10-Q

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, 2011

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. Yes þ No o

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

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

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

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

          There were 54,889,781 common units outstanding as of April 30, 2011.

TABLE OF CONTENTS

PART I		FINANCIAL INFORMATION	Page
	Item 1.	Financial Statements
		Consolidated Statements of Income for the three months ended March 31, 2011 and 2010		3
		Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010		4
		Consolidated Statement of Equity and Partners’ Capital for the three months ended March 31, 2011		5
		Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010		6
		Notes to Unaudited Consolidated Financial Statements		7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
		Cautionary Note Regarding Forward-Looking Statements		24
		Executive Summary		25
		Acquisitions		26
		Equity Offerings		27
		Results of Operations		28
		Operating Results		28
		Liquidity and Capital Resources		37
		Contractual Obligations		41
		Off-Balance Sheet Arrangements		41
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		41
	Item 4.	Controls and Procedures		42
PART II		OTHER INFORMATION
	Item 1.	Legal Proceedings		42
	Item 1A.	Risk Factors		42
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		43
	Item 6.	Exhibits		43

1

DEFINITIONS

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

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

          Bcf/d: One billion cubic feet per day.

          Btu: British thermal unit; 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.

          Cryogenic: The fractionation process in which liquefied gases, such as liquid nitrogen or liquid helium, are used to bring volumes to very low temperatures (below approximately –238 degrees Fahrenheit) to separate natural gas liquids from natural gas. Through cryogenic processing, more natural gas liquids are extracted than when traditional refrigeration methods are used.

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

          Fractionation: The process of applying various levels of higher pressure and lower temperature to separate a stream of natural gas liquids into ethane, propane, normal butane, isobutane and natural gasoline.

          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.

          Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines 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. All volumes presented herein are based on a standard pressure base of 14.73 pounds per square inch, absolute.

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

2

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,
	2011			2010(1)
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	48,610		$	45,468
Natural gas, natural gas liquids and condensate sales		53,201			59,678
Equity income and other		2,708			1,598
Total revenues – affiliates		104,519			106,744
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		12,520			11,447
Natural gas, natural gas liquids and condensate sales		18,204			10,194
Other, net		750			551
Total revenues – third parties		31,474			22,192
Total revenues		135,993			128,936
Operating expenses (2)
Cost of product		46,820			41,973
Operation and maintenance		20,862			22,391
General and administrative		6,698			6,068
Property and other taxes		3,959			3,619
Depreciation, amortization and impairments		19,558			17,719
Total operating expenses		97,897			91,770
Operating income		38,096			37,166
Interest income – affiliates		4,225			4,230
Interest expense (3)		(6,111	)		(3,528	)
Other income (expense), net		1,760			20
Income before income taxes		37,970			37,888
Income tax expense		32			5,556
Net income		37,938			32,332
Net income attributable to noncontrolling interests		2,954			1,894
Net income attributable to Western Gas Partners, LP	$	34,984		$	30,438
Limited partner interest in net income:
Net income attributable to Western Gas Partners, LP	$	34,984		$	30,438
Pre-acquisition net income allocated to Parent		—			(6,306	)
General partner interest in net income (4)		(1,448	)		(483	)
Limited partner interest in net income (4)	$	33,536		$	23,649
Net income per common unit – basic and diluted	$	0.43		$	0.37
Net income per subordinated unit – basic and diluted	$	0.41		$	0.37
Net income per limited partner unit – basic and diluted	$	0.43		$	0.37

(1)	Financial information for 2010 has been revised to include results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1.
(2)	Operating expenses include amounts charged by Anadarko to the Partnership (“Anadarko” and “Partnership” are defined in Note 1) for services as well as reimbursement of amounts paid by Anadarko to third parties on behalf of the Partnership. Cost of product expenses include purchases from Anadarko of $15.5 million and $16.7 million for the three months ended March 31, 2011 and 2010, respectively. Operation and maintenance expenses include charges from Anadarko of $9.7 million and $11.6 million for the three months ended March 31, 2011 and 2010, respectively. General and administrative expenses include charges from Anadarko of $5.0 million and $4.5 million for the three months ended March 31, 2011 and 2010, respectively. See Note 4.
(3)	Interest expense includes affiliate interest expense of $1.2 million and $1.8 million for the three months ended March 31, 2011 and 2010, respectively. See Note 8.
(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 in Note 1). See also Note 3.

See accompanying notes to the unaudited consolidated financial statements.

3

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except number of units)

	March 31,		December 31,
	2011		2010
ASSETS
Current assets
Cash and cash equivalents	$	30,841	$	27,074
Accounts receivable, net – third parties		17,792		9,140
Accounts receivable, net – affiliates		1,335		1,750
Other current assets		5,875		5,220
Total current assets		55,843		43,184
Long-term assets
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		2,004,955		1,727,231
Less accumulated depreciation		386,565		367,881
Net property, plant and equipment		1,618,390		1,359,350
Goodwill and other intangible assets		115,546		60,236
Equity investments		40,109		40,406
Other assets		5,119		2,361
Total assets	$	2,095,007	$	1,765,537
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables – third parties	$	16,030	$	13,695
Accounts and natural gas imbalance payables – affiliates		1,112		1,480
Accrued ad valorem taxes		9,939		5,986
Income taxes payable		250		160
Accrued liabilities – third parties		19,760		20,280
Accrued liabilities – affiliates		264		593
Total current liabilities		47,355		42,194
Long-term liabilities
Long-term debt – third parties		470,000		299,000
Note payable – Anadarko		175,000		175,000
Deferred income taxes		676		733
Asset retirement obligations and other		60,079		43,542
Total long-term liabilities		705,755		518,275
Total liabilities		753,110		560,469
Commitments and contingencies (Note 9)
Equity and partners’ capital
Common units (54,889,781 and 51,036,968 units issued and outstanding at March 31, 2011 and December 31, 2010, respectively)		944,009		810,717
Subordinated units (26,536,306 units issued and outstanding at March 31, 2011 and December 31, 2010)		283,249		282,384
General partner units (1,661,757 and 1,583,128 units issued and outstanding at March 31, 2011 and December 31, 2010, respectively)		24,627		21,505
Total partners’ capital		1,251,885		1,114,606
Noncontrolling interests		90,012		90,462
Total equity and partners’ capital		1,341,897		1,205,068
Total liabilities, equity and partners’ capital	$	2,095,007	$	1,765,537

See accompanying notes to the unaudited consolidated financial statements.

4

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(unaudited, in thousands)

	Partners’ Capital
	Limited Partners						General			Noncontrolling
	Common			Subordinated			Partner			Interests			Total
Balance at December 31, 2010	$	810,717		$	282,384		$	21,505		$	90,462		$	1,205,068
Issuance of common and general partner units, net of offering expenses		130,032			—			2,764			—			132,796
Net income		22,587			10,949			1,448			2,954			37,938
Contributions from noncontrolling interest owners		—			—			—			960			960
Distributions to noncontrolling interest owners		—			—			—			(4,364	)		(4,364	)
Distributions to unitholders		(19,394	)		(10,084	)		(1,086	)		—			(30,564	)
Non-cash equity-based compensation and other		67			—			(4	)		—			63
Balance at March 31, 2011	$	944,009		$	283,249		$	24,627		$	90,012		$	1,341,897

See accompanying notes to the unaudited consolidated financial statements.

5

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	Three Months Ended
	March 31,
	2011			2010(1)
Cash flows from operating activities
Net income	$	37,938		$	32,332
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		19,558			17,719
Deferred income taxes		(58	)		(1,785	)
Changes in assets and liabilities:
Increase in accounts receivable, net		(8,251	)		(4,773	)
Increase in accounts and natural gas imbalance payables and accrued liabilities		5,887			9,729
Change in other items, net		(10	)		(763	)
Net cash provided by operating activities		55,064			52,459
Cash flows from investing activities
Capital expenditures		(13,923	)		(6,931	)
Acquisition from affiliates		—			(241,680	)
Acquisition from third parties		(303,602	)		—
Investments in equity affiliates		(93	)		—
Proceeds from sale of assets to affiliate		153			—
Net cash used in investing activities		(317,465	)		(248,611	)
Cash flows from financing activities
Borrowings under revolving credit facility, net of issuance costs		556,340			209,987
Repayments of revolving credit facility		(139,000	)		—
Repayment of Wattenberg term loan		(250,000	)		—
Proceeds from issuance of common and general partner units, net of $5.4 million in offering and other expenses		132,796			—
Distributions to unitholders		(30,564	)		(21,393	)
Contributions from noncontrolling interest owners		960			1,985
Distributions to noncontrolling interest owners		(4,364	)		(2,806	)
Net distributions to Parent		—			(6,382	)
Net cash provided by financing activities		266,168			181,391
Net increase (decrease) in cash and cash equivalents		3,767			(14,761	)
Cash and cash equivalents at beginning of period		27,074			69,984
Cash and cash equivalents at end of period	$	30,841		$	55,223
Supplemental disclosures
(Decrease) increase in accrued capital expenditures	$	(726	)	$	135
Interest paid	$	5,009		$	2,671
Interest received	$	4,225		$	4,225

⁽¹⁾ Financial information for 2010 has been revised to include results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1.

See accompanying notes to the unaudited consolidated financial statements.

6

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

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

          Description of business. Western Gas Partners, LP (the “Partnership”) is a Delaware limited partnership formed in August 2007. As of March 31, 2011, the Partnership’s assets included eleven gathering systems, six natural gas treating facilities, seven natural gas processing facilities, one natural gas liquids (“NGL”) pipeline, one interstate pipeline and noncontrolling interests in Fort Union Gas Gathering, L.L.C. (“Fort Union”) and White Cliffs Pipeline, L.L.C. (“White Cliffs”). The Partnership’s assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko Petroleum Corporation and its consolidated subsidiaries and third-party producers and customers.

          For purposes of these financial statements, the “Partnership” refers to Western Gas Partners, LP and its consolidated subsidiaries; “Anadarko” or “Parent” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner; and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and also refers to Fort Union and White Cliffs. The Partnership’s general partner is Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko.

          Basis of presentation. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with the accounting principles generally accepted in the United States. 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 Partnership records its 50% proportionate share of the assets, liabilities, revenues and expenses attributed to the Newcastle system.

          The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of financial position as of March 31, 2011 and December 31, 2010, results of operations for the three months ended March 31, 2011 and 2010, statement of equity and partners’ capital for the three months ended March 31, 2011 and statements of cash flows for the three months ended March 31, 2011 and 2010. The Partnership’s financial results for the three months ended March 31, 2011 are not necessarily indicative of the expected results for the full year ending December 31, 2011.

          The accompanying consolidated financial statements of the Partnership have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures normally included in annual financial statements have been condensed or omitted pursuant to those rules and regulations, although management believes that the disclosures made are adequate to make the information not misleading. 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 unaudited consolidated financial statements and notes should be read in conjunction with the Partnership’s annual report on Form 10-K, as filed with the SEC on February 24, 2011.

          Acquisitions. During 2010 and 2011, the Partnership completed the following acquisitions:

          Granger acquisition. In January 2010, the Partnership acquired certain midstream assets from Anadarko for (i) approximately $241.7 million in cash, which was financed primarily with a $210.0 million draw on the Partnership’s revolving credit facility and $31.7 million of cash on hand, as well as (ii) the issuance of 620,689 common units and 12,667 general partner units. The assets acquired include 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, a refrigeration train, an NGLs fractionation facility and ancillary equipment. These assets are referred to collectively as the “Granger assets” and the acquisition is referred to as the “Granger acquisition.”

7

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

          Wattenberg acquisition. In August 2010, the Partnership acquired certain midstream assets from Anadarko for (i) $473.1 million in cash, which was funded with $250.0 million of borrowings under a bank-syndicated unsecured term loan, $200.0 million of borrowings under the Partnership’s revolving credit facility and $23.1 million of cash on hand; as well as (ii) the issuance of 1,048,196 common units and 21,392 general partner units. The assets acquired represent a 100% ownership interest in Kerr-McGee Gathering LLC, which owns the Wattenberg gathering system and related facilities, including the Fort Lupton processing plant. These assets, located in the Denver-Julesburg Basin, north and east of Denver, Colorado, are referred to collectively as the “Wattenberg assets” and the acquisition as the “Wattenberg acquisition.”

          White Cliffs acquisition. In September 2010, the Partnership and Anadarko closed a series of related transactions through which the Partnership acquired a 10% member interest in White Cliffs. Specifically, the Partnership acquired Anadarko’s 100% ownership interest in Anadarko Wattenberg Company, LLC (“AWC”) for $20.0 million in cash (the “AWC acquisition”). AWC owned a 0.4% interest in White Cliffs and held an option to increase its interest in White Cliffs. Also, in a series of concurrent transactions, AWC acquired an additional 9.6% interest in White Cliffs from a third party for $18.0 million in cash, subject to post-closing adjustments. White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma and became operational in June 2009. The Partnership’s acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko and the acquisition of an additional 9.6% interest in White Cliffs were funded with cash on hand and are referred to collectively as the “White Cliffs acquisition.” The Partnership’s interest in White Cliffs is referred to as the “White Cliffs investment.”

          Platte Valley acquisition. On February 28, 2011, the Partnership acquired the Platte Valley gathering system and processing plant from a third party. These assets are located in the Denver-Julesburg Basin and consist of (i) a natural gas gathering system and related compression and other ancillary equipment; and (ii) cryogenic gas processing facilities. These assets are referred to collectively as the “Platte Valley assets” and the acquisition as the “Platte Valley acquisition.” The $303.6 million acquisition price was funded primarily by borrowings under the Partnership’s revolving credit facility.

          The Platte Valley acquisition is accounted for under the acquisition method of accounting. Under this method of accounting, the Partnership’s historical operating results for periods prior to the acquisition remain unchanged. At the date of the acquisition, the assets and liabilities of the Partnership continue to be recorded based upon their historical costs and the Platte Valley assets and liabilities are recorded at their estimated fair values. Results of operations attributable to the Platte Valley assets were included in the Partnership’s consolidated statement of income beginning on the acquisition date in the first quarter of 2011.

          The following is a preliminary allocation of the purchase price to the assets acquired and liabilities assumed in the Platte Valley acquisition as of the acquisition date (in thousands).

Property, plant and equipment	$	250,703
Other assets		13,818
Intangible assets		55,399
Asset retirement obligations and other liabilities		(16,318	)
Total purchase price	$	303,602

          The purchase price allocation is based on a preliminary assessment of the fair value of the assets acquired and liabilities assumed in the Platte Valley acquisition. The assessment of the fair values of the plant and processing facilities and related equipment acquired were based on market, cost and income approaches. The liabilities assumed include certain amounts associated with environmental contingencies estimated by management. The purchase price allocation is preliminary and is subject to change pending post-closing purchase price adjustments; finalizing fair value estimates; and completing evaluations of property, plant and equipment, intangible assets, asset retirement obligations, contractual arrangements and legal and environmental matters as additional information becomes available and is assessed by the Partnership.

8

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

          The following table presents the unaudited pro forma condensed financial information as if the Platte Valley acquisition occurred on January 1, 2011 (in thousands).

	Three Months
	Ended
	March 31, 2011
Revenues	$	152,032
Net income	$	40,517
Net income attributable to Western Gas Partners, LP	$	37,563
Earnings per limited partner unit – basic and diluted	$	0.46

          The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s pro forma information includes $9.2 million of revenues and $6.3 million of expenses attributable to the Platte Valley assets and included in the Partnership’s consolidated statement of income for the three-months ended March 31, 2011. The pro forma adjustments reflect pre-acquisition results of the Platte Valley assets for January and February 2011, including: (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the preliminary purchase price allocated to property, plant and equipment and other intangible assets and estimated useful lives; (c) elimination of $0.6 million of acquisition-related costs included in general and administrative expenses in the consolidated statement of income; and (d) interest on the Partnership’s $303.0 million of borrowings under its revolving credit facility to finance the Platte Valley acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the significant effects of the transactions are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the acquisition or any future acquisition related expenses. Pro forma information is not presented for periods ending on or before December 31, 2010 as it is not practical to determine revenues and cost of product for periods prior to January 1, 2011, the effective date of the gathering and processing agreement with the seller related to a majority of the throughput at the Platte Valley assets.

          Presentation of Partnership acquisitions. References to the “Partnership Assets” refer collectively to the assets owned by the Partnership as of March 31, 2011. Because of Anadarko’s control of the Partnership through its ownership of the general partner, each acquisition of Partnership Assets, except for the acquisitions of the Platte Valley assets and a 9.6% interest in White Cliffs, was considered a transfer of net assets between entities under common control. As a result, after each acquisition of assets from Anadarko, the Partnership is required to revise its financial statements to include the activities of the Partnership Assets as of the date of common control. Anadarko acquired the Wattenberg assets in connection with its August 10, 2006 acquisition of Kerr-McGee Corporation, and made its initial investment in White Cliffs on January 29, 2007.

          The Partnership’s historical financial statements for the three months ended March 31, 2010, as presented in the Partnership’s quarterly report on Form 10-Q for the quarter ended March 31, 2010, have been recast in this quarterly report on Form 10-Q to include the results attributable to the Wattenberg assets and the 0.4% interest in White Cliffs as if the Partnership owned such assets for all periods presented. Unless otherwise noted, references to “periods prior to our acquisition of the Partnership Assets” and similar phrases refer to periods prior to July 2010 with respect to the Wattenberg assets and periods prior to September 2010 with respect to the White Cliffs investment. References to “periods including and subsequent to our acquisition of the Partnership Assets” and similar phrases refer to periods including and subsequent to July 2010 with respect to the Wattenberg assets and periods including and subsequent to September 2010 with respect to the White Cliffs investment. 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 the unaudited consolidated financial statements of Western Gas Partners, LP

          Net income attributable to the Partnership Assets for periods prior to the Partnership’s acquisition of such assets is not allocated to the limited partners for purposes of calculating net income per limited partner unit. In addition, certain amounts in prior periods have been reclassified to conform to the current presentation. Specifically, during the quarter ended September 30, 2010, the Partnership revised its presentation to report the effects of commodity price swap agreements attributable to purchases in cost of product in its consolidated statements of income and net gains and losses on commodity price swap agreements related to purchases have been reclassified for all periods to conform to the current presentation. The following table presents the impact to the historical consolidated statements of income attributable to the Wattenberg assets and 0.4% interest in White Cliffs as well as the reclassification of the impact of commodity price swap agreements related to purchases (in thousands):

	Three Months Ended March 31, 2010
	Partnership		Wattenberg		White
	Historical		Assets		Cliffs		Reclassification			Combined
Revenues	$	94,319	$	35,037	$	40	$	(460	)	$	128,936
Net income		24,808		7,483		41		—			32,332

          Equity offerings. The Partnership completed the following public equity offerings during 2010 and 2011:

          May 2010 equity offering. In May and June 2010, the Partnership closed its equity offering of 4,558,700 common units to the public at a price of $22.25 per unit, including the issuance of 558,700 common units to the public pursuant to the exercise of the underwriters’ over-allotment option granted in connection with the equity offering. The May and June 2010 issuances are referred to collectively as the “May 2010 equity offering.” In connection with the May 2010 equity offering, the Partnership issued 93,035 general partner units to its general partner. Net proceeds from the offering of approximately $99.1 million, including the general partner’s proportionate capital contribution to maintain its 2.0% interest, and cash on hand were used to repay $100.0 million outstanding under the Partnership’s revolving credit facility.

          November 2010 equity offering. In November 2010, the Partnership closed a public offering of 8,415,000 common units at a price of $29.92 per unit, including the issuance of 915,000 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with that offering. The November 2010 issuances are referred to collectively as the “November 2010 equity offering.” In connection with the November 2010 equity offering, the Partnership issued 171,734 general partner units to its general partner, representing the general partner’s proportionate capital contribution to maintain its 2.0% interest. Net proceeds from the offering of approximately $246.7 million were primarily used to repay $246.0 million outstanding under the Partnership’s revolving credit facility.

          March 2011 equity offering. On March 4, 2011, the Partnership closed a public offering of 3,550,000 common units at a price of $35.15 per unit. On March 31, 2011, the Partnership issued an additional 302,813 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with that offering. The March 4, 2011 and March 31, 2011 issuances are referred to collectively as the “March 2011 equity offering.” In connection with the March 2011 equity offering, the Partnership issued 78,629 general partner units to its general partner in exchange for $2.8 million, representing the general partner’s proportionate capital contribution to maintain its 2.0% interest. Net proceeds from the offering of approximately $132.8 million were primarily used to repay amounts outstanding under the Partnership’s revolving credit facility.

          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, 2011 (in thousands):

	Limited Partner Units				General
	Common		Subordinated		Partner Units		Total
Balance at December 31, 2010		51,037		26,536		1,583		79,156
March 2011 equity offering		3,853		—		79		3,932
Balance at March 31, 2011		54,890		26,536		1,662		83,088

10

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

          Anadarko holdings of Partnership equity. As of March 31, 2011, Anadarko held 1,661,757 general partner units representing a 2% general partner interest in the Partnership, 100% of the Partnership’s IDRs, 10,302,631 common units and 26,536,306 subordinated units. Anadarko owned an aggregate 44.3% limited partner interest in the Partnership based on its holdings of common and subordinated units. The public held 44,587,150 common units, representing a 53.7% limited partner interest in the Partnership.

2. PARTNERSHIP DISTRIBUTIONS

          The partnership agreement requires that, within 45 days subsequent to the end of each quarter, the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. The Partnership declared the following cash distributions to its unitholders for the periods presented (in thousands, except per-unit data):

	Total Quarterly
	Distribution		Total Cash		Date of
Quarters Ended	per Unit		Distribution		Distribution
March 31, 2010	$	0.34	$	22,042	May 2010
March 31, 2011(1)	$	0.39	$	33,168	May 2011

⁽¹⁾ On April 19, 2011, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.39 per unit, or $33.2 million in aggregate, including incentive distributions. The cash distribution is payable on May 13, 2011 to unitholders of record at the close of business on April 29, 2011.

3. NET INCOME PER LIMITED PARTNER UNIT

          The Partnership’s net income 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 incentive distributions allocable to the general partner. 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. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner, common unitholders and subordinated unitholders consistent with actual cash distributions, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and subordinated unitholders in accordance with their respective ownership percentages during each period.

11

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

          Basic and diluted net income per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. The common units issued in connection with acquisitions and equity offerings during 2010 and 2011 are included on a weighted-average basis for periods they were outstanding. Management currently expects that the subordinated units will convert to common units on August 15, 2011. 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,
	2011			2010(1)
Net income attributable to Western Gas Partners, LP	$	34,984		$	30,438
Pre-acquisition net income allocated to Parent		—			(6,306	)
General partner interest in net income		(1,448	)		(483	)
Limited partner interest in net income	$	33,536		$	23,649
Net income allocable to common units	$	22,587		$	13,741
Net income allocable to subordinated units		10,949			9,908
Limited partner interest in net income	$	33,536		$	23,649
Net income per limited partner unit – basic and diluted
Common units	$	0.43		$	0.37
Subordinated units	$	0.41		$	0.37
Total limited partner units	$	0.43		$	0.37
Weighted average limited partner units outstanding – basic and diluted
Common units		52,145			36,803
Subordinated units		26,536			26,536
Total limited partner units		78,681			63,339

⁽¹⁾ Financial information for 2010 has been revised to include results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1—Description of Business and Basis of Presentation—Acquisitions.

4. TRANSACTIONS WITH AFFILIATES

          Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from midstream services provided to Anadarko as well as from the sale of residue gas, condensate and NGLs to Anadarko. A portion of the Partnership’s operating expenses are paid by Anadarko, which also results in affiliate transactions pursuant to the reimbursement provisions of the omnibus agreement described below. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operating expenses include all amounts accrued or paid to affiliates for the operation of the Partnership Assets, 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.

          Contribution of Partnership Assets. Effective in January 2010, Anadarko contributed the Granger assets to the Partnership, in July 2010 Anadarko contributed the Wattenberg assets to the Partnership, and in September 2010 Anadarko sold AWC, including its 0.4% interest in White Cliffs, to the Partnership. See Note 1—Description of Business and Basis of Presentation—Acquisitions.

          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 our acquisition of the Partnership Assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged or credited the Partnership interest at a variable rate on outstanding affiliate balances 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 acquisition of the Partnership Assets. Subsequent to our acquisition of the Partnership Assets, the Partnership cash-settles transactions related to such assets directly with third parties and with Anadarko affiliates and affiliate-based interest expense on current intercompany balances is not charged.

12

Notes to the 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 $262.4 million and $258.9 million at March 31, 2011 and December 31, 2010, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest 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. The interest rate was fixed at 4.00% through November 2010 and is fixed at 2.82% thereafter. See Note 8—Debt and Interest Expense—Note payable to Anadarko for additional information.

          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 purchase and sale of natural gas, condensate or NGLs. Below is a summary of the periods over which the Partnership’s commodity swap agreements are effective for each asset or system.

Assets	Effective	Expiration
Hilight and Newcastle systems (1)	January 2009	December 2012
Granger assets	January 2010	December 2014
Wattenberg assets	July 2010	June 2015
Hugoton system (2)	October 2010	September 2015

(1)	The Partnership is able to extend the agreements, at its option, annually through December 2013.
(2)	These commodity price swap agreements are only associated with condensate and natural gas sales and purchases.

          Below is a summary of the fixed price ranges on the Partnership’s commodity price swap agreements outstanding as of March 31, 2011.

	Year Ending December 31,
	2011		2012		2013		2014		2015
	(per barrel)
Ethane	$	17.95 -   29.31	$	18.21 -   29.78	$	18.32 -   30.10	$	18.36 -   30.53	$	18.41
Propane	$	44.25 -   50.07	$	45.23 -   53.28	$	45.90 -   51.56	$	46.47 -   52.37	$	47.08
Isobutane	$	58.18 -   66.03	$	57.50 -   67.22	$	60.44 -   68.11	$	61.24 -   69.23	$	62.09
Normal butane	$	51.25 -   61.82	$	52.40 -   62.92	$	53.20 -   63.74	$	53.89 -   64.78	$	54.62
Natural gasoline	$	68.19 -   75.99	$	69.77 -   85.15	$	70.89 -   78.42	$	71.85 -   79.74	$	72.88
Condensate	$	68.87 -   75.33	$	72.73 -   78.52	$	74.04 -   78.07	$	75.22 -   79.56	$	76.47 -    78.61
	(per MMbtu)
Natural gas	$	4.12 -   5.94	$	4.15 -   5.97	$	5.14 -   6.09	$	5.32 -   6.20	$	5.50 -   5.96

13

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

          Notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold at the Hilight, Hugoton, Newcastle, Granger and Wattenberg assets. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument at inception and, therefore, are not required to be measured at fair value. The Partnership reports its realized gains and losses on the commodity price swap agreements related to sales in natural gas, natural gas liquids and condensate sales in its consolidated statements of income in the period in which the associated revenues are recognized. The Partnership reports its realized gains and losses on the commodity price swap agreements related to purchases in cost of product in its consolidated statements of income in the period in which the associated purchases are recorded. The following table summarizes gains and losses on commodity price swap agreements (in thousands):

	Three Months Ended
	March 31,
	2011			2010
Gains (losses) on commodity price swap agreements:
Natural gas sales	$	6,808		$	275
Natural gas liquids sales		(5,841	)		(2,201	)
Gains (losses), net on commodity price swap agreements related to sales		967			(1,926	)
Gains (losses), net on commodity price swap agreements related to purchases		(6,206	)		460
Gains (losses), net on commodity price swap agreements	$	(5,239	)	$	(1,466	)

          Chipeta LLC agreement. In connection with the Partnership’s acquisition of its 51% membership interest in Chipeta Processing LLC (“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.

          Gas gathering and processing agreements. The Partnership has significant gas gathering and/or processing arrangements with affiliates of Anadarko on all of its systems, with the exception of the Platte Valley, Hilight and Newcastle systems. Approximately 80% of the Partnership’s gathering and transportation throughput for both the three months ended March 31, 2011 and 2010 was attributable to natural gas production owned or controlled by Anadarko. Approximately 74% and 77% of the Partnership’s processing throughput for the three months ended March 31, 2011 and 2010, respectively, was attributable to natural gas production owned or controlled by Anadarko.

          Gas purchase and sale agreements. The Partnership sells substantially all of its natural gas, NGLs and condensate to Anadarko Energy Services Company (“AESC”), Anadarko’s marketing affiliate. In addition, the Partnership purchases natural gas from AESC pursuant to gas purchase agreements. The Partnership’s gas purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal.

          Omnibus agreement. Pursuant to the omnibus agreement, Anadarko and the general partner perform 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 general and administrative expenses allocated to the Partnership was capped at $9.0 million for the year ended December 31, 2010. The cap under the omnibus agreement expired on December 31, 2010. For the year ending December 31, 2011 and thereafter, Anadarko, in accordance with the partnership agreement and omnibus agreement, will determine in its reasonable discretion amounts to be allocated to the Partnership in exchange for services provided under the omnibus agreement.

          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.

14

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

          Tax sharing agreement. Pursuant to a tax sharing agreement, the Partnership reimburses Anadarko for the Partnership’s estimated share of non-U.S. federal taxes borne by Anadarko on behalf of the Partnership as a result of the Partnership’s results being included in a combined or consolidated tax return filed by Anadarko with respect to periods including and 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. Nevertheless, the Partnership is required to reimburse Anadarko for its estimated share of non-U.S. federal 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 and the general partner incur on behalf of the Partnership or (ii) based on an allocation of salaries and related employee benefits between the Partnership, the general partner 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.

          Long-term incentive plan. The general partner awarded phantom units primarily to the general partner’s independent directors under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”), in May 2010 and 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 $0.1 million for both the three months ended March 31, 2011 and 2010. There was no LTIP award activity for the three months ended March 31, 2011 or 2010.

          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 as amended and restated (“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, 2011 and 2010 included approximately $2.0 million and $0.9 million, respectively, of equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans 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 services and secondment agreement. These amounts exclude compensation expense associated with the LTIP.

15

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

          Summary of affiliate transactions. As described above, affiliate transactions include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas. The following table summarizes affiliate transactions, including transactions with the general partner (in thousands):

	Three Months Ended
	March 31,
	2011		2010
Revenues	$	104,519	$	106,744
Operating expenses		30,179		32,715
Interest income		4,225		4,230
Interest expense		1,234		1,785
Distributions to unitholders		15,085		12,239
Contributions from noncontrolling interest owners		960		1,985
Distributions to noncontrolling interest owners		3,014		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, 2011 and 2010. The percentage of revenues from Anadarko and the Partnership’s other customers are as follows:

	Three Months Ended
	March 31,
	2011			2010
Anadarko		75	%		82	%
Other customers		25	%		18	%
Total		100	%		100	%

6. PROPERTY, PLANT AND EQUIPMENT

          A summary of the historical cost of the Partnership’s property, plant and equipment is as follows (dollars in thousands):

	Estimated
	useful life		March 31, 2011		December 31, 2010
Land		n/a	$	354	$	354
Gathering systems		5 to 39 years		1,896,376		1,621,633
Pipelines and equipment		30 to 34.5 years		83,653		83,613
Assets under construction		n/a		21,774		18,928
Other		3 to 25 years		2,798		2,703
Total property, plant and equipment				2,004,955		1,727,231
Accumulated depreciation				386,565		367,881
Total net property, plant and equipment			$	1,618,390	$	1,359,350

          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. In addition, property, plant and equipment cost as well as accrued liabilities – third parties balances in the Partnership’s consolidated balance sheets include $4.8 million and $5.5 million of accrued capital as of March 31, 2011 and December 31, 2010, respectively, representing estimated capital expenditures for which invoices had not yet been processed.

16

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

7. GOODWILL AND OTHER INTANGIBLE ASSETS

          Goodwill. The Partnership’s consolidated balance sheets as of March 31, 2011 and December 31, 2010 include goodwill of $60.2 million. Goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the assets the Partnership has acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s goodwill balance does not reflect, and in some cases is significantly higher than, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of the net assets on the acquisition date. None of the Partnership’s goodwill is deductible for tax purposes. No goodwill impairment has been recognized in these unaudited consolidated financial statements.

          Other intangible assets. Intangible assets represent the estimated economic value assigned to certain contracts entered into or assumed in connection with the Platte Valley acquisition in February 2011. The value assigned to customer contracts primarily consists of the estimated economic value related to the contracts assumed by the Partnership that dedicate certain customers’ field production to the acquired gathering and processing system. These contracts ensure an extended commercial relationship with the existing customers and provide the Partnership with a high probability of additional production from the customers’ acreage. However, these contracts are generally limited by the quantity and production life of the underlying natural gas resource base.

          At March 31, 2011, the carrying value of the Partnership’s customer relationship intangible assets was $55.3 million, net of $89,000 of accumulated amortization, and is included in goodwill and other intangible assets in the Partnership’s consolidated balance sheets. Customer relationships are amortized on a straight-line basis over 50 years, which is the estimated productive life of the reserves covered by the underlying acreage ultimately expected to be produced and gathered or processed through the Partnership’s assets subject to current contractual arrangements. Estimated future amortization for these intangible assets is as follows (in thousands):

	Future
	amortization
April - December 2011	$	835
2012		1,108
2013		1,108
2014		1,108
2015		1,108

          The Partnership assesses intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense. A reduction of the carrying value of intangible assets would represent a Level 3 fair value measure.

17

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

8. DEBT AND INTEREST EXPENSE

          The following table presents the Partnership’s outstanding debt as of March 31, 2011 and December 31, 2010 (in thousands):

	March 31, 2011		December 31, 2010
Revolving credit facility	$	470,000	$	49,000
Wattenberg term loan		—		250,000
Note payable to Anadarko		175,000		175,000
Total debt outstanding	$	645,000	$	474,000

          The following table presents the debt activity of the Partnership for the three months ended March 31, 2011 (in thousands):

	Principal
Balance as of December 31, 2010	$	474,000
Borrowings under revolving credit facility		560,000
Repayments under revolving credit facility		(139,000	)
Repayment of Wattenberg term loan		(250,000	)
Borrowing under revolving credit facility – Swingline		10,000
Repayment under revolving credit facility – Swingline		(10,000	)
Balance as of March 31, 2011	$	645,000

          Note payable to Anadarko. 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 was fixed at 4.00% until November 2010. The term loan agreement was amended in December 2010 to fix the interest rate at 2.82% through maturity of the note in 2013. The Partnership has the option, at any time, to repay the outstanding principal amount in whole or in part.

          The provisions of the five-year term loan agreement contain customary events of default, including (i) non-payment of principal when due or non-payment of interest or other amounts within three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to the Partnership and (iii) a change of control. At March 31, 2011, the Partnership was in compliance with all covenants under the five-year term loan agreement.

          Revolving credit facility. In March 2011, the Partnership entered into an amended and restated $800.0 million senior unsecured revolving credit facility (the “revolving credit facility”) and borrowed $250.0 million under the revolving credit facility to repay the Wattenberg term loan (described below). The revolving credit facility amended and restated the Partnership’s $450.0 million credit facility, which was originally entered into in October 2009. The revolving credit facility matures in March 2016 and bears interest at London Interbank Offered Rate, or “LIBOR,” plus applicable margins ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 0.30% to 0.90%. The interest rate was 1.95% at March 31, 2011. The Partnership is required to pay a quarterly facility fee ranging from 0.20% to 0.35% 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 0.30% at March 31, 2011.

          The revolving credit facility contains covenants that limit, among other things, the ability of the Partnership and certain of its subsidiaries to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of the Partnership’s assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The revolving credit facility also contains various customary covenants, customary events of default and certain financial tests as of the end of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to consolidated EBITDA for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions,

18

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

and a minimum consolidated interest coverage ratio (which is defined as the ratio of consolidated EBITDA for the most recent four consecutive fiscal quarters to consolidated interest expense for such period) of 2.0 to 1.0. All amounts due under the revolving credit facility are unconditionally guaranteed by our wholly owned subsidiaries. The Partnership will no longer be required to comply with the minimum consolidated interest coverage ratio as well as the subsidiary guarantees and certain of the aforementioned covenants, 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. As of March 31, 2011, $470.0 million was outstanding under the revolving credit facility, $330.0 million was available for borrowing and the Partnership was in compliance with all covenants thereunder.

          Wattenberg term loan. In connection with the Wattenberg acquisition, in August 2010 the Partnership borrowed $250.0 million under a three-year term loan from a group of banks (“Wattenberg term loan”). The Wattenberg term loan incurred interest at LIBOR plus a margin ranging from 2.50% to 3.50% depending on the Partnership’s consolidated leverage ratio as defined in the Wattenberg term loan agreement. The Partnership repaid the Wattenberg term loan in March 2011 using borrowings from its revolving credit facility and recognized $1.3 million of accelerated amortization expense related to the early repayment of the loan.

          Fair value of debt. The fair value of the Partnership’s debt under the revolving credit facility and the five-year term loan agreement approximates the carrying value of those instruments at March 31, 2011 and December 31, 2010. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and quarter-end market interest rate.

          Interest-rate swap agreement. The Partnership entered into a forward-starting interest-rate swap agreement in March 2011 to mitigate the risk of rising interest rates on existing variable-rate debt expected to be refinanced during 2011. Pursuant to the agreement, the Partnership will pay a fixed interest rate of 2.32% and receive three-month LIBOR on $150.0 million notional amount from May 2011 to May 2016. The swap agreement includes a provision that requires the termination of the swap at the start of the reference period. The Partnership does not apply hedge accounting to its interest-rate swap agreements. The fair value of the swap agreement was a $1.7 million gain on March 31, 2011, based on Level 2 fair value inputs. Such amount is included in other income, net in the unaudited consolidated income statement and other current assets in the unaudited consolidated balance sheet.

          Interest expense. The following table summarizes the amounts included in interest expense (in thousands):

	Three Months Ended
	March 31,
	2011		2010
Third parties
Interest expense on revolving credit facility and Wattenberg term loan	$	2,676	$	977
Amortization of debt issuance costs and commitment fees		2,201		766
Total interest expense – third parties		4,877		1,743
Affiliates
Interest expense on notes payable to Anadarko		1,234		1,750
Credit facility commitment fees		—		35
Total interest expense – affiliates		1,234		1,785
Interest expense	$	6,111	$	3,528

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

9. COMMITMENTS AND CONTINGENCIES

          Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state and local laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As of March 31, 2011, the Partnership’s consolidated balance sheet included a $0.9 million current liability and a $2.4 million long-term liability for remediation and reclamation obligations, included in Accrued liabilities — third parties and Asset retirement obligations and other, respectively. As of December 31, 2010, the Partnership’s consolidated balance sheet included a $0.4 million current liability and a $0.5 million long-term liability for remediation and reclamation obligations. The recorded obligations do not include any anticipated insurance recoveries. Substantially all of the payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes the Partnership’s recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership’s overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered.

          Litigation and legal proceedings. On March 1, 2011, DCP Midstream LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering LLC, in Weld County District Court in Colorado, alleging that Anadarko and its affiliates diverted gas from DCP’s gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering LLC, the entity which holds the Wattenberg assets. Management does not believe the outcome of this proceeding will have a material effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership intends to vigorously defend this litigation. Furthermore, without regard to the merit of DCP’s claims, management believes that the Partnership has adequate contractual indemnities covering the claims against it in this lawsuit.

          In addition, 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 condition.

          Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations. The lease for the corporate offices expires in January 2012, with no purchase option at termination, and the leases for the shared offices extend through 2014. The lease for the warehouse extends through September 2011 and includes an early termination clause. In addition, during 2010, Anadarko and Kerr-McGee Gathering LLC purchased previously leased compression equipment used at the Granger and Wattenberg assets, which terminated the leases and associated lease expense. The purchased compression equipment was contributed to the Partnership pursuant to provisions of the contribution agreements for the Granger acquisition and the Wattenberg acquisition.

          As of March 31, 2011, there was no material change in the existing contractual lease obligations for the office and warehouse leases from December 31, 2010. Rent expense associated with these leases and the previously leased compression equipment was approximately $0.4 million and $2.1 million for the three months ended March 31, 2011 and 2010, respectively.

10. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

          As of March 31, 2011, the Partnership may issue up to approximately $635.8 million of additional 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 unaudited 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 financial information. The unaudited condensed consolidating financial information should be read in conjunction with the Partnership’s accompanying consolidated financial statements and related notes.

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Notes to the 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 are 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.

	Three Months Ended March 31, 2011
	Western					Non-
	Gas			Guarantor		Guarantor
Statement of Income	Partners, LP			Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues	$	967		$	122,233	$	12,793	$	—		$	135,993
Operating expenses		12,613			78,517		6,767		—			97,897
Operating income (loss)		(11,646	)		43,716		6,026		—			38,096
Interest income – affiliates		4,215			10		—		—			4,225
Interest expense		(6,111	)		—		—		—			(6,111	)
Other income, net		1,749			9		2		—			1,760
Equity income from consolidated subsidiaries		46,777			3,074		—		(49,851	)		—
Income before income taxes		34,984			46,809		6,028		(49,851	)		37,970
Income tax expense		—			32		—		—			32
Net income		34,984			46,777		6,028		(49,851	)		37,938
Net income attributable to noncontrolling interests		—			2,954		—		—			2,954
Net income attributable to Western Gas Partners, LP	$	34,984		$	43,823	$	6,028	$	(49,851	)	$	34,984

	Three Months Ended March 31, 2010
	Western					Non-
	Gas			Guarantor		Guarantor
Statement of Income	Partners, LP			Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues	$	(1,926	)	$	120,775	$	10,087	$	—		$	128,936
Operating expenses		4,043			81,504		6,223		—			91,770
Operating income (loss)		(5,969	)		39,271		3,864		—			37,166
Interest income – affiliates		4,219			11		—		—			4,230
Interest expense		(3,528	)		—		—		—			(3,528	)
Other income, net		18			—		2		—			20
Equity income from consolidated subsidiaries		29,392			1,972		—		(31,364	)		—
Income before income taxes		24,132			41,254		3,866		(31,364	)		37,888
Income tax expense		—			5,556		—		—			5,556
Net income		24,132			35,698		3,866		(31,364	)		32,332
Net income attributable to noncontrolling interests		—			1,894		—		—			1,894
Net income attributable to Western Gas Partners, LP	$	24,132		$	33,804	$	3,866	$	(31,364	)	$	30,438

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

	March 31, 2011
	Western				Non-
	Gas		Guarantor		Guarantor
Balance Sheet	Partners, LP		Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Current assets	$	82,412	$	18,478	$	13,414	$	(58,461	)	$	55,843
Note receivable – Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		1,097,335		99,441		—		(1,196,776	)		—
Net property, plant and equipment		151		1,435,695		182,544		—			1,618,390
Other long-term assets		5,119		155,655		—		—			160,774
Total assets	$	1,445,017	$	1,709,269	$	195,958	$	(1,255,237	)	$	2,095,007
Current liabilities	$	1,053	$	100,182	$	4,581	$	(58,461	)	$	47,355
Long-term debt		645,000		—		—		—			645,000
Other long-term liabilities		53		58,716		1,986		—			60,755
Total liabilities		646,106		158,898		6,567		(58,461	)		753,110
Partners’ capital		798,911		1,460,359		189,391		(1,196,776	)		1,251,885
Noncontrolling interests		—		90,012		—		—			90,012
Total liabilities, equity and partners’ capital	$	1,445,017	$	1,709,269	$	195,958	$	(1,255,237	)	$	2,095,007

	December 31, 2010
	Western				Non-
	Gas		Guarantor		Guarantor
Balance Sheet	Partners, LP		Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Current assets	$	24,972	$	208,208	$	10,346	$	(200,342	)	$	43,184
Note receivable – Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		1,052,073		97,018		—		(1,149,091	)		—
Net property, plant and equipment		165		1,177,971		181,214		—			1,359,350
Other long-term assets		2,361		100,642		—		—			103,003
Total assets	$	1,339,571	$	1,583,839	$	191,560	$	(1,349,433	)	$	1,765,537
Current liabilities	$	201,989	$	38,420	$	2,127	$	(200,342	)	$	42,194
Long-term debt		474,000		—		—		—			474,000
Other long-term liabilities		38		42,283		1,954		—			44,275
Total liabilities		676,027		80,703		4,081		(200,342	)		560,469
Partners’ capital		663,544		1,412,674		187,479		(1,149,091	)		1,114,606
Noncontrolling interests		—		90,462		—		—			90,462
Total liabilities, equity and partners’ capital	$	1,339,571	$	1,583,839	$	191,560	$	(1,349,433	)	$	1,765,537

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

	Three Months Ended March 31, 2011
	Western						Non-
	Gas			Guarantor			Guarantor
Statement of Cash Flows	Partners, LP			Subsidiaries			Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	34,984		$	46,777		$	6,028		$	(49,851	)	$	37,938
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(46,777	)		(3,074	)		—			49,851			—
Depreciation, amortization and impairments		14			18,106			1,438			—			19,558
Change in other items, net		(259,049	)		254,076			2,541			—			(2,432	)
Net cash provided by (used in) operating activities		(270,828	)		315,885			10,007			—			55,064
Net cash used in investing activities		—			(319,035	)		(470	)		2,040			(317,465	)
Net cash provided by (used in) financing activities		269,175			3,150			(4,117	)		(2,040	)		266,168
Net increase (decrease) in cash and cash equivalents		(1,653	)		—			5,420			—			3,767
Cash and cash equivalents at beginning of period		21,480			—			5,594			—			27,074
Cash and cash equivalents at end of period	$	19,827		$	—		$	11,014		$	—		$	30,841

	Three Months Ended March 31, 2010
	Western						Non-
	Gas			Guarantor			Guarantor
Statement of Cash Flows	Partners, LP			Subsidiaries			Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	24,132		$	35,698		$	3,866		$	(31,364	)	$	32,332
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(29,392	)		(1,972	)		—			31,364			—
Depreciation, amortization and impairments		14			16,275			1,430			—			17,719
Change in other items, net		41,403			(40,512	)		1,517			—			2,408
Net cash provided by operating activities		36,157			9,489			6,813			—			52,459
Net cash used in investing activities		(241,680	)		(5,882	)		(1,049	)		—			(248,611	)
Net cash provided by (used in) financing activities		188,740			(3,607	)		(3,742	)		—			181,391
Net increase (decrease) in cash and cash equivalents		(16,783	)		—			2,022			—			(14,761	)
Cash and cash equivalents at beginning of period		61,632			—			8,352			—			69,984
Cash and cash equivalents at end of period	$	44,849		$	—		$	10,374		$	—		$	55,223

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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, as well as our historical consolidated financial statements, and the notes thereto, included in Part I, Item 8 of our 2010 annual report on Form 10-K as filed with the Securities and Exchange Commission, or “SEC,” on February 24, 2011. Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refers to Western Gas Partners, LP and its subsidiaries, including the financial results of the Partnership Assets (described below) from their respective acquisition dates, combined with the financial results and operations of the Wattenberg assets and 0.4% interest in White Cliffs for all periods presented. For ease of reference, we refer to the historical financial results of the Partnership Assets prior to our acquisitions as being “our” historical financial results. “Anadarko” or “Parent” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner. Our “general partner” refers to Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko and the general partner of the Partnership. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and also refers to Fort Union Gas Gathering, L.L.C., or “Fort Union,” and White Cliffs Pipeline, L.L.C., or “White Cliffs.” References to the “Partnership Assets” refer collectively to the assets owned by the Partnership as of March 31, 2011.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

          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,” “will,” “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 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 acquisitions, capital expenditures and other contractual obligations, and our ability to access those resources from Anadarko or through the debt or equity capital markets;

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

• the weather;

• inflation;

• the availability of goods and services;

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

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

24

• changes in the financial or operational condition of our sponsor, Anadarko, including the outcome of the Deepwater Horizon events;

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

• our commitments to capital projects;

• the ability to utilize our revolving credit facility;

• the creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners, and other parties;

• our ability to repay debt;

• 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 “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” included in our 2010 annual report on Form 10-K, our quarterly reports on Form 10-Q and in our other public filings and press releases.

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

EXECUTIVE SUMMARY

          We are a growth-oriented 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 (Colorado, Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged primarily in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko and third-party producers and customers. As of March 31, 2011, our assets consist of eleven gathering systems, six natural gas treating facilities, seven natural gas processing facilities, one NGL pipeline, one interstate pipeline, and noncontrolling interests in a gas gathering system and a crude oil pipeline.

          Significant financial and operational highlights during the first three months of 2011 include the following:

• In February 2011, we acquired the Platte Valley gathering system and processing plant from a third party for $303.6 million in cash. These assets are located in the Denver-Julesburg basin and consist of a cryogenic processing plant, two fractionation trains and a natural gas gathering system.

• In March 2011, we issued 3,852,813 common units to the public, generating net proceeds of $132.8 million, including the general partner’s proportionate capital contributions to maintain its 2.0% general partner interest. Net proceeds from this offering were used primarily to repay amounts outstanding under our revolving credit facility.

• Our stable operating cash flow, combined with a focus on cost reduction and capital spending discipline, enabled us to raise our distribution to $0.39 per unit for the first quarter of 2011, representing a 3% increase over the distribution for the fourth quarter of 2010 and our eighth consecutive quarterly increase.

• Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP for the three months ended March 31, 2011 averaged $0.62 per Mcf, representing an 11% increase compared to the first quarter of 2010. The increase in gross margin per Mcf is primarily due to the addition of the Platte Valley system, the increase in ownership of the White Cliffs investment and growth in higher-margin areas, which offset the impact of the expiration of lower-margin contracts. The predominantly fee-based and fixed-price structure of our contracts mitigated the impact of changes in commodity prices on our gross margin.

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• Throughput attributable to Western Gas Partners, LP totaled 1,506 MMcf/d for the three months ended March 31, 2011, representing an 8% decrease compared to the same period in 2010. The throughput decrease is primarily due to lower volumes at the MIGC system due to contract expirations in January 2011 and lower volumes at the Haley, Pinnacle, Dew and Hugoton systems due to natural production declines and low drilling activity. These declines were partially offset by increased throughput at the Granger, Chipeta and Wattenberg systems resulting from drilling activity in these areas driven by favorable producer economics, and the additional throughput attributable to the Platte Valley system.

ACQUISITIONS

          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, including two cryogenic trains with combined capacity of 200 MMcf/d, a refrigeration train with capacity of 100 MMcf/d, an NGL fractionation facility with capacity of 9,500 barrels per day, and ancillary equipment. In connection with the acquisition, we entered into a ten-year fee-based arrangement covering a majority of the Granger assets’ affiliate throughput and five-year, fixed-price commodity swap agreements with Anadarko, which cover non-fee-based volumes processed at the Granger complex.

          Wattenberg acquisition. In August 2010, we acquired Anadarko’s 100% ownership interest in Kerr-McGee Gathering LLC, which owns the Wattenberg gathering system with related compression and other facilities, including the Fort Lupton processing plant in the Denver-Julesburg Basin, located north and east of Denver, Colorado. In connection with the acquisition, we entered into a ten-year fee-based arrangement covering all of the Wattenberg assets’ affiliate throughput and five-year, fixed-price commodity swap agreements with Anadarko, which fix the margin we will realize from the purchase and sale of natural gas, condensate or NGLs at the Wattenberg assets.

          White Cliffs investment. In September 2010, we and Anadarko closed a series of related transactions through which we acquired a 10% interest in White Cliffs. Specifically, we acquired Anadarko’s 100% ownership interest in Anadarko Wattenberg Company, LLC, or “AWC,” for $20.0 million in cash. AWC owned a 0.4% interest in White Cliffs and held an option to increase its interest in White Cliffs. Also, in a series of concurrent transactions AWC acquired a 9.6% interest in White Cliffs from a third party for $18.0 million in cash, subject to post-closing adjustments. Our acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko and the acquisition of an additional 9.6% interest in White Cliffs were funded with cash on hand and are referred to collectively as the “White Cliffs acquisition.”

          Platte Valley acquisition. On February 28, 2011, we acquired the Platte Valley gathering system and processing plant from a third party, for $303.6 million in cash. These assets are located in the Denver-Julesburg Basin and consist of a processing plant with cryogenic capacity of 84 MMcf/d; two fractionation trains; a 1,098 mile natural gas gathering system that delivers gas to the Platte Valley plant, either directly or through the Partnership’s Wattenberg gathering system; and related equipment. The Platte Valley gathering system and processing plant are referred to collectively as the “Platte Valley assets” and the acquisition as the “Platte Valley acquisition.” In connection with the acquisition, we entered into long-term fee-based agreements with the seller to gather and process its existing gas production, as well as to expand the existing gathering systems and processing capacity. We financed the Platte Valley acquisition with borrowings under our revolving credit facility.

          Presentation of Partnership acquisitions. Because Anadarko indirectly owns our general partner, each acquisition of Partnership Assets, except for the acquisitions of the Platte Valley assets and the 9.6% interest in White Cliffs from third parties, was considered a transfer of net assets between entities under common control. Accordingly, our consolidated financial statements include the financial results and operations of the Partnership Assets since the date of common control. Anadarko acquired the Wattenberg assets in connection with its August 10, 2006 acquisition of Kerr-McGee Corporation and made its initial investment in White Cliffs on January 29, 2007.

          Our historical financial statements for the three months ended March 31, 2010, as presented in our quarterly report on Form 10-Q for the quarter ended March 31, 2010, have been recast in this quarterly report on Form 10-Q to include the results attributable to the Wattenberg assets and the 0.4% interest in White Cliffs as if we owned such assets for all periods presented. Unless otherwise noted, references to “periods prior to our acquisition of the Partnership Assets” and similar phrases refer to periods prior to July 2010 with respect to the Wattenberg assets and periods prior to September 2010 with respect to the White Cliffs investment. Reference to “periods including and subsequent to our acquisition of the Partnership Assets” and similar phrases refer to periods including and subsequent to July 2010 with respect to the Wattenberg assets and periods including and subsequent to September 2010 with respect to the White Cliffs investment. In addition, certain amounts in prior periods have been reclassified to conform to the current presentation.

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EQUITY OFFERINGS

          May 2010 equity offering. On May 18, 2010, we closed a public offering of 4,000,000 common units at a price of $22.25 per unit. On June 2, 2010, we issued an additional 558,700 common units to the public pursuant to the exercise of the underwriters’ over-allotment option granted in connection with that offering. We refer to the May 18 and June 2, 2010 issuances collectively as the “May 2010 equity offering.” In connection with the May 2010 equity offering, we also issued 93,035 general partner units to our general partner. Net proceeds from the May 2010 equity offering of $99.1 million were used to repay amounts outstanding under our revolving credit facility.

          November 2010 equity offering. On November 15, 2010, we closed a public offering of 7,500,000 common units at a price of $29.92 per unit. On November 22, 2010, we issued an additional 915,000 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with that offering. We refer to the November 15 and November 22, 2010 issuances collectively as the “November 2010 equity offering.” In connection with the November 2010 equity offering, we also issued 171,734 general partner units to our general partner. Net proceeds from the November 2010 equity offering of $246.7 million were primarily used to repay amounts outstanding under our revolving credit facility.

          March 2011 equity offering. On March 4, 2011, we closed a public offering of 3,550,000 common units at a price of $35.15 per unit. On March 31, 2011, we issued an additional 302,813 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with the offering. The March 4, 2011 and March 31, 2011 issuances are referred to collectively as the “March 2011 equity offering.” In connection with the March 2011 equity offering, we also issued 78,629 general partner units to our general partner in exchange for $2.8 million. Net proceeds from the March 2011 equity offering of $132.8 million were primarily used to repay amounts outstanding under our revolving credit facility.

27

RESULTS OF OPERATIONS

OPERATING RESULTS

          The following tables and discussion present a summary of our results of operations:

	Three Months Ended
	March 31,
	2011			2010(1)
	(in thousands)
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	$	61,130		$	56,915
Natural gas, natural gas liquids and condensate sales		71,405			69,872
Equity income and other, net		3,458			2,149
Total revenues		135,993			128,936
Operating expenses (2)
Cost of product		46,820			41,973
Operation and maintenance		20,862			22,391
General and administrative		6,698			6,068
Property and other taxes		3,959			3,619
Depreciation, amortization and impairments		19,558			17,719
Total operating expenses		97,897			91,770
Operating income		38,096			37,166
Interest income – affiliates		4,225			4,230
Interest expense		(6,111	)		(3,528	)
Other income (expense), net		1,760			20
Income before income taxes		37,970			37,888
Income tax expense		32			5,556
Net income		37,938			32,332
Net income attributable to noncontrolling interests		2,954			1,894
Net income attributable to Western Gas Partners, LP	$	34,984		$	30,438
Key performance metrics (3)
Gross margin	$	89,173		$	86,963
Adjusted EBITDA	$	56,314		$	52,630
Distributable cash flow	$	49,726		$	47,838

(1)	Financial information for 2010 has been revised to include results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1—Description of Business and Basis of Presentation—Acquisitions in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report.
(2)	Operating expenses include amounts charged by affiliates to the Partnership for services as well as reimbursement of amounts paid by affiliates to third parties on behalf of the Partnership. See Note 4—Transactions with Affiliates in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report.
(3)	Gross margin, Adjusted EBITDA and distributable cash flow are defined under the caption Operating results within this 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 generally accepted accounting principles, or “GAAP.”

          For purposes of the following discussion, any increases or decreases “for the three months ended March 31, 2011” refer to the comparison of the three months ended March 31, 2011 to the three months ended March 31, 2010.

28

Operating Statistics

	Three Months Ended March 31,
	2011		2010(1)		D(2)
	(MMcf/d, except percentages)
Gathering and transportation throughput (3)		902		1,078		(16)	%
Processing throughput (4)		748		634		18	%
Equity investment throughput (5)		74		121		(39)	%
Total throughput		1,724		1,833		(6)	%
Throughput attributable to noncontrolling interests		218		190		15	%
Total throughput attributable to Western Gas Partners, LP		1,506		1,643		(8)	%

(1)	Throughput for 2010 has been revised to include volumes attributable to the Wattenberg assets.
(2)	Represents the percentage change for the three months ended March 31, 2011.
(3)	Excludes NGL pipeline volumes measured in barrels.
(4)	Includes 100% of Chipeta, Granger and Hilight system volumes and 50% of Newcastle system volumes for all periods presented as well as throughput for March 2011 attributable to the Platte Valley assets.
(5)	Represents the Partnership’s 14.81% share of Fort Union’s gross volumes and excludes crude oil throughput measured in barrels attributable to White Cliffs.

          Total throughput, which consists of affiliate, third-party and equity-investment volumes, decreased by 109 MMcf/d for the three months ended March 31, 2011 and total throughput attributable to Western Gas Partners, LP, which excludes the noncontrolling interest owners’ proportionate share of Chipeta Processing LLC’s, or “Chipeta’s,” throughput, decreased by 137 MMcf/d for the three months ended March 31, 2011.

          Gathering and transportation throughput decreased by 176 MMcf/d for the three months ended March 31, 2011 primarily due to lower throughput at the MIGC system resulting from the January 2011 expiration of certain contracts, which were not renewed due to the start up of the Bison pipeline, and throughput decreases at the Haley, Pinnacle, Dew and Hugoton systems resulting from natural production declines and reduced drilling activity in those areas. These declines were partially offset by throughput increases at the Wattenberg system due to drilling activity and recompletions in the area.

          Processing throughput increased by 114 MMcf/d for the three months ended March 31, 2011 primarily due to throughput increases at the Chipeta, Granger and Hilight systems, resulting from drilling activity in these areas driven by the relatively high liquid content of the gas volumes produced, as well as the additional throughput from the Platte Valley system acquired in February 2011.

          Equity investment volumes decreased by 47 MMcf/d for the three months ended March 31, 2011 due to lower throughput at the Fort Union system following the start up of the Bison pipeline.

Natural Gas Gathering, Processing and Transportation Revenues

	Three Months Ended March 31,
	2011		2010		D
	(in thousands, except percentages)
Gathering, processing and transportation of natural gas and natural gas liquids	$	61,130	$	56,915		7	%

          Gathering, processing and transportation of natural gas revenues increased by $4.2 million for the three months ended March 31, 2011 primarily due to increased fee revenue at the Wattenberg system resulting from changes in affiliate contract terms effective in July 2010 from primarily keep-whole and percentage-of-proceeds agreements to fee-based agreements. In addition, revenues increased due to the acquisition of the Platte Valley system in late February 2011. These increases were partially offset by decreased fee revenue at the MIGC, Haley, Hugoton and Dew systems resulting from decreased throughput.

29

Natural Gas, Natural Gas Liquids and Condensate Sales

	Three Months Ended March 31,
	2011		2010		D
	(in thousands, except percentages and
	per-unit amounts)
Natural gas sales	$	20,430	$	14,712		39	%
Natural gas liquids sales		42,722		44,970		(5)	%
Drip condensate sales		8,253		10,190		(19)	%
Total	$	71,405	$	69,872		2	%
Average price per unit:
Natural gas (per Mcf)	$	5.80	$	5.51		5	%
Natural gas liquids (per Bbl)	$	48.04	$	37.68		27	%
Drip condensate (per Bbl)	$	73.08	$	71.31		2	%

          Total natural gas, natural gas liquids and condensate sales increased by $1.5 million for the three months ended March 31, 2011, consisting of a $5.7 million increase in natural gas sales, including the impact of gains on commodity price swap agreements, partially offset by a $2.2 million decrease in NGLs sales and a $1.9 million decrease in drip condensate sales. The average natural gas and NGLs prices for the three months ended March 31, 2011 include the effects of commodity price swap agreements attributable to sales for the Granger, Wattenberg, Hilight, Newcastle and Hugoton systems. The average natural gas and NGLs prices for the three months ended March 31, 2010 include the effects of commodity price swap agreements attributable to sales for only the Granger, Hilight and Newcastle systems. See Note 4—Transactions with Affiliates— Commodity price swap agreements included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q.

          The increase in natural gas sales for the three months ended March 31, 2011 was due to a 31% increase in the volume of natural gas sold, resulting from higher throughput at the Hilight system as well as the acquisition of the Platte Valley system, and due to a 5% increase in average natural gas sales prices.

          For the three months ended March 31, 2011, the decrease in NGLs sales is primarily attributable to a 22% decrease in the volume of NGLs sold primarily due to the changes in affiliate contract terms at the Wattenberg system effective in July 2010, allowing the producer to take its liquids in kind. This decrease was partially offset by a 27% increase in NGL prices, higher volumes at the Hilight system, inventory sales at the Chipeta system and volumes from the recently acquired Platte Valley system.

          The decrease in drip condensate sales for the three months ended March 31, 2011 was primarily due to a decrease in the volume of condensate sold, offset by higher average sales prices at the Hugoton and Wattenberg systems.

Equity Income and Other Revenues

	Three Months Ended March 31,
	2011		2010		D
	(in thousands, except percentages)
Equity income	$	2,044	$	1,379		48	%
Other revenues, net		1,414		770		84	%
Total equity income and other revenues, net	$	3,458	$	2,149		61	%

          Equity income increased by $0.7 million for the three months ended March 31, 2011 due to the increase in the ownership interest in White Cliffs in September 2010, offset by a slight decrease in income from Fort Union due to lower volumes.

          Other revenues increased by $0.6 million for the three months ended March 31, 2011 primarily due to a change in gas imbalance positions at the MIGC and Wattenberg systems.

30

Cost of Product and Operation and Maintenance Expenses

	Three Months Ended March 31,
	2011		2010		D
	(in thousands, except percentages)
Cost of product	$	46,820	$	41,973		12	%
Operation and maintenance		20,862		22,391		(7)	%
Total cost of product and operation and maintenance expenses	$	67,682	$	64,364		5	%

          Cost of product expense increased by $4.8 million for the three months ended March 31, 2011, which includes a $9.8 million increase primarily due to higher volumes resulting from the acquisition of the Platte Valley system and increased throughput at systems subject to percent-of-proceeds and keep-whole contracts. This increase was partially offset by a $3.9 million decrease due to changes in gas imbalance positions and a $0.5 million decrease from the lower cost of natural gas to compensate shippers on a thermally equivalent basis for drip condensate retained by us and sold to third parties. Cost of product expense includes the effects of commodity price swap agreements attributable to purchases for the three months ended March 31, 2011 and 2010. See Note 4—Transactions with Affiliates— Commodity price swap agreements included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q.

          Operation and maintenance expense decreased by $1.5 million for the three months ended March 31, 2011, primarily due to annual incentive compensation attributed to the Wattenberg system prior to our acquisition, lower compressor lease expenses resulting from the purchase of compressors used at the Granger and Wattenberg systems leased during 2010, partially offset by an increase in operating expenses attributed to the Platte Valley system. The decrease in compressor lease expense was offset by an increase in depreciation expense discussed below under General and Administrative, Depreciation and Other Expenses.

General and Administrative, Depreciation and Other Expenses

	Three Months Ended March 31,
	2011		2010		D
	(in thousands, except percentages )
General and administrative	$	6,698	$	6,068		10	%
Property and other taxes		3,959		3,619		9	%
Depreciation, amortization and impairments		19,558		17,719		10	%
Total general and administrative, depreciation and other expenses	$	30,215	$	27,406		10	%

          General and administrative expenses increased by $0.6 million for the three months ended March 31, 2011 due to an increase in corporate and management personnel costs allocated to us pursuant to the omnibus agreement and an increase in noncash payroll expenses primarily due to an increase in the value of equity-based awards; partially offset by the management fee allocated to the Wattenberg assets during the three months ended March 31, 2010, then discontinued effective July 2010 upon contribution of the assets to us. Depreciation, amortization and impairments increased by $1.8 million for the three months ended March 31, 2011 primarily attributable to the addition of the Platte Valley system as well as depreciation associated with previously leased compressors used at the Granger and Wattenberg systems purchased and contributed to the Partnership during 2010.

31

Interest Income and Interest Expense

	Three Months Ended March 31,
	2011			2010			D
	(in thousands, except percentages)
Interest income on note receivable	$	4,225		$	4,225			—
Interest income, net on affiliate balances		—			5			nm	(1)
Interest income – affiliates		4,225			4,230			—
Third Parties
Interest expense on revolving credit facility and Wattenberg term loan		(2,676	)		(977	)		174	%
Amortization of debt issuance costs and commitment fees		(2,201	)		(766	)		187	%
Affiliates
Interest expense on notes payable		(1,234	)		(1,750	)		(29	)%
Credit facility commitment fees		—			(35	)		nm
Interest expense	$	(6,111	)	$	(3,528	)		73	%

⁽¹⁾ Percent change is not meaningful

          Interest expense increased by $2.6 million for the three months ended March 31, 2011 due to interest expense incurred on the amounts outstanding during 2011 under the Wattenberg term loan and our revolving credit facility as well as $1.3 million of accelerated amortization expense related to the early repayment of the Wattenberg term loan in March 2011. See Note 8—Debt and Interest Expense included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q.

Other Income (Expense), Net

	Three Months Ended March 31,
	2011		2010		D
	(in thousands, except percentages)
Other income (expense), net	$	1,760	$	20	nm(1)

⁽¹⁾ Percent change is not meaningful

          Other income (expense), net for the three months ended March 31, 2011 primarily consists of a $1.7 million unrealized gain for a forward-starting interest-rate swap agreement entered into in March 2011. See Note 8—Debt and Interest Expense included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q.

32

Income Tax Expense

	Three Months Ended March 31,
	2011			2010			Δ
	(in thousands, except percentages)
Income before income taxes	$	37,970		$	37,888		nm(1)
Income tax expense		32			5,556		nm
Effective tax rate		0	%		15	%

⁽¹⁾ Percent change is not meaningful

          The Partnership is not a taxable entity for U.S. federal income tax purposes. For the three months ended March 31, 2011 only the portion of Partnership income allocable to Texas was subject to Texas margin tax. For the three months ended March 31, 2010, other than income earned by the Granger and Wattenberg assets, only the portion of Partnership income allocable to Texas was subject to Texas margin tax. Income attributable to the Wattenberg assets prior to and including July 2010 and income attributable to the Granger assets prior to and including January 2010 were subject to federal and state income tax, resulting in the lower income tax expense for the three months ended March 31, 2011. Income earned by the Granger and Wattenberg assets for periods subsequent to January 2010 and July 2010, respectively, was subject only to Texas margin tax.

          For 2011 and 2010, the Partnership’s variance from the federal statutory rate is primarily attributable to the Partnership’s status as a non-taxable entity for U.S. federal income tax purposes.

Noncontrolling Interests

	Three Months Ended March 31,
	2011		2010		Δ
	(in thousands, except percentages)
Net income attributable to noncontrolling interests	$	2,954	$	1,894		56	%

          Net income attributable to noncontrolling interests increased by $1.1 million for the three months ended March 31, 2011 primarily due to higher volumes and improved liquids recoveries at the Chipeta system. Noncontrolling interests represent the aggregate 49% interest in Chipeta held by Anadarko and a third party.

33

Key Performance Metrics

	Three Months Ended March 31,
	2011		2010		Δ
	(in thousands, except percentages
	and gross margin per Mcf)
Gross margin	$	89,173	$	86,963		3%
Gross margin per Mcf (1)		0.57		0.53		8%
Gross margin per Mcf attributable to Western Gas Partners, LP (2)		0.62		0.56		11%
Adjusted EBITDA (3)		56,314		52,630		7%
Distributable cash flow (3)	$	49,726	$	47,838		4%

(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 Fort Union.
(2)	Calculated as gross margin, 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 attributable to the Partnership’s investments in Fort Union and White Cliffs 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 captions Adjusted EBITDA and Distributable cash flow.

          Gross margin increased by $2.2 million for the three months ended March 31, 2011, primarily due to the acquisition of the Platte Valley system; higher margins at the Chipeta and Hilight systems due to an increase in prices and volumes, including the impact of commodity price swap agreements; and the increase in our interest in White Cliffs from 0.4% to 10%. These increases were partially offset by (i) lower margins at the Wattenberg system due to changes in contract terms; (ii) lower gross margin at the Granger system due to lower NGLs volumes sold; (iii) lower throughput at the Haley and Dew systems due to naturally declining production volumes and (iv) lower revenues at the MIGC system due to the expiration of certain firm transportation contracts in January 2011. Gross margin per Mcf increased by 8% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 11% for the three months ended March 31, 2011, primarily due to the change in throughput mix within our portfolio, higher margins at the Chipeta and Hilight systems and the acquisition of the Platte Valley system.

          Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, general and administrative expense in excess of the omnibus cap (if any), interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, other income and other nonrecurring adjustments that are not settled in cash.

          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, which 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

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

34

          Adjusted EBITDA increased by $3.7 million for the three months ended March 31, 2011, primarily due to a $6.4 million increase in total revenues excluding equity income, a $1.5 million decrease in operation and maintenance expenses, a $1.3 million increase in distributions from Fort Union and White Cliffs, and a $0.7 million decrease in general and administrative expenses, excluding non-cash equity-based compensation. These changes were partially offset by a $4.8 million increase in cost of product and a $1.1 million increase in net income attributable to noncontrolling interests.

          Distributable cash flow. We define “distributable cash flow” as Adjusted EBITDA, plus interest income, less net cash paid for interest expense (including amortization of deferred debt issuance costs originally paid in cash), 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 $1.9 million for the three months ended March 31, 2011, primarily due to the $3.7 million increase in Adjusted EBITDA and a $0.8 million decrease in maintenance capital expenditures, partially offset by a $2.6 million increase in interest expense on borrowings, including $1.3 million of accelerated amortization expense related to the early repayment of the Wattenberg term loan.

          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, while 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. Our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies in our industry, 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.

35

          The following tables present (a) a reconciliation of 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:

	Three Months Ended
	March 31,
	2011			2010(1)
	(in thousands)
Reconciliation of Adjusted EBITDA to net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	56,314		$	52,630
Less:
Distributions from equity investees		2,434			1,150
Non-cash equity-based compensation expense		1,928			567
Interest expense		6,111			3,528
Income tax expense (2)		32			5,556
Depreciation, amortization and impairments (2)		18,853			17,019
Add:
Equity income, net		2,044			1,379
Interest income – affiliate		4,225			4,230
Other income, net (2)		1,759			19
Net income attributable to Western Gas Partners, LP	$	34,984		$	30,438
Reconciliation of Adjusted EBITDA to net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	56,314		$	52,630
Adjusted EBITDA attributable to noncontrolling interests		3,658			2,593
Interest income (expense), net		(1,886	)		702
Non-cash equity-based compensation expense		(1,928	)		(567	)
Current income tax expense		(90	)		(7,341	)
Other income (expense), net		1,760			20
Distributions from equity investees less than (in excess of) equity income, net		(390	)		229
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		(8,685	)		(5,529	)
Accounts payable, accrued liabilities and natural gas imbalance payable		5,887			9,729
Other		424			(7	)
Net cash provided by operating activities	$	55,064		$	52,459

(1)	Financial information for 2010 has been revised to include the results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1—Description of Business and Basis of Presentation—Acquisitions included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q.
(2)	Includes the Partnership’s 51% share of income tax expense; depreciation, amortization and impairments; and other income, net, attributable to Chipeta.

36

	Three Months Ended
	March 31,
	2011		2010(1)
	(in thousands)
Reconciliation of distributable cash flow to net income attributable to Western Gas Partners, LP
Distributable cash flow	$	49,726	$	47,838
Less:
Distributions from equity investees		2,434		1,150
Non-cash share-based compensation expense		1,928		567
Income tax expense (2)		32		5,556
Depreciation, amortization and impairments (2)		18,853		17,019
Add:
Equity income, net		2,044		1,379
Cash paid for maintenance capital expenditures (2)		4,702		5,489
Interest income, net (non-cash settled)		—		5
Other income, net (2)		1,759		19
Net income attributable to Western Gas Partners, LP	$	34,984	$	30,438

(1)	Financial information for 2010 has been revised to include the results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1—Description of Business and Basis of Presentation—Acquisitions included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q.
(2)	Includes the Partnership’s 51% share of income tax expense; depreciation, amortization and impairments; cash paid for maintenance capital expenditures; and other income, net, attributable to Chipeta.

LIQUIDITY AND CAPITAL RESOURCES

          Our primary cash requirements are for acquisitions and other capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner and distributions to our noncontrolling interest owners. Our sources of liquidity as of March 31, 2011 include cash flows generated from operations, including interest income on our $260.0 million note receivable from Anadarko; available borrowing capacity under our revolving credit facility; and issuances of additional common and general partner units or debt securities. We believe that cash flows generated from the sources above 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 results of operations, financial conditions, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including debt and common unit issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our revolving credit facility to pay distributions or fund other short-term working capital requirements.

          Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. We have made cash distributions to our unitholders and have increased our quarterly distribution each quarter from the second quarter of 2009 through the first quarter of 2011. On April 19, 2011, the board of directors of our general partner declared a cash distribution to our unitholders of $0.39 per unit, or $33.2 million in aggregate, including incentive distributions. The cash distribution will be paid on May 13, 2011 to unitholders of record at the close of business on April 29, 2011.

          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 debt 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. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Please read Item 1A—Risk Factors of our 2010 annual report on Form 10-K.

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          Working capital. As of March 31, 2011 we had $8.5 million of working capital, which we define as the amount by which current assets exceed current liabilities. 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 and 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.

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

• maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached 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 system throughput or capacity from current levels, including well connections that increase existing system throughput.

          Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Capital expenditures and capital incurred were as follows:

	Three Months Ended March 31,
	2011		2010
	(in thousands)
Acquisitions	$	303,602	$	241,680
Expansion capital expenditures	$	9,221	$	1,274
Maintenance capital expenditures		4,702		5,657
Total capital expenditures (1)	$	13,923	$	6,931
Capital incurred (2)	$	13,198	$	6,367

(1)	Capital expenditures for the three months ended March 31, 2010 include $1.6 million of pre-acquisition capital expenditures for the Partnership Assets and capital expenditures for the three months ended March 31, 2011 and 2010 include the noncontrolling interest owners’ share of Chipeta’s capital expenditures funded by contributions from the noncontrolling interest owners.
(2)	Capital incurred for the three months ended March 31, 2010 include $1.9 million of pre-acquisition capital incurred for the Partnership Assets and capital expenditures for the three months ended March 31, 2011 and 2010 include the noncontrolling interest owners’ share of Chipeta’s capital expenditures funded by contributions from the noncontrolling interest owners.

          Acquisitions include the Platte Valley acquisition in February 2011 and the Granger acquisition effective in January 2010. These acquisitions are described under the caption Acquisitions within this Item 2.

          Capital expenditures, excluding acquisitions, increased by $7.0 million for the three months ended March 31, 2011. Expansion capital expenditures increased by $7.9 million for the three months ended March 31, 2011, primarily due to expansion of field compression, gathering pipelines and well connections at the Wattenberg and Hilight systems during 2011 as well as the initial construction costs for the Chipeta cryogenic train expansion. Maintenance capital expenditures decreased by $1.0 million, primarily as a result of fewer well connections at the Haley, Hugoton and Granger systems in 2011 and improvements at the Granger system completed during 2010, partially offset by an increase in well connections at the Hilight system.

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          Historical cash flow. The following table presents a summary of our net cash flows from operating activities, investing activities and financing activities (in thousands).

	Three Months Ended
	March 31,
	2011			2010
Net cash provided by (used in):
Operating activities	$	55,064		$	52,459
Investing activities		(317,465	)		(248,611	)
Financing activities		266,168			181,391
Net increase (decrease) in cash and cash equivalents	$	3,767		$	(14,761	)

          Operating Activities. Net cash provided by operating activities increased by $2.6 million for the three months ended March 31, 2011, primarily due to the following items:

• a $7.3 million decrease in current income tax expense;

• a $6.4 million increase in revenues, excluding equity income; and

• a $1.5 million decrease in operating and maintenance expenses.

            The impact of the above items was substantially offset by the following:

• a $4.8 million increase in cost of product expense;

• a $3.5 million decrease due to changes in accounts receivable balances;

• a $3.1 million decrease due to changes in accounts payable balances and other items; and

• a $1.3 million increase in interest expense associated with higher debt balances outstanding as a result of the 2010 acquisitions of the Granger and Wattenberg assets.

          Investing Activities. Net cash used in investing activities for the three months ended March 31, 2011 included $303.6 million of cash paid for the Platte Valley acquisition and $13.9 million of capital expenditures. Net cash used in investing activities for the three months ended March 31, 2010 included $241.7 million of cash paid for the Granger acquisition and $6.9 million of capital expenditures. See the sub-caption Capital expenditures above within this Liquidity and Capital Resources discussion.

          Financing Activities. Net cash provided by financing activities for the three months ended March 31, 2011 included $303.0 million of borrowings to fund the Platte Valley acquisition and the $132.8 million of net proceeds from our March 2011 equity offering, offset by repayment of amounts due under our revolving credit facility using the offering proceeds. Financing activities for the three months ended March 31, 2011 also included the $250.0 million repayment of the Wattenberg term loan using borrowings from our revolving credit facility. Financing activities for the three months ended 2010 included the $210.0 million of borrowings to partially fund the Granger acquisition. For the three months ended March 31, 2011 and 2010, we paid $30.6 million and $21.4 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $1.0 million and $2.0 million during the three months ended March 31, 2011 and 2010, respectively, primarily for expansion of the cryogenic units. Distributions from Chipeta to noncontrolling interest owners totaled $4.4 million and $2.8 million for the three months ended March 31, 2011 and 2010, respectively, representing the distribution for the fourth quarter of each preceding year.

          Debt and credit facilities. As of March 31, 2011, our outstanding debt consisted of $470.0 million outstanding under our revolving credit facility and the $175.0 million note payable to Anadarko issued in connection with the Powder River acquisition. See Note 8—Debt and Interest Expense included in the notes to the unaudited consolidated financial statements included under Part I, Item I of this quarterly report.

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          Note payable to Anadarko. In December 2008, we 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 was fixed at 4.00% through November 2010, and is fixed at 2.82% thereafter, reflecting an amendment to the term loan agreement made in December 2010. The Partnership has the option, at any time, to repay the outstanding principal amount in whole or in part.

          The provisions of the five-year term loan agreement 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 and (iii) a change of control.

          Revolving credit facility. In March 2011, we entered into an amended and restated $800.0 million senior unsecured revolving credit facility, or the “revolving credit facility,” and borrowed $250.0 million under the revolving credit facility to repay the Wattenberg term loan (described below). The revolving credit facility amended and restated our $450.0 million credit facility, which was originally entered into in October 2009. The revolving credit facility matures in March 2016 and bears interest at London Interbank Offered Rate, or “LIBOR,” plus applicable margins ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 0.30% to 0.90%. We are also required to pay a quarterly facility fee ranging from 0.20% to 0.35% 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 covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of our business, sell all or substantially all of our assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The revolving credit facility also contains various customary covenants, customary events of default and certain financial tests, as of the end of each quarter, including a maximum consolidated leverage ratio, as defined in the revolving credit facility, of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio, as defined in the revolving credit facility, of 2.0 to 1.0. All amounts due under the revolving credit facility are unconditionally guaranteed by our wholly owned subsidiaries. The Partnership will no longer be required to comply with the minimum consolidated interest coverage ratio as well as the subsidiary guarantees and certain of the aforementioned covenants, 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. As of March 31, 2011, $470.0 million was outstanding under the revolving credit facility, $330.0 million was available for borrowing and we were in compliance with all covenants thereunder.

          Wattenberg term loan. In connection with the Wattenberg acquisition, in August 2010, we borrowed $250.0 million under a three-year term loan from a group of banks (“Wattenberg term loan”). The Wattenberg term loan incurred interest at LIBOR plus a margin, ranging from 2.50% to 3.50% depending on our consolidated leverage ratio, as defined in the Wattenberg term loan agreement. We repaid the Wattenberg term loan in March 2011 using borrowings from our revolving credit facility.

          Registered securities. As of March 31, 2011, we may issue up to approximately $635.8 million 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 counterparties, including Anadarko, financial institutions, customers and other parties. Generally, non-payment or non-performance results from a customer’s inability to satisfy payables to us 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 third-party customers.

          We are dependent upon a single producer, Anadarko, for the substantial 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, processing and transportation fees and for proceeds from the sale of residue gas, NGLs and condensate to Anadarko.

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          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, which was issued concurrently with the closing of our initial public offering. We are also party to agreements 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 assets acquired from Anadarko. Finally, we have entered into various commodity price swap agreements with Anadarko in order to reduce our exposure to commodity price risk 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, contribution agreements or the commodity price swap agreements, as described in Note 4—Transactions with Affiliates included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q, our ability to make distributions to our unitholders may be adversely impacted.

CONTRACTUAL OBLIGATIONS

          Our contractual obligations include notes payable to Anadarko, credit facilities, a corporate office lease and warehouse lease, for which information is provided in Note 8—Debt and Interest Expense and Note 9—Commitments and Contingencies in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q. Our contractual obligations also include asset retirement obligations, which have not changed significantly since December 31, 2010, except for asset retirement obligations assumed in connection with the Platte Valley acquisition for which information is provided under Note 1—Description of Business and Basis of Presentation—Acquisitions under Part I, Item 1 of this quarterly report on Form 10-Q.

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 under Note 9—Commitments and Contingencies in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q.

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 New York Mercantile Exchange, or “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 this amount of gas by supplying additional gas or by paying an agreed-upon value for the gas utilized.

          To mitigate our exposure to changes in commodity prices as a result of the purchase and sale of natural gas, condensate or NGLs, we currently have in place fixed-price swap agreements with Anadarko expiring at various times through September 2015. For additional information on the commodity price swap agreements, see Note 4—Transactions with Affiliates included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report.

          We consider our exposure to commodity price risk associated with the above-described arrangements to be minimal given the existence of the commodity price swap agreements with Anadarko and the relatively small amount of our operating income that is impacted by changes in market prices. Accordingly, we do not expect a 10% change in natural gas or NGL prices to have a material direct impact on our operating income, financial condition or cash flows for the next twelve months, excluding the effect of natural gas imbalances described below.

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

          Interest rate risk. Interest rates during 2010 and 2011 were low compared to historic rates. If interest rates rise, our future financing costs will increase. As of March 31, 2011, we owed $470.0 million under our revolving credit facility at variable interest rates based on LIBOR, and we owed $175.0 million under the note payable to Anadarko that bears a fixed rate. We entered into a forward-starting interest-rate swap agreement in March 2011 pursuant to which we will pay a 2.32% fixed interest rate and receive three-month LIBOR on $150.0 million notional amount from May 2011 to May 2016. The swap agreement includes a provision that requires the termination of the swap at the start of the reference period. See Note 8—Debt and Interest Expense included in the notes to the unaudited consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q. For the quarter ended March 31, 2011, a 10% change in LIBOR would have resulted in a nominal change in interest expense.

          We may incur additional debt in the future, either under the revolving credit facility or other financing sources, including commercial bank borrowings or debt issuances.

Item 4. Controls and Procedures

          Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of the Partnership’s general partner performed an evaluation of the Partnership’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Partnership’s disclosure controls and procedures are effective as of March 31, 2011.

          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, 2011 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, regulatory or administrative proceedings other than proceedings arising 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 condition, or for which disclosure is required by Item 103 of Regulation S-K.

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, 2010, in addition to other information in such report, and in this quarterly report on Form 10-Q. Additionally, for a full discussion of the risks associated with Anadarko’s business, see Item 1A in Anadarko’s annual report on Form 10-K for the year ended December 31, 2010, Anadarko’s quarterly reports on Form 10-Q and Anadarko’s other public filings, press releases and discussions with Anadarko management. 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.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

          In connection with our March 2011 equity offering, our general partner purchased an additional 78,629 general partner units to maintain its 2.0% general partner interest in us for $2.8 million in cash. Proceeds from the March 2011 equity offering, including from the sale of the general partner units, were primarily used to repay amounts outstanding under our revolving credit facility. The general partner units issued in connection with this transaction were issued to our general partner or other subsidiaries of Anadarko in private placements that were not registered with the SEC pursuant to an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended.

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 5, 2011	By:	/s/ Donald R. Sinclair Donald R. Sinclair
		President and Chief Executive Officer
		(Principal Executive Officer)
		Western Gas Holdings, LLC
		(as general partner of Western Gas Partners, LP)
Date: May 5, 2011	By:	/s/ Benjamin M. Fink
		Benjamin M. Fink
		Senior Vice President, Chief Financial Officer
		and Treasurer
		(Principal Financial and Accounting Officer)
		Western Gas Holdings, LLC
		(as general partner of Western Gas Partners, LP)

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EXHIBIT INDEX

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished 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).
2.5	Contribution Agreement, dated as of July 30, 2010, by and among Western Gas Resources, Inc., WGR Asset Holding Company 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 August 5, 2010, File No. 001-34046).
2.6	Purchase and Sale Agreement, dated as of January 14, 2011, by and among Western Gas Partners, LP, Kerr-McGee Gathering LLC and Encana Oil & Gas (USA) Inc. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 18, 2011 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 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).

3.7	Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 2, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
3.8	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).
3.9	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	Revolving Credit Agreement, dated as of March 24, 2011, among Western Gas Partners, LP, Wells Fargo Bank, National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 29, 2011, File No. 001-34046).
31.1*	Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Schema Document
101.CAL**	XBRL Calculation Linkbase Document
101.LAB**	XBRL Label Linkbase Document
101.PRE**	XBRL Presentation Linkbase Document
101.DEF**	XBRL Definition Linkbase Document

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Donald R. Sinclair, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Western Gas Partners, LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 5, 2011	By:	/s/ Donald R. Sinclair Donald R. Sinclair
		President and Chief Executive Officer
		(Principal Executive Officer)
		Western Gas Holdings, LLC
		(as general partner of Western Gas Partners, LP)

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Benjamin M. Fink, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Western Gas Partners, LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 5, 2011	By:	/s/ Benjamin M. Fink Benjamin M. Fink
		Senior Vice President, Chief Financial Officer
		and Treasurer
		(Principal Financial and Accounting Officer)
		Western Gas Holdings, LLC
		(as general partner of Western Gas Partners, LP)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

          Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, Donald R. Sinclair, President and Chief Executive Officer of Western Gas Holdings, LLC, the general partner of Western Gas Partners, LP (the “Company”) and Benjamin M. Fink, Senior Vice President, Chief Financial Officer and Treasurer of Western Gas Holdings, LLC, certify that:

(1)	the Quarterly Report on Form 10-Q of the Company for the period ending March 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 5, 2011	/s/ Donald R. Sinclair Donald R. Sinclair
	President and Chief Executive Officer
	(Principal Executive Officer)
	Western Gas Holdings, LLC
	(as general partner of Western Gas Partners, LP)
Date: May 5, 2011	/s/ Benjamin M. Fink
	Benjamin M. Fink
	Senior Vice President, Chief Financial Officer
	and Treasurer
	(Principal Financial and Accounting Officer)
	Western Gas Holdings, LLC
	(as general partner of Western Gas Partners, LP)

          The foregoing certifications are being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, are not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and are not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.