gathering, treating, storage, transportation, processing and fractionation agreements may fail to perform their other contractual obligations. A failure of counterparties to perform their contractual obligations could adversely affect our operating results, financial condition and cash available to pay distributions. A general downturn in the economy and tightening of global credit markets could cause more of our counterparties to fail to perform than we have expected.decreased revenues.

4532

~~Item 6. Exhibits~~


Item 6.		Exhibits

The following documents are included as exhibits to this report:


Exhibit
Number		Description


*Exhibit 103.1		Certificate of Limited Partnership of Williams Partners L.P. (attached as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517) filed with the SEC on May 2, 2005).

*Exhibit 3.2		Certificate of Formation of Williams Partners GP LLC (attached as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517) filed with the SEC on May 2, 2005).

+Exhibit 3.3		Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4 and 5.

*Exhibit 3.4		Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (attached as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the SEC on August 26, 2005).

*#Exhibit 10.1		Director Compensation Policy dated November 29, 2005, as revised ~~August 20, 2008.~~January 26, 2009 (attached as Exhibit 10.8 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599) filed with the SEC on February 26, 2009).

*Exhibit ~~31.1~~10.2		~~Rule 13a-14(a)/15d-14(a) Certification~~Amendment No. 1 to Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of ~~Chief Executive Officer.~~Articles V and VI thereof only) The Williams Companies, Inc. (attached as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the SEC on April 20, 2009).

+Exhibit ~~31.2~~31.1		~~Rule 13a-14(a)/15d-14(a)~~ Certification of ~~Chief Financial Officer.~~Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

+Exhibit 31.2		Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

+Exhibit 32		~~Section 1350 Certifications~~Certification of ~~Chief~~Principal Executive Officer and ~~Chief~~Principal Financial ~~Officer.~~Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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

+		Filed herewith.

#		Management contract or compensatory plan or arrangement.

4633

EXHIBIT INDEX


Exhibit
Number		Description

*Exhibit 3.1		Certificate of Limited Partnership of Williams Partners L.P. (attached as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517) filed with the SEC on May 2, 2005).

*Exhibit 103.2		Certificate of Formation of Williams Partners GP LLC (attached as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517) filed with the SEC on May 2, 2005).

+Exhibit 3.3		Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4 and 5.

*Exhibit 3.4		Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (attached as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the SEC on August 26, 2005).

*#Exhibit 10.1		Director Compensation Policy dated November 29, 2005, as revised ~~August 20, 2008.~~January 26, 2009 (attached as Exhibit 10.8 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599) filed with the SEC on February 26, 2009).

*Exhibit ~~31.1~~10.2		~~Rule 13a-14(a)/15d-14(a) Certification~~Amendment No. 1 to Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of ~~Chief Executive Officer.~~Articles V and VI thereof only) The Williams Companies, Inc. (attached as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) filed with the SEC on August 20, 2009).

+Exhibit ~~31.2~~31.1		~~Rule 13a-14(a)/15d-14(a)~~ Certification of ~~Chief Financial Officer.~~Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

+Exhibit 31.2		Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

+Exhibit 32		~~Section 1350 Certifications~~Certification of ~~Chief~~Principal Executive Officer and ~~Chief~~Principal Financial ~~Officer.~~Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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

+		Filed herewith.

#		Management contract or compensatory plan or arrangement.

4835


*(a)		Retrospectively adjusted as discussed in Note 1.

~~(a)~~		~~Includes Class B units converted to common units on May 21, 2007.~~

~~(b)~~		~~Includes subordinated units converted to common units on February 19, 2008.~~2.


	March 31,			December 31,
	2009			2008
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	77,287		$	116,165
Accounts receivable:
Trade		17,750			16,279
Affiliate		16,001			11,652
Other		1,390			2,919
Product imbalance		3,926			6,344
Prepaid expense		9,568			4,102
Reimbursable projects		1,166			—
Other current assets		2,565			3,642

Total current assets		129,653			161,103
Investment in Wamsutter		277,869			277,707
Investment in Discovery Producer Services		184,342			184,466
Gross property, plant and equipment		1,265,874			1,265,153
Less accumulated depreciation		(630,826	)		(624,633	)

Property, plant and equipment, net		635,048			640,520
Other noncurrent assets		27,181			28,023

Total assets	$	1,254,093		$	1,291,819

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable:
Trade	$	20,410		$	22,348
Affiliate		12,435			11,122
Product imbalance		3,153			8,926
Deferred revenue		844			4,916
Accrued interest		10,659			18,705
Other accrued liabilities		9,734			6,172

Total current liabilities		57,235			72,189
Long-term debt		1,000,000			1,000,000
Environmental remediation liabilities		2,014			2,321
Other noncurrent liabilities		13,832			13,699
Commitments and contingent liabilities (Note 7)
Partners’ capital		181,012			203,610

Total liabilities and partners’ capital	$	1,254,093		$	1,291,819


*		~~Retrospectively adjusted as discussed in Note 1.~~

~~(a)~~		~~During~~Using the second quarter of 2007, we converted our outstanding Class B units 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 $5.3 million is included in net income available to limited partners; however, it is excluded for the calculation of earnings per limited partner unit. It does not affect total net income, cash flows or total partners’ equity.

~~(b)~~		~~Under the “two class”~~ method of computing earnings per ~~share~~unit prescribed by ~~SFAS No. 128, “Earnings Per Share,” we allocate earnings to participating securities as if all of~~EITF 07-4, the ~~earnings for the period had been distributed. As a result, the general partner receives an additional allocation of~~net 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 additional allocation of incomeallocated to the general partner ~~for~~includes IDRs pertaining to the ~~three and nine months ended September 30, 2008 is $10.0 million and $30.6 million, respectively.~~current reporting period, but paid in the subsequent period. The ~~additional allocation of~~net income allocated to the general ~~partner for~~partner’s capital account reflects IDRs paid during the ~~three and nine months ended September 30, 2007 was $3.7 million.~~current reporting period.


	Page
Part I. Financial Information

Item 1. Financial Statements

Consolidated Statements of Income — Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~		5
		3
Consolidated Balance Sheets — ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007~~2008		6
		4
Consolidated Statements of Cash Flows — ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~		7
		5
Consolidated Statement of Partners’ Capital from January 1, ~~2008~~2009 to ~~September 30, 2008~~March 31, 2009		8
		6
Notes to Consolidated Financial Statements		9
		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
		15
Item 3. Quantitative and Qualitative Disclosures About Market Risk		42
		30
Item 4. Controls and Procedures		43
		30
Part II. Other Information

Item 1. Legal Proceedings		43
		31
Item 1A. Risk Factors		43
		31
Item 6. Exhibits		4633
~~EX-10~~EX-3.3
EX-31.1
EX-31.2
EX-32


										Accumulated Other			Total
	Limited Partners						General			Comprehensive			Partners’
	Common			Subordinated			Partner			Income (Loss)			Capital
							(In thousands)
Balance — January 1, 2008	$	1,473,814		$	109,542		$	(1,419,382	)	$	(2,487	)	$	161,487
Net income		155,991			1,556			18,737			—			176,284
Other comprehensive income (loss):
Net unrealized losses on cash flow hedges		—			—			—			(358	)		(358	)
Reclassification into earnings of derivative instrument losses		—			—			—			6,497			6,497

Total other comprehensive income														6,139

Total comprehensive income														182,423
Cash distributions		(90,970	)		(4,025	)		(18,770	)		—			(113,765	)
Conversion of subordinated units into common		107,073			(107,073	)		—			—			—
Contributions pursuant to the omnibus agreement		—			—			2,328			—			2,328
Issuance of units to public		28,992			—			—			—			28,992
Repurchase of units from Williams		(28,992	)		—			—			—			(28,992	)
Other		(405	)		—			1,015			—			610


Balance — September 30, 2008	$	1,645,503		$	—		$	(1,416,072	)	$	3,652		$	233,083


(a)		~~3.2375%~~1.27% at ~~September 30, 2008.~~March 31, 2009.


	Net Derivative
	Asset (Liability)
Balance as of July 1, 2008	$	(11,978	)
Realized and unrealized gains:
Included in net income		143
Included in other comprehensive income		10,015
Purchases, issuances, and settlements		5,458
Transfers in/(out) of Level 3		—

Balance as of September 30, 2008	$	3,638


Unrealized gains included in net income relating to instruments still held at September 30, 2008	$	4,962


	Net Derivative
	Asset (Liability)
Balance as of January 1, 2008	$	(2,487	)
Realized and unrealized losses:
Included in net income		(214	)
Included in other comprehensive income		(358	)
Purchases, issuances, and settlements		6,697
Transfers in/(out) of Level 3		—

Balance as of September 30, 2008	$	3,638


Unrealized gains included in net income relating to instruments still held at September 30, 2008	$	4,585


(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.

	•		$~~15.2~~28.5 million ~~from 36% higher~~related to a 59% decrease in average ~~per-unit~~ NGL sales prices realized on sales of NGLs which we received under keep-whole and percent-of-liquids processing contracts. ~~The higher per-unit NGL sales prices are caused by~~This decrease resulted from general ~~increases~~decreases in market prices for these commodities between the two periods;

	•		$~~4.5~~15.8 million ~~higher~~lower sales ~~prices on lower NGL volumes sold~~of NGLs on behalf of third-party producers. Under these arrangements, we purchase the NGLs from the third-party producers and sell them to an affiliate. This ~~increase~~decrease was primarily related to lower market prices and is offset by ~~higher~~lower associated product costs of ~~$4.6~~$15.7 million discussed below; and

	•		$~~2.0~~5.5 million ~~higher~~lower condensate and ~~LNG~~liquified natural gas (LNG) sales resulting from ~~higher~~decreased average per-unit ~~sales~~condensate prices ~~for both condensate~~ and ~~LNG and higher condensate sales volumes.~~

	•		~~These product sales increases were partially offset by a decrease of $3.4 million related to 8%~~ lower ~~NGL sales volumes resulting from lower processed~~LNG volumes.

	•		~~$4.6 million higher NGLs purchased from third-party producers, which was offset by the corresponding increased product sales discussed above; and~~

	•		~~$4.6 million increase from 31% higher average natural gas prices.~~

	•		~~lower processing volumes caused~~were reduced by ~~prolonged, severe weather during early 2008; and~~

	•		~~lower processing volumes resulting from the impact of the November 2007 fire at the Ignacio gas processing plant which was shut down until January 18, 2008.~~

	•		$~~5.9 million increase from 64% higher average natural gas prices. Gas prices in 2007 were impacted by very low local natural gas costs compared with other natural gas markets.~~

	•		~~$1.7 million increase from 23% higher volumetric shrink requirements due to higher volumes processed under Wamsutter’s keep-whole processing contracts.~~

	•		~~$11.0 million higher product sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes; and~~

	•		~~$1.6 million lower operating and maintenance expense.~~


Wamsutter Net Income Allocation	Our Share						Other		Wamsutter
(Dollars in millions)	Class A		Class C		WPZ Total		Class C		Net Income
Net income, beginning December 1, 2007 up to $70.0 million.*	$	62.6	$	—	$	62.6	$	—	$	62.6
Net income allocation related to transition support payments paid to us		5.7		—		5.7		—		5.7
Remainder net income allocated to Class C members		—		11.2		11.2		11.2		22.4


Totals	$	68.3	$	11.2	$	79.5	$	11.2	$	90.7

	•		Fractionation revenues increased $6.3 million due primarily to a 67% higher average fractionation rate and slightly higher fractionation volumes. The higher average rate is due primarily to the December 2007 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 sales ~~increased $5.4~~decreased $3.0 million due to ~~higher~~a 54% decrease in average prices per barrel and lower sales volumes of ethane and ~~a 39% increase~~normal butane. The decrease in ~~average propane prices. This increase~~sales prices and volumes was offset by the related ~~increase~~decrease in product cost discussed below.

	•		~~Storage~~Fractionation revenues ~~increased $2.1~~decreased $0.7 million due primarily to ~~higher storage revenues from new storage leases.~~


(1)		The original amount has been reduced by $12.0 million due to the ~~Lehman bankruptcy.~~bankruptcy of the parent company and certain affiliates of Lehman. See Note 6, Long-Term Debt and Credit Facilities, of our Notes to Consolidated Financial Statements. The committed amounts of other participating banks ~~under this agreement~~ remain in effect and are not impacted by this reduction. Additionally, availability of our capacity under this credit facility in future periods could be constrained by compliance with required covenants.


	Total Distribution		Our Share
Date of Distribution	to Members		Class A		Class C		Other Class C
3/28/08	$	25,000	$	17,874	$	3,563	$	3,563
6/30/08		30,500		18,150		6,175		6,175
9/30/08		35,500		18,400		8,550		8,550

Total	$	91,000	$	54,424	$	18,288	$	18,288


	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
10/30/08	$18,000	$10,800

	•		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, including certain well connection 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 to extend their useful lives including expenditures which are mandatory and/or essential for maintaining the reliability of our operations; and

	•		Expansion capital expenditures, which tend to be more discretionary than maintenance capital expenditures, include expenditures 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.


	Nine months ended
	September 30,
Wamsutter 100%	2008			2007
	(Thousands)

Net cash provided by operating activities	$	107,903		$	66,837

Net cash used by investing activities		(33,415	)		(26,293	)

Net cash used by financing activities		(74,488	)		(40,544	)


	Nine months ended
	September 30,
Discovery 100 %	2008			2007
	(Thousands)

Net cash provided by operating activities	$	84,818		$	39,557

Net cash used by investing activities		(5,715	)		(7,444	)

Net cash used by financing activities		(73,672	)		(41,252	)


		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)