Western Midstream Partners 10-Q 2010 Q1 Quarterly report

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 March 31, 2010

Or

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. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted 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). Yeso Noo

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

Large accelerated filero Accelerated filerþ Non-accelerated filero(Do not check if smaller reporting company) Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yeso Noþ

There were 36,995,614 common units outstanding as of April 30, 2010.

TABLE OF CONTENTS

	Page
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income for the three months ended March 31, 2010 and 2009		4
Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009		5
Consolidated Statement of Equity and Partners’ Capital for the three months ended March 31, 2010		6
Consolidated Statements of Cash Flows for the three months ended March 31, 2010 and 2009		7
Notes to Unaudited Consolidated Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
Executive Summary		23
Acquisitions		24
Items Affecting the Comparability of Our Financial Results		25
Results of Operations		26
Operating Results		26
Liquidity and Capital Resources		36
Contractual Obligations		40
Off-Balance Sheet Arrangements		40
Item 3. Quantitative and Qualitative Disclosures About Market Risk		40
Item 4. Controls and Procedures		41
PART II OTHER INFORMATION
Item 1. Legal Proceedings		41
Item 1A. Risk Factors		41
Item 6. Exhibits		41
EX-10.3
EX-31.1
EX-31.2
EX-32.1

2

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; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

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.

MMBtu:One million British thermal units.

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

MMcf/d:One million cubic feet per day. All volumes presented herein are based on a standard pressure base of 14.73 pounds per square inch, absolute.

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 gasoline that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Pounds per square inch, absolute:The pressure resulting from a one pound-force applied to an area of one square inch, including local atmospheric pressure.

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

3

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
	March 31,
	2010			2009(1)
Revenues – affiliates
Gathering, processing and transportation of natural gas	$	37,114		$	36,074
Natural gas, natural gas liquids and condensate sales		45,159			42,160
Equity income and other		1,557			1,730
Total revenues – affiliates		83,830			79,964
Revenues – third parties
Gathering, processing and transportation of natural gas		6,245			7,260
Natural gas, natural gas liquids and condensate sales		3,693			1,472
Other, net		551			464
Total revenues – third parties		10,489			9,196
Total revenues		94,319			89,160
Operating expenses (2)
Cost of product		32,578			33,645
Operation and maintenance		15,167			14,086
General and administrative		5,074			6,285
Property and other taxes		2,769			2,821
Depreciation and amortization		13,683			12,016
Total operating expenses		69,271			68,853
Operating income		25,048			20,307
Interest income, net (3)		697			2,677
Other income, net		20			7
Income before income taxes		25,765			22,991
Income tax expense		957			266
Net income		24,808			22,725
Net income attributable to noncontrolling interests		1,894			2,139
Net income attributable to Western Gas Partners, LP	$	22,914		$	20,586
Limited partner interest in net income:
Net income attributable to Western Gas Partners, LP (4)	$	22,914		$	20,586
Pre-acquisition (income) loss allocated to Parent		1,218			(3,628	)
General partner interest in net income		(483	)		(339	)
Limited partner interest in net income	$	23,649		$	16,619
Net income per common unit – basic and diluted	$	0.37		$	0.30
Net income per subordinated unit – basic and diluted	$	0.37		$	0.30

(1)	Financial information for 2009 has been revised to include results attributable to the Chipeta assets and Granger assets. SeeNote 1—Description of Business and Basis of Presentation—Acquisitions.
(2)	Operating expenses include amounts charged by Anadarko to the Partnership (“Anadarko” and “Partnership” are as defined inNote 1—Description of Business and Basis of Presentation)for services as well as reimbursement of amounts paid by Anadarko to third parties on behalf of the Partnership. Cost of product expenses include product purchases from Anadarko of $11.1 million and $13.8 million for the three months ended March 31, 2010 and 2009, respectively. Operation and maintenance expenses include charges from Anadarko of $8.5 million and $5.3 million for the three months ended March 31, 2010 and 2009, respectively. General and administrative expenses include charges from Anadarko of $3.5 million and $5.0 million for the three months ended March 31, 2010 and 2009, respectively. SeeNote 4—Transactions with Affiliates.
(3)	Interest income, net includes net interest income from affiliates of $2.4 million and $2.7 million for the three months ended March 31, 2010 and 2009, respectively. SeeNote 4—Transactions with Affiliates.
(4)	General and limited partner interest in net income represents net income for periods including and subsequent to the Partnership’s acquisition of the Partnership Assets (as defined inNote 1—Description of Business and Basis of Presentation — Presentation of Partnership Acquisitions). See alsoNote 3—Net Income per Limited Partner Unit.

See accompanying notes to unaudited consolidated financial statements.

4

Western Gas Partners, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited, in thousands, except number of units)

	March 31,		December 31,
	2010		2009
ASSETS
Current assets
Cash and cash equivalents	$	55,223	$	69,984
Accounts receivable, net — third parties		4,304		4,076
Accounts receivable — affiliates		6,165		2,203
Natural gas imbalance receivables — third parties		688		266
Natural gas imbalance receivables — affiliates		41		448
Other current assets		3,392		3,287
Total current assets		69,813		80,264
Note receivable — Anadarko		260,000		260,000
Property, plant and equipment
Cost		1,250,664		1,246,155
Less accumulated depreciation		265,939		252,778
Net property, plant and equipment		984,725		993,377
Goodwill		31,248		31,248
Equity investment		20,289		20,060
Other assets		2,586		2,974
Total assets	$	1,368,661	$	1,387,923
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable — third parties	$	9,203	$	12,003
Natural gas imbalance payable — third parties		193		289
Natural gas imbalance payable — affiliates		1,512		1,319
Accrued ad valorem taxes		4,239		3,046
Income taxes payable		545		412
Accrued liabilities — third parties		10,896		8,717
Accrued liabilities — affiliates		291		470
Total current liabilities		26,879		26,256
Long-term liabilities
Long-term debt — third party		210,000		—
Note payable — Anadarko		175,000		175,000
Deferred income taxes		380		92,891
Asset retirement obligations and other		15,392		15,077
Total long-term liabilities		400,772		282,968
Total liabilities		427,651		309,224
Commitments and contingencies(Note 8)
Equity and partners’ capital
Common units (36,995,614 and 36,374,925 units issued and outstanding at March 31, 2010 and December 31, 2009, respectively)		556,627		497,230
Subordinated units (26,536,306 units issued and outstanding at March 31, 2010 and December 31, 2009)		277,723		276,571
General partner units (1,296,570 and 1,283,903 units issued and outstanding at March 31, 2010 and December 31, 2009, respectively)		14,960		13,726
Parent net investment		—		200,250
Total partners’ capital		849,310		987,777
Noncontrolling interests		91,700		90,922
Total equity and partners’ capital		941,010		1,078,699
Total liabilities, equity and partners’ capital	$	1,368,661	$	1,387,923

See accompanying notes to unaudited consolidated financial statements.

5

Western Gas Partners, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(Unaudited, in thousands)

				Partners’ Capital
	Parent Net			Limited Partners						General			Noncontrolling
	Investment			Common			Subordinated			Partner			Interests			Total
Balance at December 31, 2009	$	200,250		$	497,230		$	276,571		$	13,726		$	90,922		$	1,078,699
Net pre-acquisition contributions from Parent		7,914			—			—			—			—			7,914
Elimination of net deferred tax liabilities		92,203			—			—			—			—			92,203
Contribution of Granger assets		(300,367	)		57,513			—			1,174			—			(241,680	)
Contributions from noncontrolling interest owners and Parent		—			—			—			—			1,985			1,985
Non-cash equity-based compensation		—			73			—			—			—			73
Net income		(1,218	)		13,741			9,908			483			1,894			24,808
Distributions to unitholders		—			(12,210	)		(8,756	)		(427	)		—			(21,393	)
Distributions to noncontrolling interest owners		—			—			—			—			(2,806	)		(2,806	)
Other		1,218			280			—			4			(295	)		1,207
Balance at March 31, 2010	$	—		$	556,627		$	277,723		$	14,960		$	91,700		$	941,010

See accompanying notes to unaudited consolidated financial statements.

6

Western Gas Partners, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Three Months Ended March 31,
	2010			2009(1)
Cash flows from operating activities
Net income	$	24,808		$	22,725
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		13,683			12,016
Deferred income taxes		(621	)		(689	)
Changes in assets and liabilities:
Increase in accounts receivable		(4,381	)		(8,829	)
(Increase) decrease in natural gas imbalance receivable		(15	)		1,354
Decrease (increase) in accounts payable, accrued liabilities and natural gas imbalance payable		9,124			(6,749	)
Change in other items, net		313			(251	)
Net cash provided by operating activities		42,911			19,577
Cash flows from investing activities
Granger acquisition		(241,680	)		—
Capital expenditures		(5,297	)		(24,110	)
Net cash used in investing activities		(246,977	)		(24,110	)
Cash flows from financing activities
Borrowings under revolving credit facility, net of issuance costs		209,987			—
Contributions from noncontrolling interest owners and Parent		1,985			22,327
Distributions to unitholders		(21,393	)		(17,029	)
Distributions to noncontrolling interest owners		(2,806	)		—
Net pre-acquisition contributions from (distributions to) Parent		1,532			(2,729	)
Net cash provided by financing activities		189,305			2,569
Net decrease in cash and cash equivalents		(14,761	)		(1,964	)
Cash and cash equivalents at beginning of period		69,984			36,074
Cash and cash equivalents at end of period	$	55,223		$	34,110
Supplemental disclosures
Decrease in accrued capital expenditures	$	358		$	405
Interest paid	$	2,671		$	1,455
Interest received	$	4,225		$	4,225

⁽¹⁾ Financial information for 2009 has been revised to include activity attributable to the Chipeta assets and Granger assets. SeeNote 1—Description of Business and Basis of Presentation—Acquisitions.

See accompanying notes to unaudited consolidated financial statements.

7

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 is engaged in the business of gathering, compressing, processing, treating and transporting natural gas and natural gas liquids (“NGLs”) for Anadarko Petroleum Corporation and its consolidated subsidiaries as well as for third-party producers and customers. The Partnership’s assets consist of ten gathering systems, six natural gas treating facilities, six gas processing facilities, one interstate pipeline and one NGL pipeline. The Partnership’s assets are located in East and West Texas, the Rocky Mountains and the Mid-Continent. 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; “Parent” refers to Anadarko prior to our acquisition of assets from Anadarko; and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership. The “initial assets” collectively refer to Anadarko Gathering Company LLC, or “AGC,” Pinnacle Gas Treating LLC, or “PGT,” and MIGC LLC, or “MIGC,” all of which the Partnership acquired in connection with its May 2008 initial public offering. The “Powder River assets” collectively refer to the Partnership’s 100% ownership interest in the Hilight system, 50% interest in the Newcastle system and 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C., or “Fort Union,” all of which the Partnership acquired from Anadarko in December 2008, and the “Powder River acquisition” refers to the acquisition of the Powder River assets. The “Chipeta assets” collectively refer to the 51% membership interest in Chipeta Processing LLC, or “Chipeta,” and associated natural gas liquids, or “NGL,” pipeline, which the Partnership acquired from Anadarko in July 2009, and the “Chipeta acquisition” refers to the acquisition of the Chipeta assets. The “Granger assets” collectively refer to the Granger gathering system and Granger complex, which the Partnership acquired from Anadarko in January 2010, and the “Granger acquisition” refers to the acquisition of the Granger assets. 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 March 31, 2010 and December 31, 2009, results of operations for the three months ended March 31, 2010 and 2009, statement of equity and partners’ capital for the three months ended March 31, 2010 and statements of cash flows for the three months ended March 31, 2010 and 2009. The Partnership’s financial results for the three months ended March 31, 2010 are not necessarily indicative of the results for the full year ending December 31, 2010.

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 knowledge and the best available information at the time, changes may result in revised estimates and actual results may differ from these estimates. 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.

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 (the “SEC”) on March 11, 2010, as revised by the Partnership’s current report on Form 8-K, filed with the SEC on May 4, 2010 (the “annual report on Form 10-K”) to, as discussed below, recast the Partnership’s financial statements to reflect the results generated by the Granger assets from the date in which those assets were acquired by Anadarko.

Acquisitions

Chipeta acquisition.In July 2009, the Partnership acquired certain midstream assets from Anadarko for (i) approximately $101.5 million in cash, which was financed by borrowing $101.5 million from Anadarko pursuant to the terms of a 7.0% fixed-rate, three-year term loan agreement, and (ii) 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 consisted of a 51% membership interest in Chipeta, together with an associated NGL pipeline. Chipeta owns a natural gas processing plant complex, which includes two processing trains: a refrigeration unit completed in November 2007 and a cryogenic unit which was completed in April 2009.

8

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

In November 2009, Chipeta closed its acquisition of a compressor station and processing plant (the “Natural Buttes plant”) from a third party for $9.1 million. The noncontrolling interest owners contributed $4.5 million to Chipeta during the year ended December 31, 2009 to fund their proportionate share of the Natural Buttes plant acquisition. The Natural Buttes plant is located in Uintah County, Utah.

As of March 31, 2010, Chipeta is owned 51% by the Partnership, 24% by Anadarko and 25% by a third-party member. The interests in Chipeta held by Anadarko and the third-party member are reflected as noncontrolling interests in the consolidated financial statements.

Granger acquisition. In January 2010, the Partnership acquired Anadarko’s entire 100% ownership interest in the following assets located in Southwestern Wyoming: (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains, two refrigeration trains, an NGLs fractionation facility and ancillary equipment. The Granger acquisition was financed primarily with $210.0 million in borrowings under the Partnership’s revolving credit facility plus $31.7 million of cash on hand, as well as through the issuance of 620,689 common units and 12,667 general partner units to Anadarko.

Presentation of Partnership acquisitions. The initial assets, Powder River assets, Chipeta assets and Granger assets are referred to collectively as the “Partnership Assets.” Unless otherwise noted, references to “periods prior to our acquisition of the Partnership Assets” and similar phrases refer to periods prior to May 2008, with respect to the initial assets, periods prior to December 2008, with respect to the Powder River assets, periods prior to July 2009, with respect to the Chipeta assets, and periods prior to January 2010, with respect to the Granger assets. Unless otherwise noted, references to “periods subsequent to our acquisition of the Partnership Assets” and similar phrases refer to periods including and subsequent to May 2008, with respect to the initial assets, periods including and subsequent to December 2008, with respect to the Powder River assets, periods including and subsequent to July 2009, with respect to the Chipeta assets, and periods including and subsequent to January 2010, with respect to the Granger assets.

Anadarko acquired the Granger assets in connection with its August 23, 2006 acquisition of Western Gas Resources, Inc. (“Western”) and Anadarko acquired the Chipeta assets in connection with its August 10, 2006 acquisition of Kerr-McGee Corporation (“Kerr-McGee”). The acquisitions by the Partnership of the Chipeta assets and Granger assets were considered transfers of net assets between entities under common control. Accordingly, the Partnership is required to revise its financial statements to include the activities of the Partnership Assets as of the date of common control. The Partnership’s historical financial statements for the three months ended March 31, 2009 as presented in the Partnership’s quarterly report on Form 10-Q for the quarter ended March 31, 2009, which included the results attributable to the initial assets and the Powder River assets, have been recast to include the results attributable to the Chipeta assets and the Granger assets as if the Partnership owned such assets for all periods presented. Net income attributable to the Partnership Assets for periods prior to each acquisition is not allocated to the limited partners for purposes of calculating net income per limited partner unit.

The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership 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 during the periods reported.

9

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

Limited partner and general partner units

The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.” The following table summarizes common, subordinated and general partner units issued during the three months ended March 31, 2010 (in thousands):

	Limited Partner Units				General
	Common		Subordinated		Partner Units		Total
Balance at December 31, 2009		36,375		26,536		1,284		64,195
Granger acquisition		621		—		12		633
Balance at March 31, 2010		36,996		26,536		1,296		64,828

Anadarko holdings of Partnership Equity.As of March 31, 2010, Anadarko held 1,296,570 general partner units representing a 2.0% general partner interest in the Partnership, 100% of the Partnership’s incentive distribution rights (“IDRs”), 9,254,435 common units and 26,536,306 subordinated units. Anadarko owned an aggregate 55.2% limited partner interest in the Partnership based on its holdings of common and subordinated units. The public held 27,741,179 common units, representing a 42.8% limited partner interest in the Partnership.

2. 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 three months ended March 31, 2010, the Partnership paid cash distributions to its unitholders of approximately $21.4 million, representing the $0.33 per-unit distribution for the quarter ended December 31, 2009. During the three months ended March 31, 2009, the Partnership paid cash distributions to its unitholders of approximately $17.0 million, representing the $0.30 per-unit distribution for the quarter ended December 31, 2008. See alsoNote 9—Subsequent Eventsconcerning distributions approved in April 2010.

3. NET INCOME PER LIMITED PARTNER UNIT

The Partnership’s net income attributable to the Partnership Assets for periods including and subsequent to the Partnership’s acquisitions of the Partnership Assets 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 (the “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 units than the subordinated units 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. The common units and general partner units issued during the period are included on a weighted-average basis for the days in which they were outstanding.

10

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 Ended
	March 31,
	2010			2009(1)
Net income attributable to Western Gas Partners, LP	$	22,914		$	20,586
Pre-acquisition (income) loss allocated to Parent		1,218			(3,628	)
General partner interest in net income		(483	)		(339	)
Limited partner interest in net income	$	23,649		$	16,619
Net income allocable to common units	$	13,741		$	8,728
Net income allocable to subordinated units		9,908			7,891
Limited partner interest in net income	$	23,649		$	16,619
Net income per limited partner unit — basic and diluted
Common units	$	0.37		$	0.30
Subordinated units	$	0.37		$	0.30
Total	$	0.37		$	0.30
Weighted average limited partner units outstanding — basic and diluted
Common units		36,803			29,093
Subordinated units		26,536			26,536
Total		63,339			55,629

⁽¹⁾  Financial information for 2009 has been revised to include results attributable to the Chipeta assets and Granger assets. SeeNote 1—Description of Business and Basis of Presentation—Acquisitions.

4. TRANSACTIONS WITH AFFILIATES

Affiliate transactions.The Partnership provides natural gas gathering, compression, processing, treating and transportation services to Anadarko and a portion of the Partnership’s expenditures are paid by or to Anadarko, which results in affiliate transactions. Except for volumes taken in-kind by certain producers, an affiliate of Anadarko sells the natural gas and extracted NGLs attributable to the Partnership’s processing activities, which also result in affiliate transactions. In addition, affiliate-based transactions also result from contributions to and distributions from Fort Union and Chipeta, which are paid or received by Anadarko.

Contribution of Partnership Assets to the Partnership.In January 2010, Anadarko contributed the Granger assets to the Partnership. In connection with the Granger acquisition, substantially all deferred tax liabilities attributable to the Granger assets were reversed and outstanding affiliate balances were entirely settled through an adjustment to parent net investment. SeeNote 1—Description of Business and Basis of Presentation.

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 January 1, 2010, with respect to the Granger assets, sales and purchases related to third-party transactions were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged the Partnership interest at a variable rate on outstanding affiliate balances attributable to such assets for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to parent net investment in connection with the Granger acquisition. Subsequent to January 1, 2010, with respect to the Granger assets, the Partnership cash-settles transactions directly with third parties and with Anadarko affiliates and affiliate-based interest expense on current intercompany balances is not charged.

11

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

Note receivable from Anadarko. Concurrent with the closing of the Partnership’s May 2008 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 $267.8 million and $271.3 million at March 31, 2010 and December 31, 2009, 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 in December 2008, 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 4.00% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points beginning on December 1, 2010.

Commodity price swap agreements. The Partnership entered into commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s keep-whole and percentage-of-proceeds contracts applicable to natural gas processing activities at the Hilight, Newcastle and Granger systems. Beginning on January 1, 2009, commodity price swap agreements were put in place to 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. The commodity price swap arrangements for the Hilight and Newcastle systems expire in December 2011 and the Partnership can extend the agreements, at its option, annually through December 2013. Beginning on January 1, 2010, commodity price swap agreements were put in place to fix the margin the Partnership will realize under both keep-whole and percentage-of-proceeds contracts applicable to natural gas processing activities at the Granger system. These commodity price swap arrangements for the Granger systems are in place through December 2014.

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 and the Granger system. 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, NGLs and condensate sales — affiliates in its consolidated statements of income in the period in which the associated revenues are recognized. During the three months ended March 31, 2010, the Partnership recorded realized losses of $1.5 million and, during the three months ended March 31, 2009, the Partnership recorded realized gains of $1.8 million attributable to the commodity price swap agreements.

Chipeta LLC Agreement. 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, as amended and restated as of July 23, 2009, together with Anadarko and the third-party member. 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 available cash, as defined in the Chipeta LLC Agreement, to its members quarterly in accordance with those members’ membership interests; and

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

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

Omnibus agreement. 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. The Partnership’s reimbursement to Anadarko for certain

12

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

general and administrative expenses allocated to the Partnership is capped at $8.3 million for the year ended December 31, 2010, 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. 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.

Services and secondment agreement.Pursuant to the services and secondment agreement, 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 extends through May 2018 and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination 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 the Partnership’s acquisition of the Partnership Assets.

Tax sharing agreement.Pursuant to a tax sharing agreement, 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 the Partnership’s acquisition of the Partnership Assets. 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.Prior to the Partnership’s acquisition of the Partnership Assets, the consolidated financial statements of the Partnership include costs allocated by Anadarko in the form of a management services fee, which approximated the general and administrative costs attributable to the Partnership Assets. This management services fee was allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues or other contractual arrangements. 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, 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. In general, the Partnership’s reimbursement to Anadarko under the omnibus agreement or services and secondment agreements is either (i) on an actual basis for direct expenses Anadarko incurs on behalf of the Partnership or (ii) based on an allocation of salaries and related employee benefits between the Partnership and Anadarko based on estimates of time spent on each entity’s business and affairs. The vast majority of direct general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, excluding any mark-up or subsidy charged or received by Anadarko. With respect to allocated costs, management believes that the allocation method employed by Anadarko is reasonable. While it is not practicable to determine what these direct and allocated costs would be on a stand-alone basis if the Partnership were to directly obtain these services, management believes these costs would be substantially the same.

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. Compensation expense attributable to the phantom units granted under the LTIP is recognized entirely by the Partnership over the vesting period and was approximately $73,000 and $123,000 for the three months ended March 31, 2010 and 2009, respectively.

13

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

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 Equity Incentive Plan (the “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”). The Partnership’s general and administrative expense for the three months ended March 31, 2010 and 2009 included approximately $567,000 and $846,000, respectively, of allocated 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.

Summary of affiliate transactions.Revenues from affiliates include amounts earned by the Partnership from the gathering, treating, processing and transportation of natural gas and NGLs for Anadarko, as well as from the sale of natural gas and NGLs to Anadarko. 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 necessarily those expenses attributable to generating affiliate revenues. The following table summarizes affiliate transactions.

	Three Months Ended
	March 31,
	2010		2009
	(in thousands)
Revenues — affiliates	$	83,830	$	79,964
Operating expenses — affiliates		23,081		24,105
Interest income — affiliates		4,225		4,462
Interest expense, net — affiliates		1,785		1,785
Distributions to unitholders — affiliates		12,239		10,786
Contributions from noncontrolling interest owners — affiliate and Parent		1,985		18,905
Distributions to noncontrolling interest owners — affiliate and Parent		1,375		—

5. CONCENTRATION OF CREDIT RISK

Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for the three months ended March 31, 2010 and 2009. The percentage of revenues from Anadarko and the Partnership’s other customers are as follows:

	Three Months Ended
	March 31,
Customer	2010			2009
Anadarko		87	%		88	%
Other		13	%		12	%
Total		100	%		100	%

14

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

6. PROPERTY, PLANT AND EQUIPMENT

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

	Estimated
	useful life		March 31, 2010		December 31, 2009
			(dollars in thousands)
Land		n/a	$	354	$	354
Gathering systems		5 to 39 years		1,154,328		1,149,550
Pipeline and equipment		30 to 34.5 years		86,650		86,617
Assets under construction		n/a		7,250		7,552
Other		3 to 25 years		2,082		2,082
Total property, plant and equipment				1,250,664		1,246,155
Accumulated depreciation				265,939		252,778
Total net property, plant and equipment			$	984,725	$	993,377

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.

7. DEBT

The Partnership’s outstanding debt as of March 31, 2010 consisted of the $210.0 million borrowed in January 2010 under the revolving credit facility in connection with the Granger acquisition and the $175.0 million note payable to Anadarko in 2013 issued in connection with the Powder River acquisition. The Partnership’s outstanding debt as of December 31, 2009 consisted solely of the $175.0 million note payable to Anadarko.

Anadarko’s credit facility. 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 such amounts remain available to Anadarko under the credit facility. As of March 31, 2010, the full $100.0 million was available for borrowing by the Partnership. Interest on borrowings under the credit facility is calculated based on, at the election by the borrower, 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 March 31, 2010, 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 March 31, 2010, 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 $0.1 million 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 65% or less. As of March 31, 2010, 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.

Working capital facility. In May 2008, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. At March 31, 2010, 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 pays 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.

Revolving credit facility. In October 2009, the Partnership entered into a three-year senior unsecured revolving credit facility with a group of banks (the “revolving credit facility”). The aggregate initial commitments of the lenders under the revolving credit facility are $350.0 million and are expandable to a maximum of $450.0 million. The revolving credit facility matures

15

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

in October 2012 and bears interest at LIBOR, plus applicable margins ranging from 2.375% to 3.250%. The interest rate was 2.62% at March 31, 2010. The Partnership is required to pay a quarterly facility fee ranging from 0.375% to 0.750% of the commitment amount (whether used or unused), based upon the Partnership’s consolidated leverage ratio, as defined in the revolving credit facility. The facility fee rate was 0.375% at March 31, 2010. In January 2010, the Partnership borrowed $210.0 million under the revolving credit facility in connection with the Granger acquisition. As of March 31, 2010, $140.0 million was available for borrowing by the Partnership.

The revolving credit facility contains various customary covenants, customary events of default and certain financial tests, including a maximum consolidated leverage ratio, as defined in the revolving credit facility, of 4.5 to 1.0 as of the end of each quarter and a minimum consolidated interest coverage ratio, as defined in the revolving credit facility, of 3.0 to 1.0 as of the end of each quarter. If the Partnership obtains two of the following three ratings: BBB- or better by Standard and Poor’s, Baa3 or better by Moody’s Investors Service or BBB- or better by Fitch Ratings Ltd., the Partnership will no longer be required to comply with the minimum consolidated interest coverage ratio as well as certain of the aforementioned covenants. As of March 31, 2010, the Partnership was in compliance with all covenants under the revolving credit facility.

Term loan agreement. 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 4.00% 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 in December 2010.

The provisions of the five-year 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 March 31, 2010, the Partnership was in compliance with all covenants under the five-year term loan agreement.

The fair value of the Partnership’s debt under the revolving credit facility and the five-year term loan agreement approximate the carrying value of those instruments at March 31, 2010 and December 31, 2009. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and quarter-end market rate.

Interest income and expense. The following table summarizes the amounts included in interest income, net.

	Three Months Ended
	March 31,
	2010		2009
	(in thousands)
Interest expense on note payable to Anadarko	$	1,750	$	1,750
Interest expense on borrowings under revolving credit facility – third parties		977		—
Revolving credit facility fees and amortization – third parties		766		—
Credit facility commitment fees – affiliates		35		35
Interest expense	$	3,528	$	1,785
Interest income on note receivable from Anadarko	$	4,225	$	4,225
Interest income, net on affiliates balances		—		237
Interest income, net – affiliates	$	4,225	$	4,462
Interest income, net	$	697	$	2,677

16

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

8. 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, has entered into lease agreements for corporate offices as well as compression equipment, a shared office and warehouse supporting the Granger assets. The lease for the corporate offices expires in January 2012, the leases for compression equipment include terms on a monthly basis and on a long-term basis expiring through January 2015 and the lease for the shared office expires in October 2011. The lease for the shared warehouse includes an early termination clause.

The amounts in the table below represent existing contractual lease obligations for the corporate offices, compression equipment and shared office leases as of March 31, 2010 that may be assigned or otherwise charged to the Partnership.

	Minimum rental payments
	(in thousands)
2010	$	727
2011		969
2012		799
2013		794
2014		311
Total	$	3,600

Rent expense associated with the above leases was approximately $314,000 and $209,000 for the three months ended March 31, 2010 and 2009, respectively.

9. SUBSEQUENT EVENT

On April 20, 2010, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.34 per unit, or $22.0 million in aggregate. The cash distribution is expected to be paid on May 12, 2010 to unitholders of record at the close of business on April 30, 2010.

10. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

As of May 6, 2010, the Partnership may issue up to $1.1 billion of limited partner common units and various debt securities under its effective shelf registration statement on file with the SEC. Debt securities issued under the shelf may be guaranteed by one or more existing or future subsidiaries of the Partnership (the “Guarantor Subsidiaries”), each of which is a wholly owned subsidiary of the Partnership. The guarantees, if issued, would be full, unconditional, joint and several. The following condensed consolidating financial information reflects the Partnership’s stand-alone accounts, the combined accounts of the Guarantor Subsidiaries, the accounts of the Non-Guarantor Subsidiary, consolidating adjustments and eliminations, and the Partnership’s consolidated statements of income and cash flows for the three months ended March 31, 2010 and 2009 and statements of financial position as of March 31, 2010 and December 31, 2009. The condensed consolidating financial information should be read in conjunction with the Partnership’s accompanying unaudited consolidated financial statements and related notes.

17

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

Western Gas Partners, LP’s and the Guarantor Subsidiaries’ investment in and equity income from their consolidated subsidiaries is presented in accordance with the equity method of accounting in which the equity income from consolidated subsidiaries includes the results of operations of the Partnership Assets for periods including and subsequent to the Partnership’s acquisition of the Partnership Assets.

Statement of Income	Three Months Ended March 31, 2010
	Western Gas
	Partners,			Guarantor		Non-Guarantor
	LP			Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues	$	(1,466	)	$	85,698	$	10,087	$	—		$	94,319
Operating expenses		4,502			58,546		6,223		—			69,271
Operating income (loss)		(5,968	)		27,152		3,864		—			25,048
Interest income, net		690			7		—		—			697
Other income, net		18			—		2		—			20
Equity income from consolidated subsidiaries		29,392			1,972		—		(31,364	)		—
Income before income taxes		24,132			29,131		3,866		(31,364	)		25,765
Income tax expense		—			957		—		—			957
Net income		24,132			28,174		3,866		(31,364	)		24,808
Net income attributable to noncontrolling interests		—			1,894		—		—			1,894
Net income attributable to Western Gas Partners, LP	$	24,132		$	26,280	$	3,866	$	(31,364	)	$	22,914

Statement of Income	Three Months Ended March 31, 2009
	Western Gas
	Partners,			Guarantor		Non-Guarantor
	LP			Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues	$	1,775		$	78,812	$	8,573	$	—		$	89,160
Operating expenses		4,401			60,242		4,210		—			68,853
Operating income (loss)		(2,626	)		18,570		4,363		—			20,307
Interest income, net		2,438			239		—		—			2,677
Other income, net		5			—		2		—			7
Equity income from consolidated subsidiaries		17,141			—		—		(17,141	)		—
Income before income taxes		16,958			18,809		4,365		(17,141	)		22,991
Income tax benefit		—			266		—		—			266
Net income		16,958			18,543		4,365		(17,141	)		22,725
Net income attributable to noncontrolling interests		—			2,139		—		—			2,139
Net income attributable to Western Gas Partners, LP	$	16,958		$	16,404	$	4,365	$	(17,141	)	$	20,586

18

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

Balance Sheet	As of March 31, 2010
	Western Gas
	Partners,		Guarantor		Non-Guarantor
	LP		Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Current assets	$	46,964	$	103,811	$	11,102	$	(92,064	)	$	69,813
Note receivable – Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		827,777		98,306		—		(926,083	)		—
Net property, plant and equipment		205		800,374		184,146		—			984,725
Other long-term assets		2,586		51,537		—		—			54,123
Total assets	$	1,137,532	$	1,054,028	$	195,248	$	(1,018,147	)	$	1,368,661
Current liabilities	$	92,993	$	22,965	$	2,985	$	(92,064	)	$	26,879
Long-term debt		385,000		—		—		—			385,000
Other long-term liabilities		234		13,280		2,258		—			15,772
Total liabilities		478,227		36,245		5,243		(92,064	)		427,651
Partners’ capital		659,305		926,083		190,005		(926,083	)		849,310
Noncontrolling interests		—		91,700		—		—			91,700
Total liabilities, equity and partners’ capital	$	1,137,532	$	1,054,028	$	195,248	$	(1,018,147	)	$	1,368,661

Balance Sheet	As of December 31, 2009
	Western Gas		Guarantor		Non-Guarantor
	Partners, LP		Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Current assets	$	64,001	$	58,772	$	9,425	$	(51,934	)	$	80,264
Note receivable – Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		497,997		98,959		—		(596,956	)		—
Net property, plant and equipment		219		808,952		184,206		—			993,377
Other long-term assets		2,974		51,308		—		—			54,282
Total assets	$	825,191	$	1,017,991	$	193,631	$	(648,890	)	$	1,387,923
Current liabilities	$	52,545	$	24,116	$	1,529	$	(51,934	)	$	26,256
Long-term debt		175,000		—		—		—			175,000
Other long-term liabilities		—		105,747		2,221		—			107,968
Total liabilities		227,545		129,863		3,750		(51,934	)		309,224
Partners’ capital and parent net investment		597,646		797,206		189,881		(596,956	)		987,777
Noncontrolling interests		—		90,922		—		—			90,922
Total liabilities, equity and partners’ capital	$	825,191	$	1,017,991	$	193,631	$	(648,890	)	$	1,387,923

19

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

Statement of Cash Flows

	Three Months Ended March 31, 2010
	Western Gas						Non-
	Partners,			Guarantor			Guarantor
	LP			Subsidiaries			Subsidiary			Eliminations			Consolidated
							(in thousands)
Cash flows from operating activities
Net income	$	24,132		$	28,174		$	3,866		$	(31,364	)	$	24,808
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(29,392	)		(1,972	)		—			31,364			—
Depreciation and amortization		14			12,240			1,429			—			13,683
Deferred income taxes		—			(621	)		—			—			(621	)
Change in other items, net		41,414			(37,893	)		1,520			—			5,041
Net cash provided by (used in) operating activities		36,168			(72	)		6,815			—			42,911
Cash flows from investing activities
Granger acquisition		(241,680	)		—			—			—			(241,680	)
Capital expenditures		—			(4,247	)		(1,050	)		—			(5,297	)
Net cash used in investing activities		(241,680	)		(4,247	)		(1,050	)		—			(246,977	)
Cash flows from financing activities
Borrowings under revolving credit facility, net of issuance costs		209,987			—			—			—			209,987
Contributions from noncontrolling interest owners and Parent		—			—			1,985			—			1,985
Distributions to unitholders		(21,393	)		—			—			—			(21,393	)
Distributions to noncontrolling interest owners and Parent		—			—			(5,727	)		2,921			(2,806	)
Net (distributions to) contributions from Parent		134			4,319			—			(2,921	)		1,532
Net cash provided by (used in) financing activities		188,728			4,319			(3,742	)		—			189,305
Net increase (decrease) in cash and cash equivalents		(16,784	)		—			2,023			—			(14,761	)
Cash and cash equivalents at beginning of period		61,632			—			8,352			—			69,984
Cash and cash equivalents at end of period	$	44,848		$	—		$	10,375		$	—		$	55,223

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

Statement of Cash Flows

	Three Months Ended March 31, 2009
	Western Gas						Non-
	Partners,			Guarantor			Guarantor
	LP			Subsidiaries			Subsidiary			Eliminations			Consolidated
							(in thousands)
Cash flows from operating activities
Net income	$	16,958		$	18,543		$	4,365		$	(17,141	)	$	22,725
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(17,141	)		—			—			17,141			—
Depreciation and amortization		14			11,379			623			—			12,016
Deferred income taxes		—			(689	)		—			—			(689	)
Change in other items, net		(76,683	)		60,468			(10,753	)		12,493			(14,475	)
Net cash provided by (used in) operating activities		(76,852	)		89,701			(5,765	)		12,493			19,577
Cash flows from investing activities
Capital expenditures		—			(11,594	)		(12,516	)		—			(24,110	)
Net cash used in investing activities		—			(11,594	)		(12,516	)		—			(24,110	)
Cash flows from financing activities
Contributions from noncontrolling interest owners and Parent		—			22,327			—			—			22,327
Distributions to unitholders		(17,029	)		—			—			—			(17,029	)
Net (distribution to) contribution from Parent		87,871			(100,434	)		22,327			(12,493	)		(2,729	)
Net cash provided by (used in) financing activities		70,842			(78,107	)		22,327			(12,493	)		2,569
Net increase (decrease) in cash and cash equivalents		(6,010	)		—			4,046			—			(1,964	)
Cash and cash equivalents at beginning of period		33,306			—			2,768			—			36,074
Cash and cash equivalents at end of period	$	27,296		$	—		$	6,814		$	—		$	34,110

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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 notes to unaudited consolidated financial statements, which are included under Part I, Item 1 of this quarterly report on 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 as filed with the Securities and Exchange Commission, or “SEC,” on March 11, 2010, as revised by our current report on Form 8-K, as filed with the SEC on May 4, 2010 (the “annual report on Form 10-K”) to, as discussed below, recast our financial statements to reflect the activities of the Granger assets from the date those assets were acquired by Anadarko Petroleum Corporation. 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 and “Parent” refers to Anadarko prior to our acquisition of assets from Anadarko. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership. We refer to Anadarko Gathering Company LLC, or “AGC,” Pinnacle Gas Treating LLC, or “PGT,” and MIGC LLC, or “MIGC,” all of which we acquired in connection with our May 2008 initial public offering, collectively as our “initial assets.” We refer to our 100% ownership interest in the Hilight system, 50% interest in the Newcastle system and 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C., or “Fort Union,” all of which we acquired from Anadarko in December 2008, collectively as the “Powder River assets” and to the acquisition as the “Powder River acquisition.” We refer to the 51% membership interest in Chipeta Processing LLC, or “Chipeta,” and associated natural gas liquids, or “NGL,” pipeline, which we acquired from Anadarko in July 2009, collectively as the “Chipeta assets” and to the acquisition as the “Chipeta acquisition.” We refer to the Granger gathering system and Granger complex, which we acquired from Anadarko in January 2010, collectively as the “Granger assets” and to the acquisition as the “Granger acquisition.” The Chipeta acquisition and Granger acquisition are described under the Acquisitions caption below.

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 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 the energy market;

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

• operating results;

• competitive conditions;

• technology;

• the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets;

• the supply of and 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;

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

• changes in the financial health of our sponsor, Anadarko;

• changes in Anadarko’s capital program, strategy or desired areas of focus;

• our commitments to capital projects;

• the ability to utilize our existing credit arrangements, including up to $100.0 million under Anadarko’s $1.3 billion credit facility, the $140.0 million available as of March 31, 2010 under our $350.0 million revolving credit facility and our $30.0 million working capital 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 onForm 10-K, this quarterly report onForm 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 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 and the Mid-Continent and are engaged in the business of gathering, compressing, treating, processing and transporting natural gas and NGLs for Anadarko and third-party producers and customers.

Significant operational and financial highlights during the first quarter of 2010 include the following:

• In January 2010, we acquired the Granger assets, which include a 750-mile gathering system with related compressors and other facilities, and the Granger complex which consists of two cryogenic trains, two refrigeration trains and ancillary equipment.

• Our stable operating cash flow, combined with a focus on cost reduction and capital spending discipline, enabled us to raise our distribution to $0.34 per unit for the first quarter of 2010, representing a 3% increase over the distribution for the fourth quarter of 2009 and our fourth consecutive quarterly increase. Our capital expenditures were relatively low during the first quarter of 2010 due to deferred timing of certain projects and reduced maintenance activity during the winter months.

• First-quarter gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged approximately $0.47 per Mcf, representing an approximate 21% increase compared to the first quarter of 2009. The increase in gross margin is primarily due to an increase in NGL market prices. The predominantly fee-based and fixed-price structure of our contracts at our other facilities neutralized the impact of changes in commodity prices on our gross margin.

• First-quarter throughput attributable to Western Gas Partners, LP totaled approximately 1,375 MMcf/d, representing an approximate 8% decrease compared to the first quarter of 2009. The throughput decrease for the three months ended March 31, 2010 is primarily due to lower volumes at the Pinnacle, Granger, Dew, Haley and Hugoton systems due to natural production declines and low drilling activity, partially offset by increased throughput at the Chipeta and MIGC systems.

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ACQUISITIONS

Chipeta Acquisition.In July 2009, we acquired a 51% membership interest in Chipeta, together with an associated NGL pipeline, from Anadarko. Chipeta owns a natural gas processing plant complex, which includes two 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 completed in April 2009. In November 2009, Chipeta closed its $9.1 million acquisition from a third party of a compressor station and processing plant, or the “Natural Buttes plant.” The Natural Buttes plant is located in Uintah County, Utah and provides up to 180 MMcf/d of incremental refrigeration processing capacity.

Granger Acquisition.In January 2010, we acquired the following assets from Anadarko: (i) the Granger gathering system, a 750-mile gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains with combined capacity of 200 MMcf/d, two refrigeration trains with combined capacity of 145 MMcf/d, an NGLs fractionation facility with capacity of 9,500 barrels per day, and ancillary equipment. In connection with the acquisition, we entered into five-year, fixed-price commodity swap agreements with Anadarko, which cover non-fee-based volumes processed at the Granger complex. The Granger acquisition was financed with $210.0 million of borrowings under the Partnership’s revolving credit facility plus $31.7 million of cash on hand, as well as through the issuance of 620,689 common units to Anadarko and 12,667 general partner units to our general partner.

Presentation of Partnership Acquisitions.For purposes of this quarterly report on Form 10-Q, the initial assets, Powder River assets, Chipeta assets and Granger assets are referred to collectively as the “Partnership Assets.” Unless otherwise noted, references to “periods prior to our acquisition of the Partnership Assets” and similar phrases refer to periods prior to May 2008, with respect to the initial assets, periods prior to December 2008, with respect to the Powder River assets, periods prior to July 2009, with respect to the Chipeta assets, and periods prior to January 2010, with respect to the Granger assets. Unless otherwise noted, references to “periods subsequent to our acquisition of the Partnership Assets” and similar phrases refer to periods including and subsequent to May 2008, with respect to the initial assets, periods including and subsequent to December 2008, with respect to the Powder River assets, periods including and subsequent to July 2009, with respect to the Chipeta assets, and periods including and subsequent to January 2010, with respect to the Granger assets.

Each acquisition of the Partnership Assets, except the Natural Buttes plant, was considered a transfer of net assets between entities under common control. As a result, after each acquisition of significant assets from Anadarko, we are required to revise our financial statements to include the activities of those assets as of the date of common control. Our historical financial statements for the three months ended March 31, 2009, which included the results attributable to the initial assets and Powder River assets, have been recast to reflect the results attributable to the Chipeta assets and the Granger assets as if the Partnership owned a 51% interest in Chipeta, the associated NGL pipeline and the Granger assets for all periods presented.

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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:

Granger affiliate contracts. Effective October 1, 2009, contracts covering a majority of the Granger assets’ affiliate throughput were converted from primarily keep-whole contracts into a 10-year fee-based arrangement.

Commodity price swap agreements. Our financial results for historical periods reflect commodity price changes, which, in turn, impact the financial results derived from our percent-of-proceeds and keep-whole processing contracts. In connection with the Granger acquisition, the Partnership entered into five-year commodity price swap agreements with Anadarko effective January 1, 2010 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Granger assets. SeeNote 4—Transactions with Affiliatesincluded in the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on Form 10-Q and seeNote 6—Transactions with Affiliates andNote 13—Subsequent Events—Granger acquisition of the notes to the consolidated financial statements included underPart II, Item 8of our annual report on Form 10-K.

Federal income taxes. We are generally not subject to federal or state income tax. Federal and state income tax expense was recorded for periods ending prior to January 29, 2010, with respect to income generated by our Granger assets. For periods including and subsequent to January 29, 2010, we are no longer subject to federal income tax, with respect to income generated by the Granger assets. 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.

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RESULTS OF OPERATIONS

OPERATING RESULTS

The following table and discussion presents a summary of our results of operations for the three months ended March 31, 2010 and 2009:

	Three Months Ended
	March 31,
	2010		2009(1)
	(in thousands)
Revenues
Gathering, processing and transportation of natural gas	$	43,359	$	43,334
Natural gas, natural gas liquids and condensate sales		48,852		43,632
Equity income and other, net		2,108		2,194
Total revenues		94,319		89,160
Operating expenses(2)
Cost of product		32,578		33,645
Operation and maintenance		15,167		14,086
General and administrative		5,074		6,285
Property and other taxes		2,769		2,821
Depreciation and amortization		13,683		12,016
Total operating expenses		69,271		68,853
Operating income		25,048		20,307
Interest income, net(3)		697		2,677
Other income, net		20		7
Income before income taxes		25,765		22,991
Income tax expense		957		266
Net income		24,808		22,725
Net income attributable to noncontrolling interests		1,894		2,139
Net income attributable to Western Gas Partners, LP	$	22,914	$	20,586
Key Performance Metrics(4)
Gross margin	$	61,741	$	55,515
Adjusted EBITDA		36,476		30,287
Distributable Cash Flow		33,282		26,995

(1)	Financial information for 2009 has been revised to include results attributable to the Chipeta assets and the Granger assets. SeeNote 1—Description of Business and Basis of Presentation—Acquisitionsincluded in the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on 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. SeeNote 4—Transactions with Affiliatesof the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on Form 10-Q.
(3)	Interest income, net represents interest income related to our $260.0 million note receivable from Anadarko, partially offset by interest expense paid under our term loan and credit facilities and pre-acquisition interest income (expense), net attributable to affiliate balances. SeeNote 4—Transactions with Affiliatesincluded in the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on Form 10-Q.
(4)	Gross margin, Adjusted EBITDA and distributable cash flow are defined below under the captionKey Performance Metricswithin thisPart I, Item 2.Such caption also includes reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable measures calculated and presented in accordance with GAAP.

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For purposes of the following discussion, any increases or decreases “for the three months ended March 31, 2010” refer to the comparison of the three months ended March 31, 2010 to the three months ended March 31, 2009.

Summary Financial Results. Natural gas, NGLs and condensate revenues increased by $5.2 million while gathering, processing and transportation revenue as well as equity income and other revenues remained flat. Net income attributable to Western Gas Partners, LP increased by approximately $2.3 million for the three months ended March 31, 2010 primarily due to the $5.2 million increase in revenues, a $1.1 million decrease in cost of product and a $1.2 million decrease in general and administrative expenses, partially offset by a $2.0 million decrease in interest income, net due to an increase in interest expense, a $1.7 million increase in depreciation expense and a $1.1 million increase in operation and maintenance expenses.

Operating Statistics

	Three Months Ended
	March 31,
	2010		2009		∆(1)
	(MMcf/d(2), except percentages)
Gathering and transportation throughput
Affiliates		700		782		(10	)%
Third parties		109		130		(16	)%
Total gathering and transportation throughput		809		912		(11	)%
Processing throughput(3)
Affiliates		491		436		13	%
Third parties		145		198		(27	)%
Total processing throughput		636		634		—	%
Equity investment throughput(4)		120		123		(2	)%
Total throughput		1,565		1,669		(6	)%
Throughput attributable to noncontrolling interest owners		190		175		9	%
Total throughput attributable to Western Gas Partners, LP		1,375		1,494		(8	)%

(1)	Represents the percentage change for the three months ended March 31, 2010.
(2)	All volumes are based on a standard pressure base of 14.73 pounds per square inch, absolute.
(3)	Includes 100% of Chipeta system volumes and 50% of Newcastle system volumes.
(4)	Represents the Partnership’s 14.81% share of Fort Union’s gross volumes.

Total throughput, which consists of affiliate, third-party and equity investment volumes, decreased by 104 MMcf/d for the three months ended March 31, 2010 and total throughput attributable to Western Gas Partners, LP, which excludes the noncontrolling interest owner’s proportionate share of Chipeta’s throughput, decreased by 119 MMcf/d for the three months ended March 31, 2010.

Affiliate gathering and transportation throughput decreased by 82 MMcf/d for the three months ended March 31, 2010 primarily due to throughput decreases at the Pinnacle, Dew and Haley systems resulting from natural production declines and reduced drilling activity in those areas, partially offset by affiliate throughput increases at the Chipeta plant due to completion of the cryogenic unit in April 2009 and affiliate throughput increases at the MIGC system due to a contract expiration which reallocated capacity from third parties to affiliates.

Third-party gathering and transportation throughput decreased by 21 MMcf/d for the three months ended March 31, 2010 primarily due to throughput decreases at the MIGC system resulting from a contract expiration which reallocated capacity

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from third parties to affiliates and throughput decreases at the Hugoton system due to natural production declines and reduced drilling activity.

Affiliate processing throughput increased by 55 MMcf/d for the three months ended March 31, 2010 primarily due to increased throughput at the Chipeta plant due to the completion of the cryogenic unit in April 2009 and increased throughput at the Granger complex due to well connections during 2009 and the first quarter of 2010. This increase was substantially offset by a 53 MMcf/d decrease in third-party processing throughput for the three months ended March 31, 2010 primarily at the Granger system due to one third-party producer redirecting volumes processed at the Granger system pursuant to month-to-month agreements to its own processing facility.

Equity investment volumes were relatively flat for the three months ended March 31, 2010.

Natural Gas Gathering, Processing and Transportation Revenues

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentages)
Gathering, processing and transportation of natural gas:
Affiliates	$	37,114	$	36,074		3	%
Third parties		6,245		7,260		(14	)%
Total	$	43,359	$	43,334		—

Total gathering, processing and transportation of natural gas revenues remained flat for the three months ended March 31, 2010. Revenues from affiliates increased by $1.0 million for the three months ended March 31, 2010 primarily due to an increase in Granger affiliate revenues resulting from contract changes that converted substantially all of the affiliate throughput at the Granger system from keep-whole contracts to a fee-based arrangement, slightly offset by a decrease in revenues at the Dew system due to natural production declines. Revenues from third parties decreased by $1.0 million for the three months ended March 31, 2010, primarily due to lower third-party throughput at the Granger system, substantially offsetting the increase in affiliate revenue.

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Natural Gas, Natural Gas Liquids and Condensate Sales

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentages
	and per-unit amounts)
Natural gas sales:
Affiliates	$	12,016	$	14,613		(18	)%
Third parties		4		—		nm	(1)
Total	$	12,020	$	14,613		(18	)%
Natural gas liquids sales:
Affiliates	$	33,143	$	27,547		20	%
Third parties		—		1		(100	)%
Total	$	33,143	$	27,548		20	%
Drip condensate sales — third parties	$	3,689	$	1,471		151	%
Total natural gas, natural gas liquids and condensate sales:
Affiliates	$	45,159	$	42,160		7	%
Third parties		3,693		1,472		151	%
Total	$	48,852	$	43,632		12	%
Average price per unit:
Natural gas (per Mcf)	$	5.15	$	3.59		43	%
Natural gas liquids (per Bbl)	$	37.84	$	25.96		46	%
Drip condensate (per Bbl)	$	69.82	$	30.77		127	%

⁽¹⁾ Percent change is not meaningful

Total natural gas, natural gas liquids and condensate sales increased by $5.2 million for the three months ended March 31, 2010, consisting of a $5.6 million increase in NGLs sales and a $2.2 million increase in drip condensate sales, partially offset by a $2.6 million decrease in natural gas sales. The average natural gas and NGLs prices for the three months ended March 31, 2010 include $1.5 million of losses from commodity price swap agreements for the Granger, Hilight and Newcastle systems and the average natural gas and NGLs prices for the three months ended March 31, 2009 include $1.8 million of gains from commodity price swap agreements for the Hilight and Newcastle systems.

The increase in NGLs sales was primarily due to a higher average NGLs sales price per barrel, reflecting the increase in market prices and higher fixed prices at the Hilight and Newcastle systems under the commodity price swap agreements. The fixed prices under the Hilight and Newcastle swap agreements were higher than the 2009 fixed prices but lower than 2010 market prices. The increase in NGLs sales attributable to improved pricing was partially offset by an approximate 200,000 Bbl, or 19%, decrease in the volume of NGLs sold for the three months ended March 31, 2010, primarily due to decreased NGLs volumes at the Granger plant resulting from a third-party redirecting their volumes to a third-party plant, offset by higher affiliate throughput due to affiliate drilling activity and well connections in the area.

The decrease in natural gas sales for the three months ended March 31, 2010 was primarily due to lower sales volumes, primarily at the Granger complex due as described above, partially offset by a 43% increase in average natural gas sales prices.

The increase in drip condensate sales was primarily due to increased average sales prices and volumes.

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Equity Income and Other Revenues

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentages)
Equity income — affiliate	$	1,340	$	1,550		(14	)%
Other revenues, net:
Affiliates		217		180		21	%
Third parties		551		464		19	%
Total equity income and other revenues, net	$	2,108	$	2,194		(4	)%

Total equity income and other revenues remained relatively flat for the three months ended March 31, 2010 as a $0.2 million decrease in equity income from our investment in Fort Union was substantially offset by a $0.1 million increase in other revenues.

Cost of Product and Operation and Maintenance Expenses

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentages
	and per-unit amounts)
Cost of product	$	32,578	$	33,645		(3	)%
Operation and maintenance		15,167		14,086		8	%
Total cost of product and operation and maintenance expenses	$	47,745	$	47,731		—
Cost of product — average price per unit:
Natural gas (per Mcf)	$	9.07	$	4.08		122	%
Natural gas liquids (per Bbl)	$	14.93	$	7.52		98	%
Drip condensate (per MMBtu)	$	5.20	$	3.35		55	%

Cost of product expense decreased by $1.1 million for the three months ended March 31, 2010 due to a $2.9 million decrease in fees paid by the Granger system for volumes gathered at adjacent gathering systems owned by Anadarko and a third party, then processed at Granger. Effective in October 2009, fees previously paid by Granger are paid directly by the producer to the other gathering system owners. The decrease in Granger gathering fees was partially offset by a $0.6 million increase from the higher cost of natural gas to compensate shippers on a thermally equivalent basis for drip condensate retained by us and sold to third parties, primarily due to higher market prices, as well as a $0.5 million increase in cost of product expense due to changes in gas imbalance positions and related gas prices. For the three months ended March 31, 2010, the cost of natural gas and NGLs we purchase from producers remained relatively flat as the impact of lower volumes was substantially offset by higher market prices. The volume of natural gas and NGLs purchased from producers decreased by 40% and 19%, respectively, for the three months ended March 31, 2010, primarily due to the aforementioned reduction in third-party throughput at the Granger system, partially offset by the increased purchases at the Chipeta plant due to actual liquid recoveries being less than contractually required recoveries as well as increased NGL recoveries at the Chipeta plant due to completion of the cryogenic unit in April 2009.

Operation and maintenance expense increased by $1.1 million for the three months ended March 31, 2010, primarily due to an increase in salaries, bonus and benefits, primarily attributable to direct field labor supporting the Granger assets.

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Key Performance Metrics

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentages
	and gross margin per Mcf)
Gross margin	$	61,741	$	55,515		11	%
Gross margin per Mcf(1)	$	0.44	$	0.37		19	%
Gross margin per Mcf attributable to Western Gas Partners, LP(2)	$	0.47	$	0.39		21	%
Adjusted EBITDA(3)		36,476		30,287		20	%
Distributable Cash Flow(3)		33,282		26,995		23	%

(1)	Calculated as gross margin (total revenues less cost of product) divided by total throughput, including 100% of gross margin and volumes attributable to Chipeta and the Partnership’s 14.81% interest in income and volumes attributable to the Fort Union. Calculating gross margin per Mcf separately for affiliates and third parties is not meaningful since a significant portion of throughput is delivered from third parties while the related residue gas and NGLs are sold to an affiliate.
(2)	Calculated as gross margin (total revenues less cost of product), excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product, divided by total throughput attributable to Western Gas Partners, LP. Calculation includes income and volumes attributable to the Partnership’s investment in Fort Union.
(3)	For a reconciliation of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read the descriptions below under the captionsAdjusted EBITDAandDistributable cash flow.

Gross margin increased by $6.2 million for the three months ended March 31, 2010, primarily due to the economics of our keep-whole contract arrangements at the Granger complex, in which the margin in NGL prices compared to the thermally equivalent gas price under the commodity price swaps for 2010 is more favorable than the margin realized in 2009 under market-based contracts. In addition, margins increased favorably at the Hilight system as the fixed prices on our commodity price swaps for 2010 are higher than the fixed prices on our commodity price swaps for 2009. Margins on drip condensate sales also improved due to the increase in NGLs prices relative to natural gas prices and increased volumes. These gross margin increases were partially offset by slightly lower gross margin at the Pinnacle and Dew systems resulting from lower revenues as well as lower margins at the MIGC system due to an increase in cost of product expense related to natural gas imbalances. The impact of the increase in market prices on our gross margin was neutralized by our fixed-price contract structure. Gross margin per Mcf increased by 19% for the three months ended March 31, 2010 and gross margin per Mcf attributable to Western Gas Partners, LP increased by 21% for the three months ended March 31, 2010, primarily due to higher margins at the Hilight and Granger systems, slightly offset by lower margins at the Chipeta system. Gross margin per Mcf attributable to Western Gas Partners, LP increased more compared to gross margin per Mcf, including 100% of Chipeta, as the gross margin per Mcf is lower at Chipeta than at most of our other systems.

Adjusted EBITDA.We define Adjusted EBITDA as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investee, non-cash equity-based compensation expense, expense in excess of the omnibus cap, interest expense, income tax expense, depreciation and amortization, less income from equity investments, interest income, income tax benefit and other income (expense).

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, commercial banks and rating agencies, use to assess the following, 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

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

Adjusted EBITDA increased by $6.2 million for the three months ended March 31, 2010, primarily due to a $5.4 million increase in total revenues, excluding equity income; a $1.1 million decrease in cost of product and a $0.9 million decrease in general and administrative expenses, excluding non-cash equity-based compensation; partially offset by a $1.1 million increase in operation and maintenance expenses.

Distributable cash flow.We define “distributable cash flow” as Adjusted EBITDA, plus interest income, less net cash paid for interest expense, maintenance capital expenditures, and income taxes. We believe distributable cash flow is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships. We also compare distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.

Distributable cash flow increased by $6.3 million for the three months ended March 31, 2010, primarily due to the $6.2 million increase in Adjusted EBITDA and a $1.8 million decrease in maintenance capital expenditures, partially offset by a $1.7 million increase in interest expense attributable to our $210.0 million of borrowings under the revolving credit facility in connection with the Granger acquisition as well as fees and amortization of the costs associated with the revolving credit facility.

Reconciliation to GAAP measures.Adjusted EBITDA and distributable cash flow are not defined in GAAP. The GAAP measures most directly comparable to Adjusted EBITDA are net income attributable to Western Gas Partners, LP and net cash provided by operating activities and the GAAP measure most directly comparable to distributable cash flow is net income attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net income attributable to Western Gas Partners, LP or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Furthermore, while distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period.

Management compensates for the limitations of Adjusted EBITDA and distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA and distributable cash flow compared to (as applicable) net income and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.

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The following tables present a reconciliation of (a) the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income attributable to Western Gas Partners, LP and net cash provided by operating activities and (b) a reconciliation of the non-GAAP financial measure of distributable cash flow to the GAAP financial measure of net income attributable to Western Gas Partners, LP (in thousands):

	Three Months Ended
	March 31,
	2010		2009(1)
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	36,476	$	30,287
Less:
Distributions from equity investee		1,111		1,111
Non-cash equity-based compensation expense		567		846
Interest expense, net		3,528		1,785
Income tax expense		957		266
Depreciation and amortization(2)		12,983		11,711
Add:
Equity income		1,340		1,550
Interest income, net — affiliates		4,225		4,462
Other income, net(2)		19		6
Net income attributable to Western Gas Partners, LP	$	22,914	$	20,586

	Three Months Ended
	March 31,
	2010			2009(1)
Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	36,476		$	30,287
Adjusted EBITDA attributable to noncontrolling interests		2,593			2,443
Interest income, net		697			2,677
Non-cash equity-based compensation expense		(567	)		(846	)
Current income tax benefit		(1,578	)		(955	)
Other income, net		20			7
Distributions from equity investee less than equity income		229			439
Changes in assets and liabilities:
Accounts receivable and natural gas imbalance receivable		(4,396	)		(7,475	)
Accounts payable, accrued liabilities and natural gas imbalance payable		9,124			(6,749	)
Other		313			(251	)
Net cash provided by operating activities	$	42,911		$	19,577

(1)	Financial information for 2009 has been revised to include results attributable to the Chipeta assets and the Granger assets. SeeNote 1—Description of Business and Basis of Presentation—Acquisitionsincluded in the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on Form 10-Q.
(2)	Includes the Partnership’s 51% share of depreciation and amortization expense and other income, net attributable to Chipeta.

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	Three Months Ended
	March 31,
	2010		2009(1)
	(in thousands)
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP
Distributable cash flow	$	33,282	$	26,995
Less:
Distributions from equity investee		1,111		1,111
Non-cash share-based compensation expense		567		846
Income tax expense		957		266
Depreciation and amortization (2)		12,983		11,711
Add:
Equity income		1,340		1,550
Cash paid for maintenance capital expenditures (2)		3,891		5,732
Interest income, net (non-cash settled)		—		237
Other income, net (2)		19		6
Net income attributable to Western Gas Partners, LP	$	22,914	$	20,586

(1)	Financial information for 2009 has been revised to include results attributable to the Chipeta assets and the Granger assets. SeeNote 1—Description of Business and Basis of Presentation—Acquisitionsincluded in the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on Form 10-Q.
(2)	Includes the Partnership’s 51% share of depreciation and amortization expense, cash paid for maintenance capital expenditures and other income, net attributable to Chipeta.

General and Administrative, Depreciation and Other Expenses

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentages)
General and administrative	$	5,074	$	6,285		(19	)%
Property and other taxes		2,769		2,821		(2	)%
Depreciation and amortization		13,683		12,016		14	%
Total general and administrative, depreciation and other expenses	$	21,526	$	21,122		2	%

General and administrative expenses decreased by $1.2 million for the three months ended March 31, 2010, due to the management fee allocated to the Granger assets during the three months ended March 31, 2009. The impact of this decrease on net income was offset by the increase in operation and maintenance expenses described previously. Depreciation and amortization expense increased by approximately $1.7 million for the three months ended March 31, 2010 primarily attributable to the expansion to the Chipeta plant completed in April 2009.

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Interest Income, Net

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentages)
Interest income on note receivable from Anadarko	$	4,225	$	4,225		—
Interest income, net on affiliate balances		—		237		(100	)%
Interest income, net — affiliates		4,225		4,462		(5	)%
Interest expense on note payable to Anadarko		1,750		1,750		—
Interest expense on borrowings under revolving credit facility — third parties		977		—		nm	(1)
Revolving credit facility fees and amortization — third parties		766		—		nm
Credit facility commitment fees — affiliates		35		35		—
Interest expense		3,528		1,785		98	%
Interest income, net	$	697	$	2,677		(74	)%

⁽¹⁾ Percent change is not meaningful

Interest income, net for the three months ended March 31, 2010, 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 December 2008 Powder River acquisition, the $210.0 million drawn on our revolving credit facility in connection with the January 2010 Granger acquisition, as well as commitment fees on our revolving credit facility, our $100.0 million portion of Anadarko’s $1.3 billion credit facility and our $30.0 million working capital facility. SeeNote 7— Debtincluded in the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on Form 10-Q. Interest income, net for the three months ended March 31, 2009 consisted of interest income on our $260.0 million note receivable from Anadarko and interest earned on affiliate balances, partially offset by interest on the $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.

Income Tax Expense

	Three Months Ended
	March 31,
	2010			2009			∆
	(in thousands, except percentages)
Income before income taxes	$	25,765		$	22,991			12	%
Income tax expense		957			266			260	%
Effective tax rate		4	%		1	%

Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, excluding the Granger assets, was subject only to Texas margin tax for the three months ended March 31, 2010 and March 31, 2009, respectively. Income attributable to the Granger assets prior to and including to January 2010, was subject only to federal income tax while income earned by the Granger assets for periods subsequent to January 2010 was subject only to Texas margin tax. For 2009 and 2010, the Partnership’s variance from the federal statutory rate is primarily attributable to the Partnership’s status as a non-taxable entity.

The increase in income tax expense for the three months ended March 31, 2010 is primarily related to the federal tax on the Granger assets as net income attributable to such assets for January 2010 was higher than net income attributable to such assets for the full three months ended March 31, 2009. This increase was partially offset by a $0.6 million income tax benefit recorded during the three months ended March 31, 2009 resulting from a decrease in the Partnership’s income attributable to Texas relative to the Partnership’s total income, excluding income related to the Chipeta assets and the Granger assets.

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Noncontrolling Interests

	Three Months Ended
	March 31,
	2010		2009		∆
	(in thousands, except percentage)
Net income attributable to noncontrolling interests	$	1,894	$	2,139		(11	)%

Net income attributable to noncontrolling interests decreased by $0.2 million for the three months ended March 31, 2010. Noncontrolling interests represent the aggregate 49% interest in Chipeta held by Anadarko and a third party. The decrease in net income attributable to noncontrolling interests for the three months ended March 31, 2010 is due to a decrease in the net income attributable to Chipeta resulting primarily from actual liquid recoveries being less than contractually required recoveries, while revenue remained virtually flat.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements, in addition to normal operating expenses, are for acquisitions and other capital expenditures, debt service, quarterly distributions to our limited partners and general partner and distributions to our noncontrolling interest owners. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please readItem 1A—Risk Factorsof our annual report on Form 10-K. Our sources of liquidity as of March 31, 2010 include:

• approximately $42.9 million of working capital as of March 31, 2010, which we define as the amount by which current assets exceed current liabilities;

• cash generated from operations, including interest income on our note receivable from Anadarko;

• available borrowing capacity of $140.0 million under our $350.0 million revolving credit facility, which is expandable to $450.0 million;

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

• available borrowing capacity 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 common and general partner 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.

In January 2010, we borrowed $210.0 million under our $350.0 million revolving credit facility in connection with the Granger acquisition. SeeNote 7 — Debtincluded in the notes to unaudited consolidated financial statements underItem 1of this quarterly report on Form 10-Q. Management continuously monitors the Partnership’s leverage position and coordinates its capital expenditure program, quarterly distributions and acquisition strategy with its expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or refinance outstanding revolving credit facility balances with longer-term notes. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statement which became effective with the SEC in August 2009.

Working capital. Working capital 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 the level and timing of our spending for maintenance and expansion activity.

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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 use over time, become obsolete or approached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput 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 throughput.

Total capital incurred for the three months ended March 31, 2010 and 2009 was $4.5 million and $23.4 million, respectively. Capital incurred is presented on an accrual basis. Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital expenditures for the three months ended March 31, 2010 and 2009 were $5.3 million and $24.1 million, respectively. Capital expenditures for the three months ended March 31, 2009 include $15.7 million attributable to the Chipeta assets prior to the Chipeta acquisition and include the noncontrolling interest owners’ share of Chipeta’s capital expenditures which were funded by contributions from the noncontrolling interest owners. Excluding the amounts paid for the Granger acquisition, expansion capital expenditures represented approximately 23% and 76% of total capital expenditures for the three months ended March 31, 2010 and 2009, respectively. We estimate our total capital expenditures, excluding any future acquisitions, to be $28 million to $32 million and our maintenance capital expenditures to be approximately 75% to 80% of total capital expenditures for the twelve months ending December 31, 2010. 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. We expect to fund future capital expenditures from cash flows generated from our operations, interest income from our note receivable from Anadarko, borrowings under our revolving credit facility or Anadarko’s credit facility, the issuance of additional partnership units or debt offerings.

Historical cash flow. The following table and discussion presents a summary of our net cash flows from operating activities, investing activities and financing activities for the three months ended March 31, 2010 and 2009.

	Three Months Ended
	March 31,
	2010			2009
	(in thousands)
Net cash provided by (used in):
Operating activities	$	42,911		$	19,577
Investing activities		(246,977	)		(24,110	)
Financing activities		189,305			2,569
Net increase in cash and cash equivalents	$	(14,761	)	$	(1,964	)

Operating Activities. Net cash provided by operating activities increased by $23.3 million for the three months ended March 31, 2010. This increase is primarily attributable to a $4.7 million favorable change in receivables and payables during the three months ended March 31, 2010 compared to a $14.2 million unfavorable change in receivables and payables during the three months ended March 31, 2009. In addition, cash provided by operating activities (a) increased by $5.4 million due to the increase in revenues, excluding equity income, (b) increased by $1.1 million due to the decrease in cost of product expense and (c) increased by $0.9 million due to the decrease in general and administrative expenses, excluding non-cash equity-based compensation. These increases were partially offset by a $1.3 million increase in interest expense settled in cash attributable to interest on borrowings under and fees on the revolving credit facility and a $1.1 million increase in operating and maintenance expenses as described inResults of Operations above.

Investing Activities. Net cash used in investing activities increased by $222.9 million for the three months ended March 31, 2010. Net cash used in investing activities for the three months ended March 31, 2010 includes $241.7 million attributable to the Granger acquisition. Capital expenditures for the three months ended March 31, 2010 decreased by $18.9 million. Capital expenditures for the three months ended March 31, 2009 include costs attributable to the Chipeta assets prior to the Chipeta acquisition and include the noncontrolling interest owners’ share of Chipeta’s capital expenditures. Excluding cash

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paid for the Granger acquisition, expansion capital expenditures decreased by $17.2 million, primarily due to the completion of the cryogenic unit at the Chipeta plant in April 2009. In addition, maintenance capital expenditures decreased by $1.7 million, primarily as a result of fewer well connections and the timing of maintenance projects.

Financing Activities. Net cash provided by financing activities increased by $186.7 million for the three months ended March 31, 2010, reflecting the $210.0 million in borrowings under our credit facility in connection with the Granger acquisition, partially offset by a $20.3 million decline in contributions from noncontrolling interest owners and Parent to Chipeta due to the completion of the cryogenic unit in April 2009. For the three months ended March 31, 2010 and 2009, we paid $21.4 million and $17.0 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners and Parent to Chipeta totaled $2.0 million and $22.3 million during the three months ended March 31, 2010 and 2009, respectively, primarily representing contributions for expansion of the cryogenic unit. Distributions from Chipeta to noncontrolling interest owners totaled $2.8 million for the three months ended March 31, 2010, representing the distribution for the fourth quarter of 2009. Net contributions from Parent were $1.5 million for the three months ended March 31, 2010, representing the net settlement of January 2010 income taxes and certain other transactions attributable to the Granger assets. Net distributions to Parent for the three months ended March 31, 2009 were $2.7 million, representing the net settlement of intercompany balances attributable to the Granger assets and the NGL pipeline connected to the Chipeta plant.

Distributions to unitholders. 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 three months ended March 31, 2010, we paid cash distributions to our unitholders of approximately $21.4 million, representing the $0.33 per-unit distribution for the quarter ended December 31, 2009. During the three months ended March 31, 2009, we paid cash distributions to our unitholders of approximately $17.0 million, representing the $0.30 per-unit distribution for the quarter ended December 31, 2008. On April 20, 2010, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.34 per unit, or $22.0 million in aggregate. The cash distribution is payable on May 12, 2010 to unitholders of record at the close of business on April 30, 2010.

Revolving credit facility.On October 29, 2009, we entered into a three-year senior unsecured revolving credit facility. The aggregate initial commitments of the lenders under this revolving credit facility are $350.0 million and are expandable to a maximum of $450.0 million. In January 2010, we borrowed $210.0 million under the revolving credit facility to partially fund the Granger acquisition. At March 31, 2010, $140.0 million was available for borrowing by us under the revolving credit facility. The revolving credit facility matures in October 2012 and bears interest at LIBOR plus applicable margins ranging from 2.375% to 3.250%. We are also required to pay a quarterly facility fee ranging from 0.375% to 0.750% of the commitment amount (whether used or unused), based upon our consolidated leverage ratio as defined in the revolving credit facility.

The revolving credit facility contains various customary covenants, customary events of default and certain financial tests, including a maximum consolidated leverage ratio, as defined in the revolving credit facility, of 4.5 to 1.0 as of the end of each quarter and a minimum consolidated interest coverage ratio, as defined in the revolving credit facility, of 3.0 to 1.0 as of the end of each quarter. If we obtain two of the following three ratings: BBB- or better by Standard and Poor’s, Baa3 or better by Moody’s Investors Service or BBB- or better by Fitch Ratings Ltd., we will no longer be required to comply with the minimum consolidated interest coverage ratio as well as certain of the aforementioned covenants. As of March 31, 2010, we were in compliance with all covenants under the revolving credit facility.

Anadarko’s credit facility. In March 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 such amounts remain available under the credit facility. At March 31, 2010, 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, at the election by the borrower, 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 March 31, 2010, 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 $0.1 million annually. Under Anadarko’s credit agreements, we and Anadarko are required to comply with certain

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covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. As of March 31, 2010, 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 in May 2008, we entered into a two-year, $30.0 million working capital facility with Anadarko as the lender. At March 31, 2010, 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.

Interest rate locks. In contemplation of refinancing existing borrowings under our revolving credit agreement, on April 30, 2010, we entered into agreements to lock fixed ten-year interest rates on potential note issuances with a combined notional principal amount of $95.0 million, effectively hedging the U.S. Treasury portion of the coupon rate on debt to be issued, if any. The interest rate locks expire on May 19, 2010. We have no firm obligation to issue such notes.

Registered securities. As of May 6, 2010, we may issue up to $1.1 billion of limited partner common units and various debt securities under our effective shelf registration statement on file with the SEC.

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 and monitor 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 and keep-whole contracts for the Hilight, Newcastle and Granger systems 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 agreement, as described inNote 4—Transactions with Affiliatesincluded in the notes to the unaudited consolidated financial statements included underPart I, Item 1of the quarterly report on Form 10-Q, our ability to make distributions to our unitholders may be adversely impacted.

Health Care Reform. In March 2010, the Patient Protection and Affordable Care Act, or “PPACA,” and the Health Care and Education Reconciliation Act of 2010, or “HCERA” and, together with PPACA, the “Acts,” which makes various amendments to certain aspects of the PPACA, were signed into law. The Acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, impose excise taxes on high-cost health plans, and provide for the phase-out of the Medicare Part D coverage gap. These changes are not expected to have a material impact on our financial statements.

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CONTRACTUAL OBLIGATIONS

Our contractual obligations include notes payable to Anadarko and credit facilities, for which information is provided inNote 7—Debt, included in the notes to unaudited consolidated financial statements included underPart I, Item 1of this quarterly report on Form 10-Q. Our contractual obligations also include a corporate office lease, compressor leases, warehouse lease and asset retirement obligations which have not changed significantly since December 31, 2009 and for which information is provided underManagement’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligationsin Exhibit 99.2 of our current report on Form 8-K, as filed with the SEC on May 4, 2010.

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 underManagement’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligationsin Exhibit 99.2 of our current report on Form 8-K, as filed with the SEC on May 4, 2010.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk.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 discount to the price of NYMEX West Texas Intermediate crude oil.

In addition, certain of our processing services are provided under percent-of-proceeds and keep-whole agreements in which Anadarko is typically responsible for the marketing of the natural gas and NGLs. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of natural gas and NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, we compensate the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. To mitigate our exposure to changes in commodity prices on these types of processing agreements, we entered into commodity price swap agreements with Anadarko with fixed commodity prices that extend through December 31, 2011, with an option to extend through 2013. In addition, to mitigate our exposure to changes in commodity prices on these types of processing agreements on the Granger assets we acquired in January 2010, we entered into commodity price swap agreements with Anadarko that extend through 2014. For additional information on the commodity price swap agreements, seeNote 4—Transactions with Affiliatesincluded in the notes to unaudited consolidated financial statements included underItem 1of this quarterly report on Form 10-Q as well asNote 6—Transactions with AffiliatesandNote 13—Subsequent Events—Granger acquisitionincluded in Exhibit 99.2 of our current report on Form 8-K, as filed with the SEC on May 4, 2010.

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 March 31, 2010, a 10% change in the margin between drip condensate and natural gas would have resulted in an approximate $1.1 million, or 5%, 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.

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Interest rate risk.If interest rates rise, our future financing costs will increase. Interest rates during 2009 and 2010 were low compared to historic rates. As of March 31, 2010, we had $210.0 million outstanding under our revolving credit facility, $140.0 million of credit available under our revolving credit facility, $100.0 million of credit available for borrowing under Anadarko’s five-year credit facility and $30.0 million available under our two-year working capital facility with Anadarko. Our borrowings, if any, under our revolving credit facility, Anadarko’s credit facility or our working capital facility bear interest at variable rates. In addition, as of March 31, 2010, we owed $175.0 million to Anadarko under our five-year term loan we entered into in connection with the Powder River acquisition which bears interest at a fixed rate of 4.0% until December 2011 and at a floating rate thereafter. For the three months ended March 31, 2010, a 10% change in LIBOR would have resulted in an insignificant change in interest expense for the period. SeeNote 7—Debtincluded in the notes to unaudited consolidated financial statements included inPart I, Item 1of this quarterly report on Form 10-Q.

We may incur additional debt in the future, either under the revolving credit facility, Anadarko’s existing credit facility, our $30.0 million working capital facility with Anadarko or other financing sources, including commercial bank borrowings or debt issuances.

Item 4. Controls and Procedures

Evaluation 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 Rule 13a-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures, as defined in Rule 13a-15(e) of the Exchange Act, were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Exchange Act 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 Exchange Act 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 March 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Partnership’s 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 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth in our annual report on Form 10-K for the year ended December 31, 2009 in addition to other information in such report and in this quarterly report on Form 10-Q. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Item 6. Exhibits

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

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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.

	WESTERN GAS PARTNERS, LP
Date: May 6, 2010	By:	/s/ Donald R. Sinclair
		Donald R. Sinclair
		President and Chief Executive Officer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)
Date: May 6, 2010	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)

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EXHIBIT INDEX

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

2.1	Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
2.2	Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 13, 2008, File No. 001-34046).
2.3	Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
2.4	Contribution Agreement, dated as of January 29, 2010, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Mountain Gas Resources LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
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	Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated July 22, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
3.6	Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated January 29, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
3.6	Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.7	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).
10.1	Amendment No. 3 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 31, 2009 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 7, 2010, File No. 001-34046).
10.2	Amendment No. 4 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of January 29, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
10.3*	Form of Commodity Price Swap Agreement.
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.