Edgar Filing: Western Gas Partners LP

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2009


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: 001-34046

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		26-1075808 (I.R.S. Employer Identification No.)

1201 Lake Robbins Drive The Woodlands, Texas (Address of principal executive offices)		77380 (Zip Code)

(832) 636-6000
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

There were 29,474,925 common units outstanding as of July 31, 2009.

TABLE OF CONTENTS


	Page
PART I FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Statements of Income for the three and six months ended June 30, 2009 and 2008		4

Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008		5

Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008		6

Notes to Unaudited Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3. Quantitative and Qualitative Disclosures About Market Risk		44

Item 4T. Controls and Procedures		45

PART II OTHER INFORMATION

Item 1. Legal Proceedings		45

Item 6. Exhibits		45
EX-31.1
EX-31.2
EX-32.1

Definitions

As generally used within the energy industry and in this Quarterly Report on Form 10-Q, the identified terms have the following meanings:

Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.

Bcf/d: One billion cubic feet per day.

Btu: British thermal unit.

CO₂: Carbon dioxide.

Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

Drip condensate: Heavier hydrocarbon liquids that fall out of the natural gas stream and are recovered in the gathering system without processing.

Imbalance: Imbalances result from (i) differences between gas volumes nominated by customers and gas volumes received from those customers and (ii) differences between gas volumes received from customers and gas volumes delivered to those customers.

Long ton: A British unit of weight equivalent to 2,240 pounds.

LTD: One long ton per day.

MMBtu: One million British thermal units.

MMBtu/d: One million British thermal units per day.

MMcf/d: One million cubic feet per day.

Natural gas: Hydrocarbon gas found in the earth composed of methane, ethane, butane, propane and other gases.

Natural gas liquids or NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Residue gas: The natural gas remaining after being processed or treated.

Sour gas: Natural gas containing more than four parts per million of hydrogen sulfide.

Tcf: One trillion cubic feet of natural gas.

Wellhead: The equipment at the surface of a well used to control the well’s pressure; the point at which the hydrocarbons and water exit the ground.

PART I. FINANCIAL INFORMATION


Item 1.		Financial Statements

Western Gas Partners, LP

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited, in thousands, except per-unit amounts)


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009		2008⁽¹⁾			2009			2008⁽¹⁾
Revenues — affiliates
Gathering, processing and transportation of natural gas	$	26,989	$	27,599		$	53,900		$	54,794
Natural gas, natural gas liquids and condensate sales		14,497		48,996			31,006			91,603
Equity income and other		2,639		5,017			4,369			5,667

Total revenues — affiliates		44,125		81,612			89,275			152,064

Revenues — third parties
Gathering, processing and transportation of natural gas		3,770		3,446			7,576			7,556
Natural gas, natural gas liquids and condensate sales		1,934		5,555			3,404			10,882
Other, net		145		(4	)		607			1,529

Total revenues — third parties		5,849		8,997			11,587			19,967


Total Revenues		49,974		90,609			100,862			172,031


Operating Expenses⁽²⁾
Cost of product		9,489		47,839			22,017			81,567
Operation and maintenance		10,371		12,397			19,607			23,343
General and administrative		3,860		2,792			8,583			4,752
Property and other taxes		1,771		1,717			3,528			3,350
Depreciation and amortization		8,752		8,204			17,373			15,986

Total Operating Expenses		34,243		72,949			71,108			128,998


Operating Income		15,731		17,660			29,754			43,033
Interest income, net — affiliates		2,439		2,060			4,879			271
Other income, net		9		27			14			31


Income Before Income Taxes		18,179		19,747			34,647			43,335

Income tax expense (benefit)		55		4,168			(435	)		12,635


Net Income	$	18,124	$	15,579		$	35,082		$	30,700


Calculation of Limited Partner Interest in Net Income:
Net income⁽³⁾	$	18,124	$	8,249		$	35,082		$	8,249
Less general partner interest in net income		362		165			702			165

Limited partner interest in net income	$	17,762	$	8,084		$	34,380		$	8,084

Net income per limited partner unit — basic and diluted	$	0.32	$	0.15		$	0.62		$	0.15
Limited partner units outstanding — basic and diluted		55,645		53,103			55,637			53,103


⁽¹⁾		Financial information for 2008 has been revised to include results attributable to the Powder River assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition.

⁽²⁾		Operating expenses include amounts charged by Anadarko and its affiliates to the Partnership for services as well as reimbursement of amounts paid by Anadarko and its affiliates to third parties on behalf of the Partnership. Cost of product expenses include product purchases from Anadarko and its affiliates of $0.8 million and $6.2 million for the three months ended June 30, 2009 and 2008, respectively, and $2.5 million and $13.4 million for the six months ended June 30, 2009 and 2008, respectively. Operation and maintenance expenses include charges from affiliates of $4.9 million and $4.6 million for the three months ended June 30, 2009 and 2008, respectively, and $8.6 million and $8.7 million for the six months ended June 30, 2009 and 2008, respectively. General and administrative expenses include charges from affiliates of $3.0 million and $2.5 million for the three months ended June 30, 2009 and 2008, respectively, and $6.4 million and $4.4 million for the six months ended June 30, 2009 and 2008, respectively. See Note 5—Transactions with Affiliates.

⁽³⁾		General and limited partner interest in net income for 2008 represents net income attributable to the initial assets since the closing of the Partnership’s initial public offering on May 14, 2008. See Note 4—Net Income per Limited Partner Unit.

See accompanying notes to the unaudited consolidated financial statements.

Western Gas Partners, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited, in thousands, except number of units)


	June 30,		December 31,
	2009		2008
ASSETS
Current Assets
Cash and cash equivalents	$	39,858	$	33,306
Accounts receivable, net — third parties		3,300		5,878
Accounts receivable — affiliates		3,731		3,235
Natural gas imbalance receivables — third parties		11		389
Natural gas imbalance receivables — affiliates		66		1,422
Other current assets		684		1,149

Total current assets		47,650		45,379

Note receivable — Anadarko		260,000		260,000
Property, Plant and Equipment
Cost		700,295		689,945
Less accumulated depreciation		189,320		172,130

Net property, plant and equipment		510,975		517,815
Goodwill		14,436		14,436

Equity investment		19,412		18,183
Other assets		564		628

Total Assets	$	853,037	$	856,441


LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable	$	4,242	$	5,544
Natural gas imbalance payable — third parties		220		244
Natural gas imbalance payable — affiliates		1,119		1,198
Accrued ad valorem taxes		3,667		1,330
Income taxes payable		265		146
Accrued liabilities — third parties		4,965		7,726
Accrued liabilities — affiliates		160		153

Total current liabilities		14,638		16,341
Long-Term Liabilities
Note payable — Anadarko		175,000		175,000
Deferred income taxes		499		1,053
Asset retirement obligations and other		9,379		9,093

Total long-term liabilities		184,878		185,146

Total Liabilities		199,516		201,487

Commitments and Contingencies (Note 11)

Partners’ Capital
Common units (29,123,501 and 29,093,197 units issued and outstanding at June 30, 2009 and December 31, 2008, respectively)		366,135		368,049
Subordinated units (26,536,306 units issued and outstanding at June 30, 2009 and December 31, 2008)		276,378		275,917
General partner units (1,135,296 units issued and outstanding at June 30, 2009 and December 31, 2008)		11,008		10,988

Partners’ Capital		653,521		654,954


Total Liabilities and Partners’ Capital	$	853,037	$	856,441

See accompanying notes to the unaudited consolidated financial statements.

Western Gas Partners, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Six Months Ended June 30,
	2009			2008⁽¹⁾
Cash Flows from Operating Activities
Net income	$	35,082		$	30,700
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		17,373			15,986
Deferred income taxes		(554	)		1,614
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(582	)		2,211
(Increase) decrease in natural gas imbalance receivable		1,733			(2,814	)
Increase (decrease) in accounts payable, accrued liabilities and natural gas imbalance payable		(327	)		964
Change in other items, net		(124	)		(2,031	)

Net cash provided by operating activities		52,601			46,630
Cash Flows from Investing Activities
Loan to Anadarko		—			(260,000	)
Capital expenditures		(11,718	)		(14,376	)
Investment in equity affiliate		(263	)		(5,654	)

Net cash used in investing activities		(11,981	)		(280,030	)
Cash Flows from Financing Activities
Proceeds from issuance of common units		—			315,346
Reimbursement of capital expenditures to parent		—			(45,346	)
Distributions to unitholders		(34,068	)		—
Net distributions to Anadarko		—			(10,812	)

Net cash provided by (used in) financing activities		(34,068	)		259,188

Net Increase in Cash and Cash Equivalents		6,552			25,788
Cash and Cash Equivalents at Beginning of Period		33,306			—

Cash and Cash Equivalents at End of Period	$	39,858		$	25,788


Supplemental Disclosures
Contribution of net assets from parent	$	—		$	318,209
Elimination of deferred tax liabilities		—			76,500
Decrease in accrued capital expenditures		1,377			934
Interest paid		1,821			—


⁽¹⁾		Financial information for 2008 has been revised to include activity attributable to the Powder River assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition.

See accompanying notes to the unaudited consolidated financial statements.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Basis of presentation

Western Gas Partners, LP (the Partnership) is a Delaware limited partnership formed in August 2007. The Partnership’s assets consist of nine gathering systems, six natural gas treating facilities, two gas processing facilities and one interstate pipeline. The Partnership’s assets are located in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, compressing, processing, treating and transporting natural gas for Anadarko Petroleum Corporation and its consolidated subsidiaries and third-party producers and customers. For purposes of these financial statements, “The Partnership” refers to Western Gas Partners, LP and its subsidiaries; “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership; and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership. The Partnership’s general partner is Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko.

The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of financial position as of June 30, 2009 and December 31, 2008, results of operations for the three and six months ended June 30, 2009 and 2008 and statements of cash flows for the six months ended June 30, 2009 and 2008. The Partnership’s financial results for the six months ended June 30, 2009 are not necessarily indicative of the results for the full year ending December 31, 2009.

The accompanying consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States (GAAP). To conform to these accounting principles, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results may differ. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. Changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates.

The accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s annual report on Form 10-K, as filed with the Securities and Exchange Commission (SEC) on March 13, 2009.

Initial public offering

On May 14, 2008, the Partnership closed its initial public offering of 18,750,000 common units at a price of $16.50 per unit. On June 11, 2008, the Partnership issued an additional 2,060,875 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option. The May 14 and June 11 issuances are referred to collectively as the “initial public offering.” The common units are listed on the New York Stock Exchange under the symbol “WES.”

Concurrent with the closing of the initial public offering, Anadarko contributed the assets and liabilities of Anadarko Gathering Company LLC (AGC), Pinnacle Gas Treating LLC (PGT) and MIGC LLC (MIGC) to the Partnership in exchange for 1,083,115 general partner units, representing a 2.0% general partner interest in the Partnership, 100% of the incentive distribution rights (IDRs), 5,725,431 common units and 26,536,306 subordinated units. AGC, PGT and MIGC are referred to collectively as the “initial assets.” The common units issued to Anadarko include 751,625 common units issued following the expiration of the underwriters’ over-allotment option and represent the portion of the common units for which the underwriters did not exercise their over-allotment option. See Note 4—Partnership Equity and Distributions in Item 8 of the Partnership’s annual report on Form 10-K for information related to the distribution rights of the common and subordinated unitholders and to the IDRs held by the general partner.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Powder River acquisition

On December 19, 2008, the Partnership acquired certain midstream assets from Anadarko for consideration consisting of $175.0 million cash, which was financed by borrowing $175.0 million from Anadarko pursuant to the terms of a five-year term loan agreement, 2,556,891 common units and 52,181 general partner units. The acquisition consisted of (i) a 100% ownership interest in the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C. (Fort Union). These assets are referred to collectively as the “Powder River assets” and the acquisition is referred to as the “Powder River acquisition.”

General information

As of June 30, 2009 and December 31, 2008, Anadarko held 1,135,296 general partner units representing a 2.0% general partner interest in the Partnership, 100% of the Partnership incentive distribution rights, 8,282,322 common units and 26,536,306 subordinated units. Anadarko’s common and subordinated unit ownership represents an aggregate 61.3% limited partner interest in the Partnership. The public held 20,841,179 common units, representing a 36.7% limited partner interest in the Partnership.

Anadarko acquired MIGC and the Powder River assets in connection with its August 23, 2006 acquisition of Western Gas Resources, Inc. (Western). The acquisition of the initial assets and the Powder River assets were considered transfers of net assets between entities under common control. The Partnership is required to revise its financial statements to include the activities of the acquired assets as of the date of common control. Accordingly, the Partnership’s historical financial statements for the three and six months ended June 30, 2008 have been recast to reflect the results attributable to the Powder River assets. Net income attributable to the Powder River assets for periods prior to December 19, 2008 is not allocated to the limited partners for purposes of calculating net income per limited partner unit. In addition to recasting the Partnership’s financial statements for the three and six months ended June 30, 2008 for the Powder River assets, certain amounts in prior periods have been reclassified to conform to the current presentation.

The “Partnership” as used herein refers to the combined financial results and operations of AGC, PGT and MIGC from January 1, 2008 through May 14, 2008 and to the Partnership thereafter, combined with the financial results and operations of the Powder River assets for all periods presented herein. The consolidated financial statements for periods prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets and operated as a separate entity during the periods reported.

2. NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007), Business Combinations (SFAS 141(R)). SFAS 141(R) applies fair value measurement in accounting for business combinations, expands financial disclosures, defines an acquirer and modifies the accounting for some business combination items. Under SFAS 141(R), an acquirer is required to record 100% of assets and liabilities, including goodwill, contingent assets and contingent liabilities, at fair value. This replaces the cost allocation process applied under SFAS No. 141, Business Combinations (SFAS 141). In addition, contingent consideration must be recognized at fair value at the acquisition date, acquisition-related costs must be expensed rather than treated as an addition to the assets acquired, and restructuring costs are required to be recognized separately from the business combination. The Partnership will apply the provisions of SFAS 141(R) to acquisitions of businesses from third parties that close after January 1, 2009. SFAS 141(R) did not change the accounting for transfers of assets between entities under common control and, therefore, does not impact the Partnership’s accounting for transfers of assets from Anadarko.

Emerging Issues Task Force (EITF) Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (EITF 07-4), and Financial Accounting Standards Board (FASB) Staff Position EITF Issue No. 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1). EITF 07-4 addresses the application of the two-class method under SFAS No. 128, Earnings per Share (SFAS 128), in determining net income per unit for master limited partnerships having multiple classes of securities including limited partnership units, general partnership units and, when applicable, IDRs of the general

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

partner. EITF 07-4 clarifies that the two-class method would apply, and provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. In June 2008, the FASB issued FSP EITF 03-6-1 addressing whether instruments granted in equity-based payment transactions are participating securities prior to vesting and therefore required to be accounted for in calculating earnings per unit under the two-class method described in SFAS 128. FSP EITF 03-6-1 requires companies to treat unvested equity-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per unit. The Partnership adopted EITF 07-4 and FSP EITF 03-6-1 effective January 1, 2009 and has applied these provisions with respect to all periods in which earnings per unit is presented. EITF 07-4 and FSP EITF 03-6-1 did not impact earnings per unit for the periods presented herein.

SFAS No. 165, Subsequent Events (SFAS 165). SFAS 165 does not change the Partnership’s accounting policy for subsequent events, but instead incorporates existing accounting and disclosure requirements related to subsequent events from auditing standards into generally accepted accounting principles (GAAP). SFAS 165 defines subsequent events as either recognized subsequent events, those that provide additional evidence about conditions at the balance sheet date, or nonrecognized subsequent events, those that provide evidence about conditions that arose after the balance sheet date. Recognized subsequent events are recorded in the financial statements for the period being presented, while nonrecognized subsequent events are not. Both types of subsequent events require disclosure in the consolidated financial statements if those financial statements would otherwise be misleading. SFAS 165 requires the Partnership to disclose the date through which subsequent events have been evaluated. The Partnership adopted SFAS 165 effective April 1, 2009. The adoption of SFAS 165 had no impact on the Partnership’s financial statements. The Partnership has evaluated subsequent events through August 12, 2009.

FSP FAS 107-1 and Accounting Principles Board Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1). FSP FAS 107-1 requires the Partnership to disclose the fair value of financial instruments quarterly. The Partnership adopted FSP FAS 107-1 in the second quarter of 2009 and disclosed the fair value of its note receivable from Anadarko and long-term debt in Note 5—Transactions with Affiliates and Note 9—Debt, respectively.

3. PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended June 30, 2008, the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the six months ended June 30, 2009, the Partnership paid cash distributions to its unitholders of approximately $34.1 million, representing the $0.30 per unit distributions for each of the quarters ended March 31, 2009 and December 31, 2008. See also Note 13—Subsequent Events concerning distributions approved in July 2009.

4. NET INCOME PER LIMITED PARTNER UNIT

The Partnership’s net income attributable to the initial assets for periods including and subsequent to May 14, 2008 and its net income attributable to the Powder River assets for periods including and subsequent to December 19, 2008 is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (LTIP) and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the Partnership Agreement) for the period. The Partnership’s net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Accordingly, if current net income allocable to the limited partners is less than the minimum quarterly distribution, or if cumulative net income allocable to the limited partners since May 14, 2008 is less than the cumulative minimum quarterly distributions, more income is allocated to the common unitholders than the subordinated unitholders for that quarterly period.

Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):


	Three Months		Six Months		May 14, 2008
	Ended		Ended		to
	June 30, 2009		June 30, 2009		June 30, 2008

Net income⁽¹⁾	$	18,124	$	35,082	$	8,249
Less general partner interest in net income		362		702		165

Limited partner interest in net income	$	17,762	$	34,380	$	8,084


Net income allocable to common units	$	9,297	$	17,997	$	4,199
Net income allocable to subordinated units		8,465		16,383		3,885

Limited partner interest in net income	$	17,762	$	34,380	$	8,084


Net income per limited partner unit — basic and diluted
Common units	$	0.32	$	0.62	$	0.16
Subordinated units	$	0.32	$	0.62	$	0.15
Total	$	0.32	$	0.62	$	0.15

Weighted average limited partner units outstanding — basic and diluted
Common units		29,109		29,101		26,567
Subordinated units		26,536		26,536		26,536

Total		55,645		55,637		53,103


⁽¹⁾		Net income for 2008 represents net income attributable to the initial assets since the closing of the Partnership’s initial public offering on May 14, 2008.

5. TRANSACTIONS WITH AFFILIATES

Affiliate transactions

The Partnership provides natural gas gathering, compression, treating and transportation services to Anadarko and a portion of the Partnership’s expenditures were paid by or to Anadarko, which results in affiliate transactions. In addition, contributions to and distributions from Fort Union were paid or received by Anadarko. Prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, balances arising from affiliate transactions were net-settled on a non-cash basis by way of an adjustment to parent net equity. Anadarko charged the Partnership interest at a variable rate on outstanding affiliate balances owed by the Partnership to Anadarko for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to parent net equity in connection with the initial public offering and the Powder River acquisition. Subsequent to May 14, 2008, with respect to the initial assets, and subsequent to December 19, 2008, with respect to the Powder River assets, affiliate transactions are cash-settled and affiliate-based interest expense on current intercompany balances is not charged.

Note receivable from Anadarko

Concurrent with the closing of the initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest on the note is payable quarterly. The fair value of the note receivable from Anadarko was approximately $236.8 million and $198.1 million at June 30, 2009 and December 31, 2008, respectively. The fair value of the note reflects any premium or discount for the differential between the stated interest rate and quarter-end market rate, based on quoted market prices of similar debt instruments.

Note payable to Anadarko

Concurrent with the closing of the Powder River acquisition, the Partnership entered into a five-year, $175.0 million term loan agreement with Anadarko under which the Partnership pays Anadarko interest at a fixed rate of 4.0% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. See Note 9—Debt.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Commodity price swap agreements

The Partnership entered into commodity price swap agreements with Anadarko in December 2008 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Hilight and Newcastle systems. Beginning on January 1, 2009, the commodity price swap agreements fix the margin the Partnership will realize on its share of revenues under percent-of-proceeds contracts applicable to natural gas processing activities at the Hilight and Newcastle systems. In this regard, the Partnership’s notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to volumes equal in amount to the Partnership’s share of actual volumes processed at the Hilight and Newcastle systems. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument and are therefore not required to be measured at fair value. The Partnership reports its realized gains and losses on the commodity price swap agreements in natural gas, natural gas liquids and condensate sales — affiliates in its consolidated statements of income in the period in which the associated revenues are recognized. During the three and six months ended June 30, 2009, the Partnership recorded realized gains of $2.3 million and $4.1 million, respectively, attributable to the commodity price swap agreements.

Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements outstanding as of June 30, 2009. The commodity price swap arrangements expire in December 2010 and the Partnership may annually, at its option, extend the agreements through December 2013.


	Year Ended December 31,
	2009		2010
	(per barrel)
Natural Gasoline	$	55.60	$	63.20
Condensate	$	62.27	$	70.72
Propane	$	35.56	$	40.63
Butane	$	42.24	$	48.15


	(per MMBtu)
Natural Gas	$	4.85	$	5.61

Cash management

Anadarko operates a cash management system whereby excess cash from most of its subsidiaries, held in separate bank accounts, is generally swept to centralized accounts. Prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, sales and purchases related to third-party transactions were received or paid in cash by Anadarko within the centralized cash management system and were settled with the Partnership through an adjustment to parent net equity. Subsequent to May 14, 2008, with respect to the initial assets, and subsequent to December 19, 2008, with respect to the Powder River assets, the Partnership cash-settles transactions directly with third parties and with Anadarko affiliates.

Credit facilities

In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may borrow up to $100.0 million. Concurrent with the closing of the initial public offering, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. See Note 9—Debt for more information on these credit facilities.

Omnibus agreement

Concurrent with the closing of the initial public offering, the Partnership entered into an omnibus agreement with the general partner and Anadarko that addresses the following:

•

Anadarko’s obligation to indemnify the Partnership for certain liabilities and the Partnership’s obligation to indemnify Anadarko for certain liabilities with respect to the initial assets;

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

	•		the Partnership’s obligation to reimburse Anadarko for all expenses incurred or payments made on the Partnership’s behalf in conjunction with Anadarko’s provision of general and administrative services to the Partnership, including salary and benefits of the general partner’s executive management and other Anadarko personnel and general and administrative expenses which are attributable to the Partnership’s status as a separate publicly traded entity;

	•		the Partnership’s obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to the Partnership’s assets; and

	•		the Partnership’s obligation to reimburse Anadarko for the Partnership’s allocable portion of commitment fees that Anadarko incurs under its $1.3 billion credit facility.

Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal, accounting, treasury, cash management, investor relations, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, tax, marketing and midstream administration. As of June 30, 2009, the Partnership’s reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership was capped at $6.65 million annually through December 31, 2009, subject to adjustment to reflect expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses and with the concurrence of the special committee of the Partnership’s general partner’s board of directors. See Note 13—Subsequent Events. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses allocated to or incurred by the Partnership as a result of being a publicly traded partnership. The consolidated financial statements of the Partnership include costs allocated by Anadarko pursuant to the omnibus agreement for periods including and subsequent to May 14, 2008.

Services and secondment agreement

Concurrent with the closing of the initial public offering, the general partner and Anadarko entered into a services and secondment agreement pursuant to which specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement is 10 years and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice otherwise before the applicable twelve-month period expires. The consolidated financial statements of the Partnership include costs allocated by Anadarko pursuant to the services and secondment agreement for periods including and subsequent to May 14, 2008, with respect to the initial assets, and periods including and subsequent to December 1, 2008, with respect to the Powder River assets.

Tax sharing agreement

Concurrent with the closing of the initial public offering, the Partnership and Anadarko entered into a tax sharing agreement pursuant to which the Partnership reimburses Anadarko for the Partnership’s share of Texas margin tax borne by Anadarko as a result of the Partnership’s results being included in a combined or consolidated tax return filed by Anadarko with respect to periods subsequent to May 14, 2008. Anadarko may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. However, the Partnership is nevertheless required to reimburse Anadarko for the tax the Partnership would have owed had the attributes not been available or used for the Partnership’s benefit, regardless of whether Anadarko pays taxes for the period.

Allocation of costs

The consolidated financial statements of the Partnership include costs allocated by Anadarko in the form of a management services fee for periods prior to May 14, 2008, with respect to the initial assets, and prior to December 1, 2008, with respect to the Powder River assets. General, administrative and management costs were allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues. Management believes these allocation methodologies are reasonable.

The employees supporting the Partnership’s operations are employees of Anadarko. Anadarko charges the Partnership its allocated share of personnel costs, including costs associated with Anadarko’s equity-based compensation plans,

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

non-contributory defined pension and postretirement plans and defined contribution savings plan, through the management services fee or pursuant to the omnibus agreement and services and secondment agreement described above.

Equity-based compensation

Grants made under equity-based compensation plans result in equity-based compensation expense which is determined by reference to the fair value of equity compensation as of the date of the relevant equity grant.

Long-term incentive plan

The general partner awarded phantom units primarily to the general partner’s independent directors under the LTIP in May 2008 and May 2009. The phantom units awarded to the independent directors vest one year from the grant date. The following table summarizes information regarding phantom units under the LTIP for the six months ended June 30, 2009:


	Value per
	Unit		Units

Units outstanding at beginning of period	$	16.50		30,304
Vested	$	16.50		(30,304	)
Granted	$	15.02		21,970

Units outstanding at end of period	$	15.02		21,970

Compensation expense attributable to the phantom units granted under the LTIP is recognized entirely by the Partnership over the vesting period and was approximately $93,000 and $216,000 during the three and six months ended June 30, 2009, respectively, and was approximately $65,000 during the three and six months ended June 30, 2008. The Partnership expects to recognize approximately $149,000 and $124,000 of additional compensation expense during the six months ending December 31, 2009 and the twelve months ending December 31, 2010, respectively, related to the phantom units granted under the LTIP.

Equity incentive plan and Anadarko incentive plans

The Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan (Incentive Plan), as well as the Anadarko Petroleum Corporation 1999 Stock Incentive Plan and the Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan (Anadarko’s plans are referred to collectively as the Anadarko Incentive Plans). Under the Incentive Plan, participants are granted Unit Value Rights (UVRs), Unit Appreciation Rights (UARs) and Dividend Equivalent Rights (DERs). The following table summarizes information regarding UVRs, UARs and DERs issued under the Incentive Plan for the six months ended June 30, 2009:


	Units

Units outstanding at beginning of period		50,000
Granted		10,000
Vested		(16,667	)
Forfeited		(6,666	)

Units outstanding at end of period		36,667

Weighted average grant date fair value per UVR	$	50.00

The Partnership’s general and administrative expense for the three and six months ended June 30, 2009 included approximately $1.0 million and $1.9 million, respectively, of equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans. The Partnership’s general and administrative expense for the three and six months ended June 30, 2008 included approximately $279,000 of equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans. A portion of these expenses are allocated to the Partnership by Anadarko as a component of compensation expense for the executive officers of the Partnership’s general partner and other employees pursuant to the omnibus agreement and employees who provide services to the Partnership pursuant to the services and secondment agreement. These amounts exclude compensation expense associated with the LTIP.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Summary of affiliate transactions

Operating expenses include all amounts accrued or paid to affiliates for the operation of the Partnership’s systems, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. Affiliate expenses do not bear a direct relationship to affiliate revenues and third-party expenses do not bear a direct relationship to third-party revenues. For example, the Partnership’s affiliate expenses are not those expenses necessary for generating affiliate revenues. The following table summarizes affiliate transactions.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
			(in thousands)
Revenues — affiliates	$	44,125	$	81,612	$	89,275	$	152,064
Operating expenses — affiliates		8,673		13,343		17,498		26,461
Interest income — affiliates		4,225		2,226		8,450		2,226
Interest expense — affiliates		1,786		166		3,571		1,955

Distributions to unitholders — affiliates		10,786		—		21,572		—

6. INCOME TAXES

The following table summarizes the Partnership’s effective tax rate:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(in thousands, except effective tax rate)
Income before income taxes	$	18,179		$	19,747		$	34,647		$	43,335
Income tax expense (benefit)	$	55		$	4,168		$	(435	)	$	12,635

Effective tax rate		0	%		21	%		(1	%)		29	%

For the three and six months ended June 30, 2009, income tax expense decreased compared to the same periods of 2008 primarily due to a change in the applicability of U.S. federal income tax to the Partnership’s income that occurred in connection with its initial public offering. Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, for the three and six months ended June 30, 2009 was subject only to Texas margin tax while income earned by the Partnership and attributable to the initial assets prior to May 14, 2008 and to the Powder River assets for the three and six months ended June 30, 2008, was subject to federal and state income tax. In addition, for the six months ended June 30, 2009, the Partnership’s estimated income attributed to Texas relative to the Partnership’s total income decreased as compared to the prior year, which resulted in a $560,000 reduction of previously recognized deferred taxes. For 2008, the Partnership’s variance from the federal statutory rate is primarily attributable to the Partnership’s status as a non-taxable entity after May 14, 2008, partially offset by state income tax expense.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

7. CONCENTRATION OF CREDIT RISK

Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for the three and six months ended June 30, 2009 and 2008. The percentage of revenues from Anadarko and the Partnership’s other customers are as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
Customer	2009			2008			2009			2008
Anadarko		84	%		88	%		85	%		87	%
Other		16	%		12	%		15	%		13	%

Total		100	%		100	%		100	%		100	%

8. PROPERTY, PLANT AND EQUIPMENT

A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:


	Estimated
	useful life		June 30, 2009		December 31, 2008
			(dollars in thousands)
Land		n/a	$	354	$	354
Gathering systems		15 to 25 years		605,969		594,658
Pipeline and equipment		30 to 34.5 years		86,977		85,598
Assets under construction		n/a		5,335		7,690
Other		3 to 25 years		1,660		1,645

Total property, plant and equipment				700,295		689,945
Accumulated depreciation				189,320		172,130

Total net property, plant and equipment			$	510,975	$	517,815

The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. This amount represents property that is not yet suitable to be placed into productive service as of the balance sheet date.

9. DEBT

In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may utilize up to $100.0 million to the extent that sufficient amounts remain available to Anadarko. As of June 30, 2009, the full $100.0 million was available for borrowing by the Partnership. Interest on borrowings under the credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.50% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which was 0.44% at June 30, 2009, and the commitment fees on the facility are based on Anadarko’s senior unsecured long-term debt rating. Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, the Partnership is required to reimburse Anadarko for its allocable portion of commitment fees (as of June 30, 2009, 0.11% of the Partnership’s committed and available borrowing capacity, including the Partnership’s outstanding balances, if any) that Anadarko incurs under its credit facility, or up to $110,000 annually. Under Anadarko’s credit agreements, the Partnership and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 60% or less. As of June 30, 2009, Anadarko and the Partnership were in compliance with all covenants. Should the Partnership or Anadarko fail to comply with any covenant in Anadarko’s credit agreements, the Partnership may not be permitted to borrow under the credit facility. Anadarko is a guarantor of the Partnership’s borrowings, if any, under the credit facility. The Partnership is not a guarantor of Anadarko’s borrowings under the credit facility. The $1.3 billion credit facility expires in March 2013.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

In May 2008, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. At June 30, 2009, no borrowings were outstanding under the working capital facility. The facility is available exclusively to fund working capital needs. Borrowings under the facility will bear interest at the same rate that would apply to borrowings under the Anadarko credit facility described above. Pursuant to the omnibus agreement, the Partnership will pay a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility, or up to $33,000 annually. The Partnership is required to reduce all borrowings under the working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility.

In December 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko in order to finance the cash portion of the consideration paid for the Powder River acquisition. The interest rate is fixed at 4.0% for the first two years and is a floating rate equal to three-month LIBOR plus 150 basis points for the final three years. The Partnership has the option to repay the outstanding principal amount in whole or in part commencing upon the second anniversary of the term loan agreement. The provisions of the term loan agreement are non-recourse to the Partnership’s general partner and limited partners and contain customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) certain events of bankruptcy or insolvency with respect to the Partnership; or (iii) a change of control. At June 30, 2009, the Partnership was in compliance with all covenants under the term loan agreement. The fair value of the Partnership’s debt under the term loan agreement approximated its carrying value at June 30, 2009 and December 31, 2008. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and quarter-end market rate.

10. SEGMENT INFORMATION

The Partnership’s operations are organized into a single business segment, the assets of which consist of natural gas gathering and processing systems, treating facilities, a pipeline and related plants and equipment. To assess the operating results of the Partnership’s segment, management uses Adjusted EBITDA, which it defines as net income (loss) plus distributions from equity investee, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, less income from equity investee, interest income, income tax benefit and other income (expense). The Partnership changed its definition of Adjusted EBITDA from the definition used in the prior year. Adjusted EBITDA has been calculated using the revised definition for all periods presented.

Adjusted EBITDA is a supplemental financial measure that management and external users of the Partnership’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess, among other measures:

	•		the Partnership’s operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;

	•		the ability of the Partnership’s assets to generate cash flow to make distributions; and

	•		the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

Management believes that the presentation of Adjusted EBITDA provides information useful in assessing the Partnership’s financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA, as defined by the Partnership, may not be comparable to similarly titled measures used by other companies. Therefore, the Partnership’s consolidated Adjusted EBITDA should be considered in conjunction with net income and other performance measures, such as operating income or cash flow from operating activities.

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Below is a reconciliation of Adjusted EBITDA to net income.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
			(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Adjusted EBITDA	$	24,899	$	25,010	$	47,950	$	59,230
Less:
Distributions from equity investee		1,459		844		2,570		2,251
Non-cash equity-based compensation expense		942		261		1,788		261
Interest expense, net — affiliates		1,786		166		3,571		1,955
Income tax expense		55		4,168		—		12,635
Depreciation and amortization		8,752		8,204		17,373		15,986
Add:
Equity income, net		1,985		1,959		3,535		2,301
Interest income from note — affiliate		4,225		2,226		8,450		2,226
Other income, net		9		27		14		31
Income tax benefit		—		—		435		—


Net Income	$	18,124	$	15,579	$	35,082	$	30,700

11. COMMITMENTS AND CONTINGENCIES

Environmental

The Partnership is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are no such matters that could have a material adverse effect on the Partnership’s results of operations, cash flows or financial position.

Litigation and legal proceedings

From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which a final disposition could have a material adverse effect on the Partnership’s results of operations, cash flows or financial position.

Lease commitments

Anadarko, on behalf of the Partnership, formerly leased compression equipment used exclusively by the Partnership. As a result of lease modifications in October 2008, Anadarko became the owner of the compression equipment and contributed the equipment to the Partnership, effectively terminating the lease. Rent expense associated with the compression equipment was approximately $270,000 and $641,000 for the three and six months ended June 30, 2008, respectively. As of June 30, 2009, the Partnership does not have significant non-cancelable lease commitments.

12. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

The Partnership filed a shelf registration statement on Form S-3 with the SEC in June 2009 under which the Partnership may issue and sell up to $1.25 billion of debt and equity securities after the shelf registration statement is declared effective by the SEC. As of June 30, 2009, the shelf registration statement had not become effective. Debt securities issued under the shelf may be guaranteed by one or more existing or future subsidiaries of the Partnership, including WGR Operating, LP (WGR Operating), AGC, PGT, MIGC, Western Gas Wyoming, L.L.C. (WG Wyoming) and Western Gas Operating, LLC (collectively, the Guarantor Subsidiaries), each of which is a wholly owned subsidiary of the Partnership. WG Wyoming holds the Partnership’s 14.81% limited liability company membership interest in Fort Union. The guarantees, if issued, would be full, unconditional, joint and several. The following condensed consolidating financial information reflects the

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Partnership’s stand-alone accounts, the consolidated accounts of the Guarantor Subsidiaries, consolidating adjustments and eliminations, and the Partnership’s consolidated accounts for the three and six months ended June 30, 2009, for the three and six months ended June 30, 2008 and as of June 30, 2009 and December 31, 2008. The condensed consolidating financial information should be read in conjunction with the Partnership’s accompanying unaudited consolidated financial statements and related notes.

WGR Operating acquired the initial assets in connection with the Partnership’s initial public offering in May 2008 and acquired the Powder River assets in connection with the December 2008 Powder River acquisition (see Note 1—Description of Business and Basis of Presentation). Anadarko acquired MIGC and the Powder River assets in connection with its August 23, 2006 acquisition of Western. Western Gas Partners, LP’s investment in and equity income from its consolidated subsidiaries is presented in accordance with the equity method of accounting and includes the results of operations of the initial assets from May 14, 2008 and the Powder River assets from December 19, 2008.

Statement of Income


	Three Months Ended June 30, 2009
	Western Gas			Guarantor
	Partners, LP			Subsidiaries		Eliminations			Consolidated
				(in thousands)
Revenues
Gathering, processing and transportation of natural gas	$	—		$	30,759	$	—		$	30,759
Natural gas, natural gas liquids and condensate sales		2,293			14,138		—			16,431
Equity income and other, net		—			2,784		—			2,784

Total Revenues	$	2,293		$	47,681	$	—		$	49,974


Operating Expenses
Cost of product	$	—		$	9,489	$	—		$	9,489
Operation and maintenance		—			10,421		(50	)		10,371
General and administrative		3,451			359		50			3,860
Property and other taxes		—			1,771		—			1,771
Depreciation and amortization		14			8,738		—			8,752

Total Operating Expenses	$	3,465		$	30,778	$	—		$	34,243


Operating Income (Loss)	$	(1,172	)	$	16,903	$	—		$	15,731

Interest income, net — affiliates		2,435			4		—			2,439
Other income, net		9			—		—			9
Equity income from consolidated subsidiaries		16,852			—		(16,852	)		—


Income Before Income Taxes	$	18,124		$	16,907	$	(16,852	)	$	18,179

Income tax expense		—			55		—			55


Net Income	$	18,124		$	16,852	$	(16,852	)	$	18,124

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Statement of Income


	Three Months Ended June 30, 2008
	Western Gas			Guarantor
	Partners, LP			Subsidiaries			Eliminations			Consolidated
				(in thousands)
Revenues
Gathering, processing and transportation of natural gas	$	—		$	31,045		$	—		$	31,045
Natural gas, natural gas liquids and condensate sales		—			54,551			—			54,551
Equity income and other, net		—			5,013			—			5,013

Total Revenues	$	—		$	90,609		$	—		$	90,609


Operating Expenses
Cost of product	$	—		$	47,839		$	—		$	47,839
Operation and maintenance		—			12,397			—			12,397
General and administrative		1,395			1,397			—			2,792
Property and other taxes		—			1,717			—			1,717
Depreciation and amortization		—			8,204			—			8,204

Total Operating Expenses	$	1,395		$	71,554		$	—		$	72,949


Operating Income (Loss)	$	(1,395	)	$	19,055		$	—		$	17,660

Interest income, net — affiliates		2,186			(126	)		—			2,060
Other income, net		27			—			—			27
Equity income from consolidated subsidiaries		7,431			—			(7,431	)		—


Income Before Income Taxes	$	8,249		$	18,929		$	(7,431	)	$	19,747

Income tax expense		—			4,168			—			4,168


Net Income	$	8,249		$	14,761		$	(7,431	)	$	15,579

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Statement of Income


	Six Months Ended June 30, 2009
	Western Gas			Guarantor
	Partners, LP			Subsidiaries			Eliminations			Consolidated
				(in thousands)
Revenues
Gathering, processing and transportation of natural gas	$	—		$	61,476		$	—		$	61,476
Natural gas, natural gas liquids and condensate sales		4,067			30,343			—			34,410
Equity income and other, net		—			4,976			—			4,976

Total Revenues	$	4,067		$	96,795		$	—		$	100,862


Operating Expenses
Cost of product	$	—		$	22,017		$	—		$	22,017
Operation and maintenance		—			19,693			(86	)		19,607
General and administrative		7,838			659			86			8,583
Property and other taxes		—			3,528			—			3,528
Depreciation and amortization		27			17,346			—			17,373

Total Operating Expenses	$	7,865		$	63,243		$	—		$	71,108


Operating Income (Loss)	$	(3,798	)	$	33,552		$	—		$	29,754

Interest income, net — affiliates		4,873			6			—			4,879
Other income, net		14			—			—			14
Equity income from consolidated subsidiaries		33,993			—			(33,993	)		—


Income Before Income Taxes	$	35,082		$	33,558		$	(33,993	)	$	34,647

Income tax benefit		—			(435	)		—			(435	)


Net Income	$	35,082		$	33,993		$	(33,993	)	$	35,082

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Statement of Income


	Six Months Ended June 30, 2008
	Western Gas			Guarantor
	Partners, LP			Subsidiaries			Eliminations			Consolidated
				(in thousands)
Revenues
Gathering, processing and transportation of natural gas	$	—		$	62,350		$	—		$	62,350
Natural gas, natural gas liquids and condensate sales		—			102,485			—			102,485
Equity income and other, net		—			7,196			—			7,196

Total Revenues	$	—		$	172,031		$	—		$	172,031


Operating Expenses
Cost of product	$	—		$	81,567		$	—		$	81,567
Operation and maintenance		—			23,343			—			23,343
General and administrative		1,395			3,357			—			4,752
Property and other taxes		—			3,350			—			3,350
Depreciation and amortization		—			15,986			—			15,986

Total Operating Expenses	$	1,395		$	127,603		$	—		$	128,998


Operating Income (Loss)	$	(1,395	)	$	44,428		$	—		$	43,033

Interest income, net — affiliates		2,186			(1,915	)		—			271
Other income, net		27			4			—			31
Equity income from consolidated subsidiaries		7,431			—			(7,431	)		—


Income Before Income Taxes	$	8,249		$	42,517		$	(7,431	)	$	43,335

Income tax expense		—			12,635			—			12,635


Net Income	$	8,249		$	29,882		$	(7,431	)	$	30,700

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Balance Sheet


	As of June 30, 2009
	Western Gas		Guarantor
	Partners, LP		Subsidiaries		Eliminations			Consolidated
			(in thousands)
Cash and cash equivalents	$	39,858	$	—	$	—		$	39,858
Other current assets		8,922		10,082		(11,212	)		7,792
Note receivable — Anadarko		260,000		—		—			260,000
Investment in consolidated subsidiaries		530,395		—		(530,395	)		—
Net property, plant and equipment		245		510,730		—			510,975
Goodwill		—		14,436		—			14,436
Equity investment		—		19,412		—			19,412
Other assets		564		—		—			564

Total Assets	$	839,984	$	554,660	$	(541,607	)	$	853,037


Accounts payable	$	11,212	$	4,242	$	(11,212	)	$	4,242
Other current liabilities		251		10,145		—			10,396
Note payable — Anadarko		175,000		—		—			175,000
Other long-term liabilities		—		9,878		—			9,878

Total Liabilities	$	186,463	$	24,265	$	(11,212	)	$	199,516

Partners’ Capital	$	653,521	$	530,395	$	(530,395	)	$	653,521

Total Liabilities and Partners’ Capital	$	839,984	$	554,660	$	(541,607	)	$	853,037

Balance Sheet


	As of December 31, 2008
	Western Gas		Guarantor
	Partners, LP		Subsidiaries		Eliminations			Consolidated
			(in thousands)
Cash and cash equivalents	$	33,306	$	—	$	—		$	33,306
Other current assets		459		50,430		(38,816	)		12,073
Note receivable — Anadarko		260,000		—		—			260,000
Investment in consolidated subsidiaries		574,442		—		(574,442	)		—
Net property, plant and equipment		273		517,542		—			517,815
Goodwill		—		14,436		—			14,436
Equity investment		—		18,183		—			18,183
Other assets		628		—		—			628

Total Assets	$	869,108	$	600,591	$	(613,258	)	$	856,441


Accounts payable	$	38,816	$	5,544	$	(38,816	)	$	5,544
Other current liabilities		338		10,459		—			10,797
Note payable — Anadarko		175,000		—		—			175,000
Other long-term liabilities		—		10,146		—			10,146

Total Liabilities	$	214,154	$	26,149	$	(38,816	)	$	201,487

Partners’ Capital	$	654,954	$	574,442	$	(574,442	)	$	654,954

Total Liabilities and Partners’ Capital	$	869,108	$	600,591	$	(613,258	)	$	856,441

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Statement of Cash Flows


	Six Months Ended June 30, 2009
	Western Gas			Guarantor
	Partners, LP			Subsidiaries			Eliminations			Consolidated
				(in thousands)
Cash Flows from Operating Activities

Net income	$	35,082		$	33,993		$	(33,993	)	$	35,082
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(33,993	)		—			33,993			—
Depreciation and amortization		27			17,346			—			17,373
Deferred income taxes		—			(554	)		—			(554	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable and natural gas imbalance receivable		(8,758	)		(37,843	)		47,752			1,151
Increase (decrease) in accounts payable, accrued liabilities and natural gas imbalance payable		47,665			(240	)		(47,752	)		(327	)
Change in other items, net		597			(721	)		—			(124	)

Net cash provided by operating activities	$	40,620		$	11,981		$	—		$	52,601


Cash Flows from Investing Activities
Capital expenditures	$	—		$	(11,718	)	$	—		$	(11,718	)
Investment in consolidated subsidiaries and equity affiliate		—			(263	)		—			(263	)

Net cash used in investing activities	$	—		$	(11,981	)	$	—		$	(11,981	)


Cash Flows from Financing Activities
Distributions to unitholders	$	(34,068	)	$	—		$	—		$	(34,068	)

Net cash used in financing activities	$	(34,068	)	$	—		$	—		$	(34,068	)


Net Increase in Cash and Cash Equivalents	$	6,552		$	—		$	—		$	6,552
Cash and Cash Equivalents at Beginning of Period		33,306			—			—			33,306

Cash and Cash Equivalents at End of Period	$	39,858		$	—		$	—		$	39,858

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

Statement of Cash Flows


	Six Months Ended June 30, 2008
	Western Gas			Guarantor
	Partners, LP			Subsidiaries			Eliminations			Consolidated
				(in thousands)
Cash Flows from Operating Activities
Net income	$	8,249		$	29,882		$	(7,431	)	$	30,700
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(7,431	)		—			7,431			—
Depreciation and amortization		—			15,986			—			15,986
Deferred income taxes		—			1,614			—			1,614
Changes in assets and liabilities:
(Increase) decrease in accounts receivable and natural gas imbalance receivable		—			(8,422	)		7,819			(603	)
Increase (decrease) in accounts payable, accrued liabilities and natural gas imbalance payable		20,475			800			(20,311	)		964
Change in other items, net		(1,002	)		(1,029	)		—			(2,031	)

Net cash provided by operating activities	$	20,291		$	38,831		$	(12,492	)	$	46,630


Cash Flows from Investing Activities
Loan to parent	$	(260,000	)	$	—		$	—		$	(260,000	)
Capital expenditures		—			(14,376	)	$	—			(14,376	)
Investment in consolidated subsidiaries and equity affiliate		—			(4,402	)		(1,252	)		(5,654	)

Net cash used in investing activities	$	(260,000	)	$	(18,778	)	$	(1,252	)	$	(280,030	)


Cash Flows from Financing Activities

Proceeds from issuance of common units	$	315,346		$	—		$	—		$	315,346
Reimbursement of capital expenditures to parent		(45,346	)		—			—			(45,346	)
Net distributions paid		(4,463	)		(20,093	)		13,744			(10,812	)

Net cash provided by (used in) financing activities	$	265,537		$	(20,093	)	$	13,744		$	259,188


Net Increase (Decrease) in Cash and Cash Equivalents	$	25,828		$	(40	)	$	—		$	25,788
Cash and Cash Equivalents at Beginning of Period		—			—			—			—

Cash and Cash Equivalents at End of Period	$	25,828		$	(40	)	$	—		$	25,788

13. SUBSEQUENT EVENTS

Cash distribution

On July 20, 2009, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.31 per unit, or $17.7 million in aggregate. The cash distribution is payable on August 14, 2009 to unitholders of record at the close of business on July 31, 2009.

Chipeta acquisition

In July 2009, the Partnership acquired certain midstream assets from Anadarko for approximately $106.8 million, which was financed by borrowing $101.5 million from Anadarko pursuant to the terms of a 7.00% fixed-rate, three-year term loan agreement and the issuance of 351,424 common units and 7,172 general partner units at an implied price of approximately $14.89 per unit. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. The acquisition is comprised of a 51% membership interest in Chipeta Processing LLC (Chipeta) and associated midstream assets. Chipeta owns a natural gas processing plant complex, which includes two recently completed processing trains: a refrigeration unit completed in November 2007 with a design capacity of 240 MMcf/d and a 250 MMcf/d capacity cryogenic unit which was commissioned in April 2009. The 51% membership interest in Chipeta and

Notes to unaudited consolidated financial statements of Western Gas Partners, LP

associated midstream assets are referred to collectively as the “Chipeta assets” and the acquisition is referred to as the “Chipeta acquisition.” As of July 31, 2009, Chipeta is owned 51% by the Partnership, 24% by Anadarko and 25% by a third party.

The Chipeta acquisition and related transactions closed on July 22, 2009. The Partnership will account for the Chipeta acquisition as a transfer of net assets between entities under common control. The Chipeta assets will be recorded based on the amounts recorded in Anadarko’s consolidated financial statements. The difference between the consideration paid and Anadarko’s allocated carrying value of the Chipeta assets will be recorded as an adjustment to partners’ capital. GAAP also prescribes that all income statements be revised to include the results attributable to the Chipeta assets as of the date of common control. Accordingly, beginning with its quarterly report for the third quarter of 2009, the Partnership will recast its current and historical financial statements to consolidate the Chipeta assets for periods including and subsequent to August 10, 2006, the date Anadarko acquired the Chipeta assets in connection with its acquisition of Kerr-McGee Corporation.

Concurrent with the Chipeta acquisition, the Partnership amended the omnibus agreement, resulting in an increase to the cap applicable to the Partnership’s obligation to reimburse Anadarko for certain general and administrative expenses. The cap was increased from $6.65 million to $6.9 million annually through December 31, 2009.

Additionally, in connection with the Partnership’s acquisition of its 51% membership interest in Chipeta, the Partnership became party to Chipeta’s limited liability company agreement dated May 22, 2008, as amended (Chipeta LLC Agreement), together with Anadarko and a third party. Among other things, the Chipeta LLC Agreement provides that:

•

Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;

•

to the extent available, Chipeta will distribute cash to its members quarterly in accordance with those members’ membership interests;

•		Chipeta’s membership interests are subject to significant restrictions on transfer; and

•		Chipeta’s existence is perpetual.

Upon its acquisition of its interest in Chipeta, the Partnership became the managing member of Chipeta. As managing member, the Partnership manages the day-to-day operations of Chipeta and receives a management fee from the other members which is intended to compensate the managing member in the performance of its duties. The Partnership may only be removed as managing member of Chipeta if it is grossly negligent or fraudulent, breaches its primary duties or fails to respond in a commercially reasonable manner to written business proposals from the other members, and such behavior, breach or failure causes a material adverse effect upon Chipeta.

Chipeta is party to a gas processing agreement with a subsidiary of Anadarko dated September 6, 2008, pursuant to which Chipeta processes natural gas delivered by that subsidiary and the subsidiary takes allocated residue and NGLs in-kind. That agreement, pursuant to which the Chipeta plant receives approximately 90% of its throughput, has a primary term that extends through 2023.


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

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and the notes to unaudited consolidated financial statements, which are included in this report in Part I, Item 1 of this Form 10-Q, as well as our historical consolidated financial statements, and the notes thereto, included in Item 8 of our annual report on Form 10-K. Unless the context clearly indicates otherwise, references in this report to the “Partnership,” “we,” “our,” “us” or like terms refer to Western Gas Partners, LP and its subsidiaries. “Anadarko” refers to Anadarko Petroleum Corporation (NYSE: APC) and its consolidated subsidiaries, excluding the Partnership. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership.

We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions by Partnership management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning our operations, economic performance and financial condition. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or financial condition or include other “forward-looking” information. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct.

These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

	•		our assumptions about energy markets;

	•		future gathering, treating and processing volumes and pipeline throughput, including Anadarko’s production, which is gathered or transported through our assets;

	•		operating results;

	•		competitive conditions;

	•		technology;

	•		the availability of capital resources for capital expenditures and other contractual obligations;

	•		the supply of, demand for, and the price of oil, natural gas, NGLs and other products or services;

	•		the weather;

	•		inflation;

	•		the availability of goods and services;

	•		general economic conditions, either internationally or nationally or in the jurisdictions in which we are doing business;

	•		legislative or regulatory changes, including changes in environmental regulation, environmental risks, regulations by the Federal Energy Regulatory Commission or FERC and liability under federal and state environmental laws and regulations;

	•		our ability to access the capital markets;

	•		our ability to access credit, including under Anadarko’s $1.3 billion credit facility;

	•		our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

	•		our ability to acquire assets on acceptable terms;

	•		non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing and transportation agreements and our $260.0 million note receivable from Anadarko; and

•

other factors discussed below and elsewhere in Item 1A—Risk Factors and in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates included in our annual report on Form 10-K filed with the Securities and Exchange Commission (“SEC”) on March 13, 2009, this Form 10-Q and in our other public filings and press releases.

The risk factors and other factors noted throughout or incorporated by reference in this report could cause our actual results to differ materially from those contained in any forward-looking statement. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

EXECUTIVE SUMMARY

We are a growth-oriented Delaware limited partnership organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently operate in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged in the business of gathering, compressing, treating, processing and transporting natural gas for Anadarko and third-party producers and customers.

The current commodity price environment, particularly for natural gas, has resulted in lower drilling activity throughout the areas in which we operate. Our throughput decreased approximately 6% for the three months ended June 30, 2009 compared to the three months ended June 30, 2008 and decreased approximately 4% for the six months ended June 30, 2009 compared to the six months ended June 30, 2008. These volume decreases are primarily due to the aforementioned reduced drilling activity, which limits our ability to offset lower throughput from natural production declines by connecting new wells to our systems. The predominantly fee-based and fixed-price structure of our contracts mitigated the impact of changes in commodity prices on our gross margin. We also benefited from our geographically diverse asset mix as reduced throughput on our Dew, Pinnacle and Hugoton systems was offset by higher throughput on our Haley and Fort Union systems.

INITIAL PUBLIC OFFERING

On May 14, 2008, we closed our initial public offering of 18,750,000 common units at a price of $16.50 per unit. On June 11, 2008, we issued an additional 2,060,875 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with our initial public offering. Concurrent with the initial closing of the offering, Anadarko contributed the assets and liabilities of Anadarko Gathering Company LLC, or AGC, Pinnacle Gas Treating LLC, or PGT, and MIGC LLC, or MIGC, to us in exchange for a 2.0% general partner interest in the Partnership, 5,725,431 common units, 26,536,306 subordinated units and 100% of the IDRs. We refer to AGC, PGT and MIGC as our initial assets.

POWDER RIVER ACQUISITION

On December 19, 2008, we acquired certain midstream assets from Anadarko, consisting of (i) a 100% ownership interest in the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C., or Fort Union. We refer to these assets collectively as the Powder River assets and to the acquisition as the Powder River acquisition. The Powder River assets provide a combination of gathering, treating and processing services in the Powder River Basin of Wyoming.

PARTNERSHIP AGREEMENT AMENDMENT

On April 15, 2009, after receiving the unanimous approval of the special committee of the board of directors of Western Gas Holdings, LLC, the general partner of the Partnership, the general partner’s board of directors unanimously approved an amendment (the “Amendment”) to the Partnership’s First Amended and Restated Agreement of Limited Partnership, effective on the date of approval. The purpose of the Amendment was to ensure that the Partnership’s common unitholders maintain, to the maximum extent possible, their existing share of allocable tax deductions throughout the subordination period. Absent this amendment, it would have been possible, as a result of equity issuances at a price less than the initial

public offering price during the subordination period, that the common unitholders’ allocable share of tax deductions would be significantly diminished.

The foregoing general description of the Amendment is not complete and is qualified in its entirety by reference to the full and complete terms of the Amendment, which is attached to the Form 8-K, filed with the SEC on April 20, 2009, and the partnership agreement, which is incorporated herein.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput volumes, (2) operating expenses, (3) Adjusted EBITDA and (4) gross margin.

Throughput volumes

In order to maintain or increase throughput volumes on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by successful drilling of new wells by producers which will be dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors.

To maintain and increase throughput volumes on our MIGC system, we must continue to contract capacity to shippers, including producers and marketers, for transportation of their natural gas. Although firm capacity on the MIGC system is fully subscribed, we nevertheless monitor producer and marketing activities in the area served by our transportation system to identify new opportunities to attempt to maintain a full subscription of MIGC’s firm capacity.

Operating expenses

We analyze operating expenses to evaluate our performance. Operating expenses include all amounts accrued or paid for the operation of our systems, including cost of product, utilities, field labor, measurement and analysis and other disbursements. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses and general and administrative expenses. Certain of our operating expenses are paid to affiliates; however, affiliate expenses do not bear a direct relationship to affiliate revenues and third-party expenses do not bear a direct relationship to third-party revenues. For example, our affiliate expenses are not those expenses necessary for generating our affiliate revenues and our third-party expenses are not those expenses necessary for generating our third-party revenues.

Operation and maintenance expenses include, among other things, direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf. For periods commencing on and subsequent to May 14, 2008, with respect to our initial assets, and for periods commencing on and subsequent to December 1, 2008, with respect to the Powder River assets, certain of these expenses are incurred under and governed by our services and secondment agreement with Anadarko.

Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds processing contracts, (ii) costs associated with the valuation of our gas imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers which is thermally equivalent to condensate retained by us and sold to third parties and (iv) costs associated with our fuel-tracking mechanism, which tracks the difference between actual fuel usage and loss and amounts recovered for estimated fuel usage and loss under our contracts. These expenses are subject to variability, although our exposure to commodity price risk attributable to our percent-of-proceeds contracts is mitigated through our commodity price swap agreements with Anadarko.

General and administrative expenses for periods prior to May 14, 2008, with respect to our initial assets, and for periods prior to December 1, 2008, with respect to the Powder River assets, include reimbursements attributable to costs incurred by Anadarko on our behalf and allocations of general and administrative costs by Anadarko to us. For these periods, Anadarko received compensation or reimbursement through a management services fee. Subsequent to May 14, 2008, with respect to our initial assets, and subsequent to December 1, 2008, with respect to the Powder River assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, we reimburse Anadarko for general and administrative expenses it incurs on our behalf pursuant to the terms of our omnibus agreement with Anadarko. Amounts

required to be reimbursed to Anadarko under the omnibus agreement include those expenses attributable to our status as a publicly traded partnership, such as:

	•		expenses associated with annual and quarterly reporting;

	•		tax return and Schedule K-1 preparation and distribution expenses;

	•		expenses associated with listing on the New York Stock Exchange; and

	•		independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.

In addition to the above, we are required pursuant to the terms of the omnibus agreement with Anadarko to reimburse Anadarko for allocable general and administrative expenses. As of June 30, 2009, the amount required to be reimbursed by us to Anadarko for allocated general and administrative expenses is capped at $6.65 million for the year ended December 31, 2009, subject to adjustment to reflect expansions of our operations through the acquisition or construction of new assets or businesses and with the concurrence of the special committee of our general partner’s board of directors. After December 31, 2009, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses incurred by or allocated to us as a result of being a separate publicly traded entity. We currently expect public company expenses not subject to the cap contained in the omnibus agreement to be approximately $6.4 million per year, excluding equity-based compensation and transaction costs related to the Chipeta acquisition and any future acquisitions.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss), plus distributions from equity investee, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, less income from equity investments, interest income, income tax benefit and other income (expense). We changed our definition of Adjusted EBITDA from the definition used in the prior year. Adjusted EBITDA has been calculated using the revised definition for all periods presented. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess, among other measures:

	•		our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;

	•		the ability of our assets to generate cash flow to make distributions; and

	•		the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008⁽¹⁾			2009			2008⁽¹⁾

Reconciliation of Adjusted EBITDA to net income
Adjusted EBITDA	$	24,899		$	25,010		$	47,950		$	59,230
Less:
Distributions from equity investee		1,459			844			2,570			2,251
Non-cash equity-based compensation expense		942			261			1,788			261
Interest expense, net — affiliates		1,786			166			3,571			1,955
Income tax expense		55			4,168			—			12,635
Depreciation and amortization		8,752			8,204			17,373			15,986
Add:
Equity income, net		1,985			1,959			3,535			2,301
Interest income from note — affiliate		4,225			2,226			8,450			2,226
Other income, net		9			27			14			31
Income tax benefit		—			—			435			—


Net income	$	18,124		$	15,579		$	35,082		$	30,700


Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities
Adjusted EBITDA	$	24,899		$	25,010		$	47,950		$	59,230
Interest income, net — affiliates		2,439			2,060			4,879			271
Non-cash equity-based compensation expense		(942	)		(261	)		(1,788	)		(261	)
Current income tax expense		(55	)		(4,657	)		(119	)		(11,021	)
Other income (expense), net		9			27			14			31
Distributions from equity investee less than equity income, net		526			1,115			965			50
Changes in operating working capital:
Accounts receivable and natural gas imbalances		7,682			(1,975	)		1,151			(603	)
Accounts payable, accrued liabilities and natural gas imbalance payable		490			360			(327	)		964
Other, including changes in non-current assets and liabilities		(12	)		(2,373	)		(124	)		(2,031	)


Net cash provided by operating activities	$	35,036		$	19,306		$	52,601		$	46,630


⁽¹⁾		Financial information for 2008 has been revised to include results attributable to the Powder River assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition of the notes to the unaudited consolidated financial statements in Part I, Item 1 of this Form 10-Q.

Gross margin

We define gross margin as total revenues less cost of product. We changed our definition of gross margin from the definition used in the prior year. Gross margin has been presented using the revised definition for all periods presented. We consider gross margin to provide information useful in assessing our results of operations, our ability to internally fund capital expenditures and to service or incur additional debt.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below:

•

We anticipate incurring approximately $6.4 million per year of public company expenses not subject to the cap contained in the omnibus agreement, excluding equity-based compensation expense and transaction costs related to the Chipeta acquisition and any future acquisitions. General and administrative expenses such as these are reflected in our historical consolidated financial statements for only those periods including and subsequent to our initial public offering in May 2008.

	•		We anticipate incurring up to $6.9 million in general and administrative expenses annually to be charged by Anadarko to us pursuant to the omnibus agreement, which became effective in connection with our initial public offering. This amount is expected to be greater than amounts allocated to us by Anadarko for the management services fee reflected in our historical consolidated financial statements for periods prior to May 14, 2008, with respect to our initial assets, and prior to December 1, 2008, with respect to the Powder River assets.

	•		Prior to May 14, 2008, with respect to our initial assets, and prior to December 19, 2008, with respect to the Powder River assets, all affiliate transactions were net settled within our consolidated financial statements because these transactions related to Anadarko and were funded by Anadarko’s working capital. Effective on May 14, 2008, with respect to our initial assets, and December 19, 2008, with respect to the Powder River assets, all affiliate and third-party transactions are funded by our working capital. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.

	•		Prior to May 14, 2008, with respect to our initial assets, and prior to December 19, 2008, with respect to the Powder River assets, we incurred interest expense or earned interest income on current intercompany balances with Anadarko. These intercompany balances were extinguished through non-cash transactions in connection with the closing of our initial public offering and the Powder River acquisition; therefore, interest expense and interest income attributable to these balances is reflected in our historical consolidated financial statements for the periods ending prior to and including May 14, 2008, with respect to our initial assets, and prior to and including December 19, 2008, with respect to the Powder River assets.

	•		Concurrent with the closing of our initial public offering, we loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. For periods including and subsequent to May 14, 2008, interest income attributable to the note is reflected in our consolidated financial statements so long as the note remains outstanding.

	•		In connection with the Powder River acquisition, we entered into a five-year, $175.0 million term loan agreement with Anadarko, under which we pay interest at a fixed rate of 4.0% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. For periods including and subsequent to December 19, 2008, interest expense on the $175.0 million note payable to Anadarko will be incurred so long as the loan remains outstanding.

	•		Our financial results for historical periods reflect commodity price changes, which, in turn, impact the financial results derived from our percent-of-proceeds processing contracts. Effective January 1, 2009, commodity price risk associated with our percent-of-proceeds processing contracts has been mitigated through our fixed-price commodity price swap agreements with Anadarko that extend through December 31, 2010, with an option to extend through 2013. See Note 5—Transactions with Affiliates of the notes to the unaudited consolidated financial statements included in Part I, Item 1 of this Form 10-Q.

	•		We are generally not subject to federal or state income tax. Federal and state income tax expense was recorded for periods ending prior to and including May 14, 2008, with respect to income generated by our initial assets, and prior to and including December 19, 2008, with respect to income generated by the Powder River assets. For periods subsequent to May 14, 2008, with respect to income generated by our initial assets, and subsequent to December 19, 2008, with respect to income generated by the Powder River assets, we are only subject to Texas margin tax; therefore, income tax expense attributable to Texas margin tax will continue to be recognized in our consolidated financial statements. We are required to make payments to Anadarko pursuant to a tax sharing arrangement for our share of Texas margin tax included in any combined or consolidated returns of Anadarko.

	•		We have made cash distributions to our unitholders and our general partner at an initial distribution rate of $0.30 per unit per full quarter ($1.20 per unit on an annualized basis) commencing with the quarter ended September 30, 2008. We paid cash distributions to our unitholders of $0.60 per unit, or $34.1 million in aggregate, during the six months ended June 30, 2009. We did not make any such distributions during the six months ended June 30, 2008.

	•		We expect that we will rely upon external financing sources, including commercial bank borrowings, long-term debt and equity issuances, to fund our acquisitions and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.

•

In connection with the closing of our initial public offering, our general partner adopted two new compensation plans; the Western Gas Partners, LP 2008 Long-Term Incentive Plan, or LTIP, and the Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan, or the Incentive Plan. Phantom unit grants have been made under the LTIP and incentive unit grants have been made under the Incentive Plan. These grants result in equity-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. For periods ending prior to May 14, 2008, equity-based compensation expense attributable to the LTIP and Incentive Plan is not reflected in our historical consolidated financial statements as there were no outstanding equity grants under either plan. For periods including and subsequent to May 14, 2008, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made under the LTIP and Incentive Plan as well as the Anadarko Petroleum Corporation 1999 Stock Incentive Plan and the Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan (Anadarko’s plans are referred to collectively as the Anadarko Incentive Plans). Equity-based compensation expense attributable to grants made under the LTIP will impact our cash flows from operating activities only to the extent cash payments are made to a participant in lieu of the actual issuance of common units to the participant upon the lapse of the relevant vesting period. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact our cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants who provided services to us pursuant to the omnibus agreement and such cash payments do not cause total annual reimbursements made by us to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth therein for the periods to which such expense limit applies. Equity-based compensation granted under the Anadarko Incentive Plans does not impact our cash flow from operating activities. See equity-based compensation discussion included in Note 5—Transactions with Affiliates of the notes to the unaudited consolidated financial statements included in Part I, Item 1 of this Form 10-Q and in Note 2 — Summary of Significant Accounting Policies of the notes to the consolidated financial statements in Item 8 of our annual report on Form 10-K.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expectations.

Natural gas supply and demand

There is a natural decline in production from existing wells. Until recently, there has been a significant level of drilling activity offsetting this decline in the areas in which we operate; however, the current natural gas price environment has recently resulted in lower drilling activity throughout areas in which we operate and may result in further reductions in drilling activity or temporary suspension of production. We have no control over this activity. In addition, the recent or further decline in commodity prices could affect production rates and the level of capital investment by Anadarko and third parties in the exploration for and development of new natural gas reserves.

Capital markets

We require periodic access to capital in order to fund acquisitions and expansion projects. Under the terms of our partnership agreement, we are required to distribute all of our available cash to our unitholders, which makes us dependent upon raising capital to fund growth projects. Historically, master limited partnerships have accessed the public debt and equity capital markets to raise money for new growth projects. Recent market turbulence has either raised the cost of those public funds or, in some cases, eliminated the availability of these funds to prospective issuers. If we are unable either to access the public capital markets or find alternative sources of capital, our growth strategy may be more challenging to execute.

Impact of interest rates

Interest rates have been volatile in recent periods. If interest rates rise, our future financing costs could increase accordingly. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors, which could limit our ability to raise funds, or increase the cost of raising

funds in the capital markets. Though our competitors may face similar circumstances, such an environment could adversely impact our efforts to expand our operations or make future acquisitions.

Rising operating costs and inflation

The high level of natural gas exploration, development and production activities across the U.S. in recent years, and the associated construction of required midstream infrastructure, resulted in an increase in the competition for and cost of personnel and equipment. As a result of the recent decline in commodity prices, we have and will continue to actively work with our suppliers to negotiate cost savings on services and equipment to more accurately reflect the current industry environment. To the extent we are unable to negotiate lower costs, or recover higher costs through escalation provisions provided for in our contracts, our operating results will be adversely impacted.

Benefits from system expansions

We expect that capital projects, including the following, will mitigate the impact of natural production declines and position us to capitalize on future drilling activity by Anadarko and third-party producers and shippers:

	•		In June 2009, we completed compressor modifications on our Dew system which are expected to result in lower gathering line pressures servicing the Holly Branch producing area once the modifications are fully utilized. We anticipate increased throughput of approximately 2 MMcf/d.

	•		In July 2008, we completed the expansion of our Pinnacle Bethel treating facility by installing an additional 11 LTD of sulfur treating capacity in order to provide additional sour gas treating capacity for drilling in the area. During the second quarter of 2009, we installed a larger separator at the inlet of the Pinnacle Bethel Plant which will improve the on-line reliability of the facility.

	•		We are expanding our Dew and Pinnacle gathering systems by connecting wells drilled by third parties and Anadarko. During the six months ended June 30, 2009, we connected one third party well with an initial production rate of 15.3 MMcf/d and seven new Anadarko wells with an average initial production rate of 6.8 MMcf/d per well.

	•		We have expanded our Hugoton gathering system and, during the six months ended June 30, 2009, we connected four third-party wells with an average initial production rate of 1.8 MMcf/d per well.

	•		We are continuing to expand our Haley gathering system by connecting wells drilled by third parties and Anadarko. During the six months ended June 30, 2009, we connected one third-party well with an initial production rate of 1.5 MMcf/d and seven new Anadarko wells with an average initial production rate of 10.2 MMcf/d per well.

	•		During 2008, Anadarko completed Phase III of the Fort Union expansion project by installing a third parallel 106-mile 24” line, increasing the total Fort Union handling capacity to 1,300 MMcf/d. During the fourth quarter of 2008, Anadarko completed train two of the Medicine Bow Plant at the terminus of the Fort Union gathering system, which is designed for 600 gallons per minute of amine circulation. During the first quarter of 2009, Anadarko completed train three of the Medicine Bow Plant, which is identical to train two. The system’s gas treating capacity will vary depending upon the CO₂ content of the inlet gas. At the current level of 3.7% CO₂, the system is capable of treating and blending over 1 Bcf/d while satisfying CO₂ specifications of downstream pipelines.

Acquisition opportunities

A key component of our growth strategy is to acquire midstream energy assets from Anadarko over time. In July 2009, we acquired certain midstream assets from Anadarko for approximately $106.8 million, which was financed by borrowing $101.5 million from Anadarko pursuant to the terms of a 7.00% fixed-rate, three-year term loan agreement and the issuance of 351,424 common units and 7,172 general partner units. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. The acquisition is comprised of a 51% membership interest in Chipeta Processing LLC, or Chipeta, and associated midstream assets. Chipeta owns a natural gas processing plant complex, which includes two recently completed processing trains: a refrigeration unit completed in November 2007 with a design capacity of 240 MMcf/d and a 250 MMcf/d capacity cryogenic unit which was commissioned in April 2009. The 51% membership interest in Chipeta and associated midstream assets are referred to collectively as the Chipeta assets and the acquisition is referred to as the Chipeta acquisition.

RESULTS OF OPERATIONS — OVERVIEW

OPERATING RESULTS

The following table and discussion presents a summary of our results of operations for the three and six months ended

June 30, 2009 and 2008:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008⁽¹⁾		2009			2008⁽¹⁾
			(in thousands)

Revenues
Gathering, processing and transportation of natural gas	$	30,759	$	31,045	$	61,476		$	62,350
Natural gas, natural gas liquids and condensate sales		16,431		54,551		34,410			102,485
Equity income and other, net		2,784		5,013		4,976			7,196

Total Revenues		49,974		90,609		100,862			172,031


Operating Expenses ⁽²⁾
Cost of product		9,489		47,839		22,017			81,567
Operation and maintenance		10,371		12,397		19,607			23,343
General and administrative		3,860		2,792		8,583			4,752
Property and other taxes		1,771		1,717		3,528			3,350
Depreciation and amortization		8,752		8,204		17,373			15,986

Total Operating Expenses		34,243		72,949		71,108			128,998


Operating Income		15,731		17,660		29,754			43,033

Interest income, net — affiliates		2,439		2,060		4,879			271
Other income, net		9		27		14			31


Income Before Income Taxes		18,179		19,747		34,647			43,335

Income tax expense (benefit)		55		4,168		(435	)		12,635


Net Income	$	18,124	$	15,579	$	35,082		$	30,700


Adjusted EBITDA ⁽³⁾	$	24,899	$	25,010	$	47,950		$	59,230
Gross margin ⁽³⁾		40,485		42,770		78,845			90,464


⁽¹⁾		Financial information for 2008 has been revised to include results attributable to the Powder River assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition of the notes to the unaudited consolidated financial statements in Part I, Item 1 of this Form 10-Q.

⁽²⁾		Operating expenses include amounts charged by affiliates to the Partnership for services as well as reimbursement of amounts paid by affiliates to third parties on behalf of the Partnership. See Note 5—Transactions with Affiliates of the notes to the unaudited consolidated financial statements in Part I, Item 1 of this Form 10-Q.

⁽³⁾		Adjusted EBITDA and gross margin are defined above within this Item 2 under the caption How We Evaluate Our Operations, which includes a reconciliation of Adjusted EBITDA to its most directly comparable measures calculated and presented in accordance with GAAP.

For purposes of the following discussion, any increases or decreases “for the three months ended June 30, 2009” refer to the comparison of the three months ended June 30, 2009 with the three months ended June 30, 2008 and any increases or decreases “for the six months ended June 30, 2009” refer to the comparison of the six months ended June 30, 2009 with the six months ended June 30, 2008.

Summary Financial Results

Total revenues decreased by $40.6 million and $71.2 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. For the three months ended June 30, 2009, gathering, processing and transportation

revenues decreased by $286,000; natural gas, NGLs and condensate revenues decreased by $38.1 million and equity income and other revenues decreased by $2.2 million. For the six months ended June 30, 2009, gathering, processing and transportation revenues decreased by $874,000; natural gas, NGLs and condensate revenues decreased by $68.1 million and equity income and other revenues decreased by $2.2 million.

Net income increased by $2.5 million and $4.4 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. The increase for the three months ended June 30, 2009 is primarily due to a $38.7 million decrease in operating expenses, a $4.1 million decrease in income tax expense and a $379,000 increase in net interest income, partially offset by a $40.6 million decrease in revenues. The increase for the six months ended June 30, 2009 is primarily due to a $57.9 million decrease in operating expenses, a $13.1 million decrease in income tax expense and a $4.6 million increase in net interest income, partially offset by a $71.2 million decrease in revenues. The changes in revenues, operating expenses, interest expense and income taxes are discussed in more detail below.

Operating Statistics


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Δ⁽¹⁾			2009		2008		Δ⁽¹⁾
					(MMcf/d, except percentages and gross margin per Mcf)
Gathering and transportation throughput
Affiliates		784		860		(9	)%		783		848		(8	)%
Third parties		126		121		4	%		128		120		7	%

Total gathering and transportation throughput		910		981		(7	)%		911		968		(6	)%

Processing throughput — third parties		30		29		3	%		29		29		0	%

Equity investment throughput ⁽²⁾		120		112		7	%		122		107		14	%


Total throughput		1,060		1,122		(6	)%		1,062		1,104		(4	)%

Gross margin per Mcf ⁽³⁾	$	0.42	$	0.42		0	%	$	0.41	$	0.45		(9	)%


⁽¹⁾		Represents the percentage change for the three months ended June 30, 2009 or for the six months ended June 30, 2009.

⁽²⁾		Represents the Partnership’s 14.81% share of Fort Union’s gross volumes.

⁽³⁾		Calculated as gross margin (total revenues less cost of product) divided by total throughput, including income and volumes attributable to the Partnership’s investment in Fort Union. Processing volumes originate from third parties while the related residue gas and NGLs are sold to an affiliate, therefore the gross margin per Mcf calculated separately for affiliates and third parties is not meaningful.

Total throughput, which consists of affiliate, third-party and equity investment volumes, decreased by 62,000 Mcf/d for the three months ended June 30, 2009 and decreased by 42,000 Mcf/d for the six months ended June 30, 2009.

Affiliate gathering and transportation throughput decreased by 76,000 Mcf/d and 65,000 Mcf/d for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, primarily due to throughput decreases at the Pinnacle and Dew systems, partially offset by affiliate throughput increases at the MIGC system. Production and associated throughput from the Dew and Pinnacle systems have gradually declined due to natural production declines associated with existing wells and reduced rig activity resulting in fewer new well connections. In addition, contract terms for one Pinnacle customer changed in August 2008 in which a producer chose to take its product in-kind and contract directly with us for gathering services, rather than to sell its production to our affiliate at the wellhead, resulting in a shift in volumes from affiliate to third party. Affiliate volume increases for the MIGC system are primarily due to an increase in the throughput from an affiliate upon expiration of two third-party contracts in December 2008 and January 2009.

Third-party gathering and transportation throughput increased by 5,000 Mcf/d and 8,000 Mcf/d for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, primarily attributable to throughput increases at the Haley and Pinnacle systems, partially offset by third-party throughput decreases at the MIGC system. The increase in third-party throughput at the Haley and Pinnacle systems is primarily due to changes in contract terms in which producers elected

to take their product in-kind and contract directly with us for gathering services, rather than sell their production to our affiliate, resulting in a shift from affiliate to third-party throughput. The declines experienced on the MIGC pipeline were primarily due to the expiration of two third-party contracts mentioned above and, with respect to the three months ended June 30, 2009, also due to production outages in March 2009 due to snowstorm activity in Wyoming.

Processing volumes remained relatively unchanged for the three months ended June 30, 2009 and for the six months ended June 30, 2009. Equity investment volumes increased by 8,000 Mcf/d and 15,000 Mcf/d for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, primarily due to additional throughput from the Powder River area following expansion of the Fort Union system during the second half of 2008.

Gathering, Processing and Transportation of Natural Gas Revenues


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Δ			2009		2008		Δ
	(in thousands, except percentages)
Gathering, processing and transportation of natural gas:
Affiliates	$	26,989	$	27,599		(2	)%	$	53,900	$	54,794		(2	)%
Third parties		3,770		3,446		9	%		7,576		7,556		0	%

Total	$	30,759	$	31,045		(1	)%	$	61,476	$	62,350		(1	)%

Total gathering, processing and transportation of natural gas revenues decreased by $286,000 and $874,000 for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. Revenues from affiliates decreased by $610,000 and $894,000 for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, primarily due to decreased volumes in the Pinnacle and Dew systems, partially offset by affiliate volume increases at the MIGC system due to the third-party contract expirations that caused volumes and associated revenues to shift from third party to affiliate. Revenues from third parties increased by $324,000 for the three months ended June 30, 2009 and $20,000 for the six months ended June 30, 2009, primarily due to third-party volume increases at the Haley and Pinnacle systems, partially offset by a decrease in third-party volumes on the MIGC system attributable to the third-party contract expirations described above.

Natural Gas, Natural Gas Liquids and Condensate Sales


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Δ			2009		2008		Δ
			(in thousands, except percentages and per-unit amounts)
Natural gas sales:
Affiliates	$	5,900	$	19,377		(70	)%	$	13,476	$	34,346		(61	)%
Third parties		2		15		(87	)%		4		22		(82	)%

Total	$	5,902	$	19,392		(70	)%	$	13,480	$	34,368		(61	)%

Natural gas liquids sales — affiliates	$	8,597	$	29,619		(71	)%	$	17,530	$	57,257		(69	)%

Drip condensate sales — third parties	$	1,932	$	5,540		(65	)%	$	3,400	$	10,860		(69	)%

Total natural gas, natural gas liquids and condensate sales:
Affiliates	$	14,497	$	48,996		(70	)%	$	31,006	$	91,603		(66	)%
Third parties		1,934		5,555		(65	)%		3,404		10,882		(69	)%

Total	$	16,431	$	54,551		(70	)%	$	34,410	$	102,485		(66	)%


Average price per unit:
Natural gas (per Mcf)	$	2.90	$	9.98		(71	)%	$	3.36	$	8.64		(61	)%
Natural gas liquids (per Bbl)	$	37.82	$	84.99		(56	)%	$	37.71	$	81.14		(54	)%
Drip condensate (per Bbl)	$	47.75	$	116.46		(59	)%	$	38.55	$	102.77		(62	)%

Total natural gas, natural gas liquids and condensate sales decreased by $38.1 million and $68.1 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. The decrease for the three months ended June 30, 2009 consisted of a $21.0 million decrease in NGLs sales, a $13.5 million decrease in natural gas sales and a

$3.6 million decrease in drip condensate sales. The decrease for the six months ended June 30, 2009 consisted of a $39.7 million decrease in NGLs sales, a $20.9 million decrease in natural gas sales and a $7.5 million decrease in drip condensate sales.

The decrease in NGLs sales was primarily due to a decrease in the average price for NGLs sold. The average natural gas and NGLs prices for the three and six months ended June 30, 2009 include gains from commodity price swap agreements. The decrease in the NGLs sales per Bbl is due to the decrease in market prices, partially offset by the fixed prices at the Hilight and Newcastle systems under the commodity price swap agreements. The fixed prices under the swap agreements were lower than 2008 market prices but higher than 2009 market prices. The volume of NGLs sold decreased by approximately 162,000 Bbls, or 39%, for the three months ended June 30, 2009 and decreased by approximately 268,000 Bbls, or 35%, for the six months ended June 30, 2009, primarily due to the shut-in of a plant at the Hilight system in September 2008 in which butane was purchased, processed into iso-butane and sold.

The decrease in natural gas sales was primarily due to a decrease in the average price for residue sold. The decrease in average natural gas prices was partially offset by an increase in the volume of natural gas sold for the three months ended June 30, 2009 and for the six months ended June 30, 2009.

The decrease in drip condensate sales was primarily due to decreased average prices for drip condensate sold.

Equity Income and Other Revenues


	Three Months Ended June 30,								Six Months Ended June 30,
	2009		2008			Δ			2009		2008		Δ
	(in thousands, except percentages)
Equity income — affiliate	$	1,985	$	1,959			1	%	$	3,535	$	2,301		54	%

Other revenues, net:
Affiliates	$	654	$	3,058			(79	)%	$	834	$	3,366		(75	)%
Third parties		145		(4	)	nm⁽¹⁾				607		1,529		(60	)%


Total equity and other revenues, net	$	2,784	$	5,013			(44	)%	$	4,976	$	7,196		(31	)%


⁽¹⁾		Percent change is not meaningful

Total equity income and other revenues decreased by $2.2 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009. The decrease for the three months ended June 30, 2009 and for the six months ended June 30, 2009 was primarily due to a decrease in other affiliate revenues resulting from changes in gas imbalance positions and related gas prices. In addition, $0.9 million of other revenues were recorded in the three months ended June 30, 2008 related to an indemnity payment received from a third party. For the six months ended June 30, 2009, these decreases were offset by an increase in equity income from our investment in Fort Union following system expansions.

Cost of Product and Operation and Maintenance Expenses


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Δ			2009		2008		Δ
			(in thousands, except percentages and per-unit amounts)
Cost of product	$	9,489	$	47,839		(80	)%	$	22,017	$	81,567		(73	)%
Operation and maintenance		10,371		12,397		(16	)%		19,607		23,343		(16	)%

Total cost of product and operation and maintenance expenses	$	19,860	$	60,236		(67	)%	$	41,624	$	104,910		(60	)%


Cost of product — average price per unit:
Natural gas (per Mcf)	$	1.87	$	7.79		(76	)%	$	2.21	$	7.03		(69	)%
Natural gas liquids (per Bbl)	$	18.32	$	56.84		(68	)%	$	18.25	$	56.99		(68	)%
Drip condensate (per MMBtu)	$	2.59	$	8.93		(71	)%	$	3.00	$	7.91		(62	)%

Cost of product expense decreased by $38.4 million and $59.5 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. The decrease for the three months ended June 30, 2009 includes an approximate $30.0 million decrease in cost of product expense attributable to the lower cost of natural gas and NGLs we purchase from producers, primarily due to lower market prices, a $3.9 million decrease in the cost of fuel primarily attributable to the shut-in of a plant at the Hilight system in September 2008 and lower prices, a $2.9 million decrease due to changes in gas imbalance positions and related gas prices and a $1.6 million decrease from the lower cost of natural gas to compensate shippers on a thermally equivalent basis for drip condensate retained by us and sold to third parties. The decrease for the six months ended June 30, 2009 includes an approximate $53.1 million decrease attributable to the lower cost of natural gas and NGLs we purchase from producers, primarily due to lower market prices, a $3.5 million decrease due to changes in gas imbalance positions and related gas prices and a $2.9 million decrease in cost of product expense from the lower cost of natural gas to compensate shippers on a thermally equivalent basis for drip condensate retained by us and sold to third parties. The decreases in natural gas cost of product expense from lower prices were partially offset by a 15% and 13% increase in volumes of natural gas purchased from producers for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, as a decrease in the volume of NGLs recovered per Mcf of gas processed resulted in an increase in the volume of residue gas purchased. NGLs volumes decreased by 39% and 35% for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, primarily due to the shut-in of a plant at the Hilight system in September 2008.

Operation and maintenance expense decreased by $2.0 million and $3.7 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. The decrease for the three months ended June 30, 2009 is primarily due to a $1.4 million decrease in operating fuel costs attributable to the shut-in of a plant in the Hilight system in September 2008; a $313,000 decrease in compressor parts and rental expenses primarily due to the contribution of previously leased compression equipment to the Partnership in November 2008 and lower rates on equipment rentals as a result of renegotiating with suppliers; and a $258,000 decrease in labor and labor-related expenses. The decrease for the six months ended June 30, 2009 is primarily due to a $2.1 million decrease in operating fuel costs attributable to the shut-in of a plant in the Hilight system effective September 2008; a $661,000 decrease in compressor parts and rental expenses primarily due to the contribution of previously leased compression equipment to the Partnership in November 2008 and lower rates on equipment rentals as a result of renegotiating with suppliers; and a $289,000 decrease in labor and labor related expenses.

Gross Margin


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Δ			2009		2008		Δ
			(in thousands, except percentages and gross margin per Mcf)
Gross margin	$	40,485	$	42,770		(5	)%	$	78,845	$	90,464		(13	)%
Gross margin per Mcf ⁽¹⁾	$	0.42	$	0.42		0	%	$	0.41	$	0.45		(9	)%


⁽¹⁾		Calculated as gross margin (total revenues less cost of product) divided by total throughput, including income and volumes attributable to the Partnership’s investment in Fort Union.

Gross margin decreased by $2.3 million and $11.6 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. The decrease in gross margin for the three months ended June 30, 2009 and for the six months ended June 30, 2009 is primarily due to the decrease in natural gas and NGLs prices and throughput volumes. The impact of the decrease in market prices on our gross margin was mitigated by our fixed-price contract structure. Gross margin per Mcf remained flat for the three months ended June 30, 2009 and decreased by 9% for the six months ended June 30, 2009. The decrease in gross margin per Mcf for the six-month period is primarily due to lower processing margins and drip condensate margins.

General and Administrative, Depreciation and Other Expenses


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Δ			2009		2008		Δ
	(in thousands, except percentages)
General and administrative	$	3,860	$	2,792		38	%	$	8,583	$	4,752		81	%
Property and other taxes		1,771		1,717		3	%		3,528		3,350		5	%
Depreciation and amortization		8,752		8,204		7	%		17,373		15,986		9	%

Total general and administrative, depreciation and other expenses	$	14,383	$	12,713		13	%	$	29,484	$	24,088		22	%

General and administrative, depreciation and other expenses increased by $1.7 million and $5.4 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. General and administrative expenses increased by $1.1 million for the three months ended June 30, 2009, primarily due to incurring expenses attributable to being a publicly traded partnership and equity-based compensation expense for the full three months ended June 30, 2009, compared to approximately half of the quarter ended June 30, 2008. Expenses attributable to being a publicly traded partnership include consulting and auditing fees; expenses attributable to accounting personnel dedicated to the operations of the Partnership; expenses associated with annual and quarterly reporting; tax return and schedule K-1 preparation and distribution expenses; expenses associated with listing on the New York Stock Exchange; investor relations expenses; registrar and transfer agent fees; independent auditor fees; legal expenses and director fees. Prior to May 14, 2008, with respect to the initial assets, and prior to December 1, 2008, with respect to the Powder River assets, general and administrative expenses included costs allocated by Anadarko to the Partnership in the form of a management services fee. Subsequent to May 14, 2008, with respect to the initial assets, and subsequent to December 1, 2008, with respect to the Powder River assets, general and administrative expenses were charged to us by Anadarko pursuant to the omnibus agreement and incurred directly. General and administrative expenses increased $3.8 million for the six months ended June 30, 2009, primarily due to incurring expenses attributable to being a publicly traded partnership and equity-based compensation expense.

Depreciation and amortization expense increased $548,000 and $1.4 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, due to depreciation on assets placed in service in late 2008 and in 2009, primarily attributable to the expansion to our Pinnacle Bethel treating facility completed in July 2008 and previously leased Hugoton compression equipment contributed to the Partnership in November 2008.

Interest Income, Net — Affiliates


	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Δ			2009			2008			Δ
	(in thousands, except percentages)
Interest income on note receivable from Anadarko	$	4,225		$	2,226			90	%	$	8,450		$	2,226			280	%
Interest (expense) on note payable to Anadarko		(1,750	)		—			nm	⁽¹⁾		(3,500	)		—			nm
Interest (expense), net — affiliates		(36	)		(166	)		(78	)%		(71	)		(1,955	)		(96	)%

Total	$	2,439		$	2,060			18	%	$	4,879		$	271		nm


⁽¹⁾		Percentage change is not meaningful

Interest income, net for the three and six months ended June 30, 2009, consisted of interest income on our $260.0 million note receivable from Anadarko entered into in connection with our initial public offering in May 2008, partially offset by interest expense attributable to our $175.0 million term loan agreement entered into with Anadarko in connection with the Powder River acquisition and commitment fees on our $100.0 million portion of Anadarko’s $1.3 billion credit facility and our $30.0 million working capital facility. Interest income, net for the three and six months ended June 30, 2008 consisted of interest income on our $260.0 million note receivable from Anadarko, partially offset by interest charged on affiliate balances.

Income Tax Expense


	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Δ			2009			2008			Δ
	(in thousands, except percentages)
Income before income taxes	$	18,179		$	19,747			(8	)%	$	34,647		$	43,335			(20	)%
Income tax expense (benefit)		55			4,168			(99	)%		(435	)		12,635			(103	)%
Effective tax rate		0	%		21	%					(1	)%		29	%

Income tax expense decreased by $4.1 million and $13.1 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, primarily due to a change in the applicability of U.S. federal income tax to our income that occurred in connection with our initial public offering. Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, subsequent to May 14, 2008, with respect to our initial assets, and subsequent to December 19, 2008, with respect to the Powder River assets, was subject only to Texas margin tax while income earned prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, was subject to federal and state income tax. In addition, for the six months ended June 30, 2009, our estimated income attributed to Texas relative to our total income decreased as compared to the prior year, which resulted in a $560,000 reduction of previously recognized deferred taxes. For 2008, the variance from the federal statutory rate is primarily attributable to our U.S. federal income tax status as a non-taxable entity after May 14, 2008, partially offset by state income tax expense.

LIQUIDITY AND CAPITAL RESOURCES

Our ability to finance operations, fund maintenance capital expenditures and pay distributions will largely depend on our ability to generate sufficient cash flow to cover these requirements. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please read Item 1A—Risk Factors of our annual report on Form 10-K.

Prior to our initial public offering, our sources of liquidity included cash generated from operations and funding from Anadarko. Furthermore, we had participated in Anadarko’s cash management program, whereby Anadarko, on a periodic basis, swept cash balances residing in our bank accounts. Thus, our historical consolidated financial statements for periods ending prior to our initial public offering reflect no significant cash balances. Unlike our transactions with third parties, which ultimately are settled in cash, our affiliate transactions prior to May 14, 2008, with respect to our initial assets, and prior to December 19, 2008, with respect to the Powder River assets, were settled on a net basis through an adjustment to parent net equity. Subsequent to our initial public offering, we maintain our own bank accounts and sources of liquidity. Although we continue to utilize Anadarko’s cash management system, our cash accounts are not subject to cash sweeps with Anadarko’s cash accounts.

Our current sources of liquidity include:

	•		approximately $33.0 million of working capital as of June 30, 2009, which we define as the amount by which current assets exceed current liabilities;

	•		cash generated from operations;

	•		available borrowings of up to $100.0 million under Anadarko’s credit facility;

	•		available borrowings under our $30.0 million working capital facility with Anadarko;

	•		interest income from our $260.0 million note receivable from Anadarko; and

	•		issuances of additional partnership units.

We believe that cash generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance capital expenditure requirements. The amount of future distributions to unitholders will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis.

Working capital

Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by factors such as credit extended to, and the timing of collections from, our customers and our level of spending for maintenance and expansion activity.

Historical cash flow

The following table and discussion presents a summary of our net cash flows from operating activities, investing activities and financing activities as well as Adjusted EBITDA for the three and six months ended June 30, 2009 and 2008.

For the period prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, our net cash from operating activities and capital contributions from our parent were used to service our cash requirements, which included the funding of operating expenses and capital expenditures. Subsequent to May 14, 2008, with respect to our initial assets, and subsequent to December 19, 2008, with respect to the Powder River assets, transactions with Anadarko are cash-settled.


	Three Months Ended June 30,									Six Months Ended June 30,
	2009			2008			Δ			2009			2008			Δ
	(in thousands, except percentages)
Net cash provided by (used in):
Operating activities	$	35,036		$	19,306			81	%	$	52,601		$	46,630			13	%
Investing activities		(5,435	)		(273,323	)		98	%		(11,981	)		(280,030	)		96	%
Financing activities	$	(17,039	)	$	279,805			(106	)%	$	(34,068	)	$	259,188			(113	)%

Net increase in cash and cash equivalents	$	12,562		$	25,788			(51	)%	$	6,552		$	25,788			(75	)%
Adjusted EBITDA⁽¹⁾	$	24,899		$	25,010			0	%	$	47,950		$	59,230			(19	)%

⁽¹⁾ For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see above within this Item 2 under the caption How We Evaluate Our Operations.

Operating Activities. Net cash provided by operating activities increased by $15.7 million and $6.0 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively, primarily attributable to lower gross margins and higher general and administrative expenses as described in Results of Operations—Overview above. These items were partially offset by lower current income taxes, higher net interest income and lower operations and maintenance expenses as described in Results of Operations—Overview above.

Investing Activities. Net cash used in investing activities decreased by $267.9 million and $268.0 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. Net cash used in investing activities for the three and six months ended June 30, 2008 included our $260.0 million loan made to Anadarko in connection with our initial

public offering. In addition, capital expenditures decreased by $2.5 million and $2.7 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. Expansion capital expenditures decreased by 85%, from $4.4 million during the three months ended June 30, 2008 to $671,000 during the three months ended June 30, 2009, primarily due to expansions of the Bethel facility completed during 2008. This decrease was offset by a 35% increase in maintenance cash capital expenditures, from $3.3 million during the three months ended June 30, 2008 to $4.5 million during the three months ended June 30, 2009, primarily due to a compression overhaul at our Hugoton System, an upgrade to the control system at the Hilight facility and equipment replacements at the Bethel facility during 2009. Expansion capital expenditures decreased by 65%, from $8.5 million during the six months ended June 30, 2008 to $3.0 million during the six months ended June 30, 2009, primarily due to the completion of expansions of the Bethel facility and at the Dew system during 2008. This decrease was partially offset by a 47% increase in maintenance capital expenditures, from $5.9 million during the six months ended June 30, 2008 to $8.7 million during the six months ended June 30, 2009, primarily due to a compression overhaul at our Hugoton System, an upgrade to the control system at the Hilight facility and equipment replacements at the Bethel facility during 2009. Investing cash flows included contribution to Fort Union of $5.6 million during the three and six months ended June 30, 2009 related to the system expansion.

Financing Activities. Net cash used in financing activities decreased by $296.9 million and $293.3 million for the three months ended June 30, 2009 and for the six months ended June 30, 2009, respectively. Net cash provided by financing activities for the three and six months ended June 30, 2008 included the receipt of $315.3 million of net proceeds from our initial public offering, partially offset by reimbursement to Anadarko of $45.3 million for pre-offering capital expenditures. For the three and six months ended June 30, 2009, $17.0 million and $34.1 million, respectively, of cash distributions were paid to unitholders. Our initial public offering occurred in May 2008; therefore, no distributions were paid to unitholders during the three or six months ended June 30, 2008. We paid $10.8 million of net distributions to Anadarko for the six months ended June 30, 2008, representing the net settlement of intercompany transactions attributable to the Powder River assets.

Adjusted EBITDA. Adjusted EBITDA remained relatively flat for the three months ended June 30, 2009 and decreased by $11.3 million for the six months ended June 30, 2009. The decrease for the six months ended June 30, 2009 is primarily due to a $72.4 million decrease in total revenues, excluding equity income and a $2.3 million increase in general and administrative expenses, excluding non-cash equity-based compensation, partially offset by a $59.6 million decrease in cost of product, a $3.7 million decrease in operation and maintenance expenses and a $319,000 decrease in distributions from Fort Union.

Capital requirements

Our business can be capital intensive, requiring significant investment to maintain and improve existing facilities. We categorize capital expenditures as either:

	•		maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory or legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or

	•		expansion capital expenditures, which include those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase gathering, processing, treating and transmission throughput or capacity from current levels, including well connections that increase existing system volumes.

Total capital incurred for the six months ended June 30, 2009 and 2008 was $10.2 million and $13.2 million, respectively. Capital incurred is presented on an accrual basis. Capital expenditures in the consolidated statement of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital expenditures for the six months ended June 30, 2009 and 2008 were $11.7 million and $14.4 million, respectively. Expansion capital expenditures represented approximately 25% and 59% of total capital expenditures for the six months ended June 30, 2009 and 2008, respectively. We estimate our total capital expenditures, excluding Chipeta capital expenditures prior to our acquisition of the asset in July and any future acquisitions, to be $22.0 million to $26.0 million and our maintenance capital expenditures to be approximately 85% of total capital expenditures for the twelve months ending December 31, 2009. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us, which are dependent, in part, on the drilling activities of Anadarko and third-party producers. From time to time, for projects with significant risk or capital exposure, we may secure indemnity provisions or throughput agreements.

We expect to fund future capital expenditures from cash flows generated from our operations, interest income from our note receivable from Anadarko, borrowings under Anadarko’s credit facility, the issuance of additional partnership units or debt offerings.

Distributions

We expect to pay a minimum quarterly distribution of $0.31 per unit per full quarter, which equates to approximately $17.7 million per full quarter, or approximately $70.9 million per full year, based on the number of common, subordinated and general partner units outstanding as of July 31, 2009. Our partnership agreement requires that the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the six months ended June 30, 2009, we paid cash distributions to our unitholders of $0.30 per unit, or $34.1 million in aggregate, representing the distribution for the quarters ended December 31, 2008 and March 31, 2009. On July 21, 2009, the board of directors of our general partner declared a cash distribution to our unitholders of $0.31 per unit, or $17.7 million in aggregate, which is payable on August 14, 2009 to unitholders of record at the close of business on July 31, 2009.

Our borrowing capacity under Anadarko’s credit facility

On March 4, 2008, Anadarko entered into a $1.3 billion credit facility under which we are a co-borrower. This credit facility is available for borrowings and letters of credit and permits us to utilize up to $100.0 million under the facility for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Anadarko. At June 30, 2009, the full $100.0 million was available for borrowing by us. The $1.3 billion credit facility expires in March 2013.

Interest on borrowings under the credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.50% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which was 0.44% at June 30, 2009, and the commitment fees on the facility are based on Anadarko’s senior unsecured long-term debt rating. Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, we are required to reimburse Anadarko for our allocable portion of commitment fees (0.11% of our committed and available borrowing capacity, including our outstanding balances, if any) that Anadarko incurs under its credit facility, or up to $110,000 annually. Under Anadarko’s credit agreements, we and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 60% or less. As of June 30, 2009, we and Anadarko were in compliance with all covenants. Should we or Anadarko fail to comply with any covenant in Anadarko’s credit agreements, we may not be permitted to borrow thereunder. Anadarko is a guarantor of our borrowings, if any, under the credit facility. We are not a guarantor of Anadarko’s borrowings under the credit facility.

Our working capital facility

Concurrent with the closing of our initial public offering, we entered into a two-year, $30.0 million working capital facility with Anadarko as the lender. At June 30, 2009, no borrowings were outstanding under the working capital facility. The facility is available exclusively to fund working capital needs. Borrowings under the facility will bear interest at the same rate as would apply to borrowings under the Anadarko credit facility described above. We pay a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility, or up to $33,000 annually.

We are required to reduce all borrowings under our working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility.

Credit risk

We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including Anadarko. Generally, non-payment or non-performance results from a customer’s inability to satisfy receivables for services rendered or volumes owed pursuant to gas imbalance agreements. We examine the creditworthiness of third-party customers and may establish credit limits for significant third-party customers.

We are dependent upon a single producer, Anadarko, for the majority of our natural gas volumes and we do not maintain a credit limit with respect to Anadarko. Consequently, we are subject to the risk of non-payment or late payment by Anadarko for gathering, treating and transmission fees and for proceeds from the sale of natural gas, NGLs and condensate to Anadarko.

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we are exposed to credit risk on the note receivable from Anadarko that was issued concurrent with the closing of our initial public offering. We are also party to an omnibus agreement with Anadarko under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits and income taxes with respect to the initial assets. Finally, we entered into commodity price swap agreements with Anadarko in order to substantially reduce our exposure to commodity price risk attributable to our percent-of-proceeds contracts for the Hilight system and the Newcastle system and are subject to performance risk thereunder.

If Anadarko becomes unable to perform under the terms of our gathering, processing and transportation agreements, natural gas and NGL purchase agreements, its note payable to us, the omnibus agreement, the services and secondment agreement or the commodity price swap agreements, our ability to make distributions to our unitholders may be adversely impacted.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than operating leases. The information pertaining to operating leases required for this item is provided in Note 11—Commitments and Contingencies, included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q.


Item 3.		Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We bear a limited degree of commodity price risk with respect to certain of our gathering contracts. Specifically, pursuant to certain of our contracts, we retain and sell drip condensate that is recovered during the gathering of natural gas. As part of this arrangement, we are required to provide a thermally equivalent volume of natural gas or the cash equivalent thereof to the shipper. Thus, our revenues for this portion of our contractual arrangement are based on the price received for the drip condensate and our costs for this portion of our contractual arrangement depend on the price of natural gas. Historically, drip condensate sells at a price representing a slight discount to the price of NYMEX West Texas Intermediate crude oil.

In addition, certain of our processing services are provided under percent-of-proceeds agreements in which Anadarko is typically responsible for the marketing of the natural gas and NGLs. Under these agreements, we receive a specified percent of the net proceeds from the sale of natural gas and NGLs. To mitigate our exposure to changes in commodity prices on these processing agreements, we entered into commodity price swap agreements with Anadarko with fixed commodity prices that extend through December 31, 2010, with an option to extend through 2013. For additional information on the commodity price swap agreements, see Note 5—Transactions with Affiliates included in the notes to the unaudited consolidated financial statements under Part I, Item 1 of this Form 10-Q.

We consider our exposure to commodity price risk associated with the above-described arrangements to be minimal given the relatively small amount of our operating income generated by drip condensate sales and the existence of the commodity price swap agreements with Anadarko. For the three months ended June 30, 2009, a 10% change in the margin between drip condensate and natural gas would have resulted in an approximate $141,000, or less than 1%, change in operating income for the period.

We also bear a limited degree of commodity price risk with respect to settlement of our natural gas imbalances that arise from differences in gas volumes received into our systems and gas volumes delivered by us to customers. Natural gas volumes owed to or by us that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates, and generally reflect market index prices. Other natural gas volumes owed to or by us are valued at our weighted average cost of natural gas as of the balance sheet dates and are settled in-kind. Our exposure to the impact of changes in commodity prices on outstanding imbalances depends on the timing of settlement of the imbalances.

Interest Rate Risk

Interest rates during the periods discussed above were low compared to rates over the last 50 years. If interest rates rise, our future financing costs will increase. As of June 30, 2009, we owed $175.0 million to Anadarko under our five-year term loan we entered into in connection with the Powder River acquisition and had $100.0 million of credit available for borrowing under Anadarko’s five-year credit facility in addition to $30.0 million available under our two-year working capital facility with Anadarko. Our $175.0 million term loan agreement with Anadarko requires us to pay interest at a fixed rate of 4.0% for the first two years and a floating rate, three-month LIBOR plus 150 basis points, for the final three years. Interest on borrowings under Anadarko’s credit facility is calculated based on the election by the borrower of either: (i) a floating rate

equal to the federal funds effective rate plus 0.50% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which was 0.44% at June 30, 2009, is based on Anadarko’s senior unsecured long-term debt rating. Borrowings under our working capital facility bear interest at the same rate that would apply to borrowings under the Anadarko credit facility. We may incur additional debt in the future, either through accessing our working capital facility with Anadarko, our $100.0 million borrowing capacity under Anadarko’s existing credit facility or other financing sources, including commercial bank borrowings or debt issuances.


Item 4T.		Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the second quarter of 2009, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


Item 1.		Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial position.


Item 6.		Exhibits

Exhibits are listed below in the Exhibit Index of this report on Form 10-Q.

SIGNATURES

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



Date: August 12, 2009	By:	/s/ Robert G. Gwin
		Robert G. Gwin
		President and Chief Executive Officer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)


Date: August 12, 2009	By:	/s/ Benjamin M. Fink
		Benjamin M. Fink
		Senior Vice President and Chief Financial Officer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)

EXHIBIT INDEX

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


3.1		Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).

3.2		First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).

3.3		Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of December 19, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).

3.4		Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of April 15, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046).

3.5		Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).

3.6		Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated as of May 14, 2008 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).

4.1		Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).

31.1*		Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.