8-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported): May 4, 2010

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware	001-34046	26-1075808
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(IRS Employer Identification No.)

1201 Lake Robbins Drive
The Woodlands, Texas 77380-1046
(Address of principal executive office) (Zip Code)

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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events

On February 3, 2010, Western Gas Partners, LP (the “Partnership”) filed a Current Report on Form 8-K (the “Initial Report”) to report, among other things, the closing of its acquisition of certain midstream assets from certain affiliates of Anadarko Petroleum Corporation (“Anadarko”), consisting of a 100% ownership interest in the following assets: (i) an approximately 750-mile natural gas gathering system and related compression and other ancillary equipment, known collectively as the “Granger gathering system,” located in Sublette, Lincoln, Uinta and Sweetwater Counties of Wyoming; and (ii) gas processing facilities with cryogenic capacity of 200 MMcf/d and combined refrigeration capacity of 145 MMcf/d with NGL fractionation located in Sweetwater County, Wyoming. These assets are referred to collectively as the “Granger Operations” and the acquisition as the “Granger Acquisition.” Consideration for the Granger Operations consisted of (i) $241.7 million in cash, which was funded with $210.0 million of borrowings under the Partnership’s revolving credit facility plus cash on hand, and (ii) the issuance of 620,689 common units and 12,667 general partner units to affiliates of Anadarko. The terms of the Granger Acquisition were unanimously approved by the Board of Directors of the Partnership’s general partner and by the Board’s special committee.

On March 26, 2010, the Partnership also filed a Current Report on Form 8-K/A (the “Amendment”) amending and supplementing the Initial Report to include the audited financial statements of the Granger Operations and the unaudited pro forma financial statements of the Partnership required by Items 9.01(a) and 9.01(b) of Form 8-K and to include exhibits under Item 9.01(d) of Form 8-K. No other modifications to the Initial Report were made by the Amendment.

Due to Anadarko’s control of the Partnership through its ownership of the general partner, the acquisition of the Granger Operations was considered a transfer of net assets between entities under common control. As a result, the Partnership is required to revise its financial statements to include the activities of the Granger Operations as of the date of common control. As such, Exhibits 12.1, 99.1, 99.2 and 99.3 included in this Current Report on Form 8-K give retroactive effect to the acquisition of the Granger Operations as if the Partnership owned the Granger Operations since August 23, 2006, the date Anadarko acquired the Granger Operations in conjunction with its acquisition of Western Gas Resources, Inc.

The Partnership’s Annual Report Form 10-K for the year ended December 31, 2009 (the “2009 Form 10-K”) as filed with the Securities and Exchange Commission (the “SEC”) on March 11, 2010 is hereby revised by this Current Report on Form 8-K as follows:

• The Computation of Ratio of Earnings to Fixed Charges of the Partnership included herein on Exhibit 12.1 supersedes Exhibit 12.1 of Item 15 in the 2009 Form 10-K.

• The Selected Financial and Operating Data of the Partnership included herein on Exhibit 99.1 supersedes Item 6 in the 2009 Form 10-K.

• The Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Partnership included herein on Exhibit 99.2 supersedes Item 7 in the 2009 Form 10-K.

• The Consolidated Financial Statements and Supplemental Quarterly Information of the Partnership included herein on Exhibit 99.3 supersede Item 8 in the 2009 Form 10-K, except for Management’s Assessment of Internal Control Over Financial Reporting and the Report of Independent Registered Public Accounting Firm with regard to internal control over financial reporting, included at pages F-2 and F-3 of the 2009 Form 10-K, respectively, which are not impacted by this Current Report on Form 8-K.

Other than the revisions noted above, we have made no attempt to revise any other sections of our 2009 Form 10-K.

This report is also being filed to provide the consolidated balance sheet of Western Gas Holdings, LLC as of December 31, 2009, which is included as Exhibit 99.4 to this Current Report on Form 8-K. Western Gas Holdings, LLC is the general partner of the Partnership. The consolidated balance sheet of Western Gas Holdings, LLC includes the net assets of the Granger Operations as if they were owned by the Partnership on December 31, 2009.

This Current Report on Form 8-K should be read in conjunction with the 2009 Form 10-K. Any references herein to Item 6 of the 2009 Form 10-K refer to Exhibit 99.1, references herein to Item 7 of the 2009 Form 10-K refer to Exhibit 99.2 and references to Item 8 of the 2009 Form 10-K refer to Exhibit 99.3. As of the date of this Current Report on Form 8-K, future references to the Partnership’s historical financial statements should be made to this Current Report and future quarterly and annual reports on Form 10-Q and Form 10-K, respectively.

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Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

12.1	Computation of Ratio of Earnings to Fixed Charges
23.1	Consent of Independent Registered Public Accounting Firm
23.2	Consent of Independent Registered Public Accounting Firm
99.1	Selected Financial and Operating Data
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations
99.3	Financial Statements and Supplementary Data
99.4	Consolidated Balance Sheet of Western Gas Holdings, LLC as of December 31, 2009

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SIGNATURE

     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 hereunto duly authorized.

	WESTERN GAS PARTNERS, LP
	By:	Western Gas Holdings, LLC, its general partner
Date: May 4, 2010	By:	/s/ Donald R. Sinclair
		Donald R. Sinclair
		President and Chief Executive Officer

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EXHIBIT INDEX

Exhibit
Number	Description
12.1	Computation of Ratio of Earnings to Fixed Charges
23.1	Consent of Independent Registered Public Accounting Firm
23.2	Consent of Independent Registered Public Accounting Firm
99.1	Selected Financial and Operating Data
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations
99.3	Financial Statements and Supplementary Data
99.4	Consolidated Balance Sheet of Western Gas Holdings, LLC as of December 31, 2009

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EX-12.1

Exhibit 12.1

WESTERN GAS PARTNERS, LP
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2009			2008			2007			2006			2005
	(dollars in thousands)
Earnings:
Income before income taxes	$	107,511		$	147,744		$	113,646		$	29,003		$	11,899
Add: Fixed charges		10,331			880			6,712			10,411			9,795
Distributions from equity investee		5,487			5,128			1,349			741			—
Amortization of capitalized interest		248			6			—			—			—
Less: Equity income		6,982			4,736			4,017			1,360			—
Earnings	$	116,595		$	149,022		$	117,690		$	38,795		$	21,694
Fixed charges:
Interest expense	$	9,955		$	364		$	6,187		$	9,515		$	8,650
Interest component of lease expense		376			516			525			896			1,145
Fixed charges	$	10,331		$	880		$	6,712		$	10,411		$	9,795
Ratio of earnings to fixed charges		11.3	x		169.3	x		17.5	x		3.7	x		2.2	x

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EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):

We consent to the incorporation by reference in the registration statements on Form S-3 (No. 333-160000) and Form S-8 (No. 333-151317) of Western Gas Partners, LP of our report dated May 4, 2010, with respect to the consolidated balance sheets of Western Gas Partners, LP as of December 31, 2009 and 2008, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2009, which report appears in the Current Report on Form 8-K dated May 4, 2010, which references our report dated March 11, 2010 with respect to the effectiveness of internal control over financial reporting as of December 31, 2009, which report appears in the December 31, 2009 annual report on Form 10-K of Western Gas Partners, LP.

/s/ KPMG LLP  

Houston, Texas
May 4, 2010

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EX-23.2

     Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):

We consent to the incorporation by reference in the registration statements on Form S-3 (No. 333-160000) and Form S-8 (No. 333-151317) of Western Gas Partners, LP of our report dated May 4, 2010, with respect to the consolidated balance sheet of Western Gas Holdings, LLC as of December 31, 2009.

/s/ KPMG LLP  

Houston, Texas
May 4, 2010

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EX-99.1

Exhibit 99.1

Item 6. Selected Financial and Operating Data

The following table shows our selected financial and operating data, which are derived from our consolidated financial statements, for the periods and as of the dates indicated. In May 2008, we closed our initial public offering. Concurrent with the closing of the offering, Anadarko contributed to us the assets and liabilities of AGC, PGT and MIGC, which we refer to as our “initial assets.” In December 2008, we closed the Powder River acquisition with Anadarko and in July 2009, we closed the Chipeta acquisition with Anadarko. In January 2010, we closed the Granger acquisition with Anadarko, and the assets and operations of the Granger assets are reflected herein on a retroactive basis. Anadarko acquired MIGC, the Powder River assets and the Granger assets in connection with its August 23, 2006 acquisition of Western, and acquired the Chipeta assets in connection with its August 10, 2006 acquisition of Kerr-McGee.

Our acquisition of the initial assets, the Powder River acquisition, the Chipeta acquisition and the Granger acquisition are considered transfers of net assets between entities under common control. Accordingly, our consolidated financial statements include (i) the combined financial results and operations of AGC and PGT from their inception through the closing date of our initial public offering and (ii) the consolidated financial results and operations of Western Gas Partners, LP and its subsidiaries from the closing date of our initial public offering thereafter, combined with (a) the financial results and operations of MIGC, the Powder River assets and the Granger assets, from August 23, 2006 thereafter, and (b) the financial results and operations of the Chipeta assets, from August 10, 2006 thereafter.

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The information in the following table should be read together with Item 7 of this annual report.

	Summary Financial Information
	2009(1)			2008(1)			2007(1)			2006(1)			2005
	(in thousands, except per unit data, throughput and gross margin per Mcf)
Statement of Income Data (for the year ended):
Total revenues	$	371,223		$	579,950		$	463,155		$	183,207		$	71,650
Costs and expenses		220,125			387,766			299,715			120,503			35,720
Depreciation, amortization and impairment		51,090			55,876			43,592			24,160			15,447
Total operating expenses		271,215			443,642			343,307			144,663			51,167
Operating income		100,008			136,308			119,848			38,544			20,483
Interest income (expense), net		7,449			11,240			(6,187	)		(9,515	)		(8,650	)
Other income (expense), net		54			196			(15	)		(26	)		66
Income tax expense (2)		6,975			32,255			39,637			9,168			4,789
Net income		100,536			115,489			74,009			19,835			7,110
Net income (loss) attributable to noncontrolling interests		10,260			7,908			(92	)		—			—
Net income attributable to Western Gas Partners, LP	$	90,276		$	107,581		$	74,101		$	19,835		$	7,110
Key Performance Measures (for the year ended):
Gross margin (3)	$	246,310		$	285,499		$	236,327		$	108,502		$	65,643
Adjusted EBITDA(4)		141,563			185,078			160,772			62,085			35,930
Distributable cash flow (4)		128,014			173,838			n/a			n/a			n/a
General partner’s interest in net income (5)		1,428			842			n/a			n/a			n/a
Common unitholders’ interest in net income (5)		37,035			20,841			n/a			n/a			n/a
Subordinated unitholders’ interest in net income (5)		32,945			20,420			n/a			n/a			n/a
Net income per common unit (basic and diluted)	$	1.25		$	0.78			n/a			n/a			n/a
Net income per subordinated unit (basic and diluted)	$	1.24		$	0.77			n/a			n/a			n/a
Distributions per unit	$	1.23		$	0.46			n/a			n/a			n/a
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	993,377		$	982,813		$	904,813		$	782,297		$	200,451
Total assets		1,387,923			1,344,458			956,235			833,604			206,373
Total long-term liabilities		282,968			282,832			236,888			238,830			37,664
Total partners’ capital and equity	$	1,078,699		$	1,006,204		$	692,686		$	578,386		$	160,585
Cash Flow Data (for the year ended):
Net cash provided by (used in):
Operating activities	$	135,532		$	185,922		$	130,206		$	43,473		$	30,131
Investing activities		(171,321	)		(552,585	)		(149,013	)		(46,843	)		(21,076	)
Financing activities		69,699			402,737			18,349			3,824			(9,067	)
Capital expenditures	$	69,488		$	109,490		$	142,613		$	46,843		$	20,841
Operating Data (volumes in MMcf/d):
Gathering and transportation throughput		883			967			987			971			798
Processing throughput (6)		637			524			323			409			—
Equity investment throughput (7)		120			112			84			—			—
Total throughput		1,640			1,603			1,394			1,380			798
Throughput attributable to noncontrolling interests		180			124			—			—			—
Throughput attributable to Western Gas Partners, LP		1,460			1,479			1,394			1,380			798
Average gross margin per Mcf (8)	$	0.41		$	0.49		$	0.46		$	0.26		$	0.22
Average gross margin per Mcf attributable to Western Gas Partners, LP	$	0.43		$	0.50		$	0.46		$	0.26		$	0.22

(1)

Financial information for 2009 has been revised to include results attributable to the Granger acquisition and financial information for 2008, 2007 and 2006 has been revised to include results attributable to Granger acquisition and the Chipeta acquisition. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.

(2)

Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, during the time periods including and subsequent to our acquisition of the Partnerships Assets, except for Chipeta, was subject only to Texas

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	margin tax, while income earned during periods prior to our acquisition of the Partnership Assets, except for Chipeta, was subject to federal and state income tax. Income attributable to Chipeta was subject to federal and state income tax for periods prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes. See Note 6—Transactions with Affiliates of the notes to the consolidated financial statements in under Item 8 of this annual report.
(3)	We define gross margin as total revenues less cost of product.
(4)	Adjusted EBITDA and distributable cash flow are not defined in GAAP. For descriptions and reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see the caption How We Evaluate Our Operations under Item 7 of this annual report. We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2008 and, as such, did not differentiate between maintenance and capital expenditures prior to 2008.
(5)	The Partnership’s net income attributable to the Partnership Assets for periods including and subsequent to the Partnership’s acquisitions of the Partnership Assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages. Prior to our acquisition of the Partnership Assets, all income is attributed to the Parent. See Note 5—Net Income per Limited Partner Unit of the notes to the consolidated financial statements under Item 8 of this annual report.
(6)	Processing throughput includes 100% of Chipeta system volumes and 50% of Newcastle system volumes.
(7)	Equity investment throughput represents the Partnership’s 14.81% share of Fort Union’s gross volumes.
(8)	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 14.81% interest in income and volumes attributable to Fort Union.

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EX-99.2

Exhibit 99.2

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

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

OPERATING AND FINANCIAL HIGHLIGHTS

We achieved significant milestones during 2009. Significant operational and financial highlights include:

• In July 2009, we acquired a 51% membership interest in Chipeta Processing LLC, or “Chipeta,” together with related midstream assets from Anadarko.

• In October 2009, we entered into a three-year senior unsecured revolving credit facility with aggregate initial commitments of $350.0 million. This revolving credit facility matures in October 2012 and bears interest at a variable rate.

• In December 2009, we issued 6,900,000 common units at a price of $18.20 per unit to the public. Net proceeds from the offering of approximately $122.5 million were used to repay $100.0 million outstanding under our revolving credit facility and to partially fund the January 2010 Granger acquisition.

• Our stable operating cash flow along with our Chipeta acquisition, combined with a focus on cost reduction and capital spending discipline, enabled us to raise our distribution over three consecutive quarters to $0.33 per unit for the fourth quarter of 2009, representing a 10.0% increase over the distribution for the fourth quarter of 2008.

• Although the current commodity price environment, particularly for natural gas, has resulted in lower drilling activity throughout the areas in which we operate, related throughput decreases were offset by throughput increases at the Chipeta plant and Fort Union system due to facility expansions. The total throughput attributable to Western Gas Partners, LP, for the year ended December 31, 2009, was approximately 1,460 MMcf/d, representing an approximate 1% decrease compared to the year ended December 31, 2008.

ACQUISITIONS

Concurrent with the closing of the initial public offering in May 2008, Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to us in exchange for a 2.0% general partner interest, 100% of the IDRs, 5,725,431 common units and 26,536,306 subordinated units. In connection with the Powder River acquisition in December 2008, Anadarko contributed the Powder River assets to us for consideration consisting of $175.0 million in cash, which was funded by a note from Anadarko, 2,556,891 common units and 52,181 general partner units. In connection with the Chipeta acquisition in July 2009, Anadarko contributed the Chipeta assets to us for consideration consisting of $101.5 million in cash, which was funded by a note from Anadarko, 351,424 common units and 7,172 general partner units. In November 2009, Chipeta closed its $9.1 million acquisition from a third party of the Natural Buttes plant. In connection with the Granger acquisition in January 2010, Anadarko contributed the Granger assets to us for consideration consisting of $241.7 million in cash, which was funded with $210.0 million of borrowings under our revolving credit facility and $31.7 million of cash on hand, as well as the issuance of 620,689 common units to Anadarko and 12,667 general partner units to our general partner. See the caption Acquisitions under Items 1 and 2 of this annual report for additional transaction and asset descriptions.

Because Anadarko owns the Partnership’s general partner, each acquisition of Partnership Assets, except the Natural Buttes plant, was considered a transfer of net assets between entities under common control. As a result, after each acquisition of assets from Anadarko, we are required to revise our financial statements to include the activities of those assets as of the date of common control. Our historical financial statements for the years ended December 31, 2008 and 2007 as presented in our annual report on Form 10-K for the year ended December 31, 2008, included the results attributable to the Powder River assets. The financial statements as presented herein have been further recast to reflect the results attributable to the Chipeta assets and the Granger assets as if the Partnership owned the 51% interest in Chipeta, the associated NGL pipeline and the Granger assets for all periods presented. The following tables present the impact to the consolidated statements of income attributable to the Chipeta assets and the Granger assets (in thousands):

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	Partnership			Chipeta			Granger
	Historical			Acquisition			Acquisition		Combined
	Year Ended December 31, 2009
Revenues	$	245,119			n/a	(1)	$	126,104	$	371,223
Operating expenses		164,489			n/a			106,726		271,215
Operating income		80,630			n/a			19,378		100,008
Interest and other income, net		6,987			n/a			516		7,503
Income before income taxes		87,617			n/a			19,894		107,511
Income tax expense		12			n/a			6,963		6,975
Net income		87,605			n/a			12,931		100,536
Net income attributable to noncontrolling interests		10,260			n/a			—		10,260
Net income attributable to Western Gas Partners, LP	$	77,345			n/a		$	12,931	$	90,276
	Year Ended December 31, 2008
Revenues	$	311,648		$	32,858		$	235,444	$	579,950
Operating expenses		241,931			16,408			185,303		443,642
Operating income		69,717			16,450			50,141		136,308
Interest and other income, net		9,336			51			2,049		11,436
Income before income taxes		79,053			16,501			52,190		147,744
Income tax expense		13,777			211			18,267		32,255
Net income		65,276			16,290			33,923		115,489
Net income attributable to noncontrolling interests		—			7,908			—		7,908
Net income attributable to Western Gas Partners, LP	$	65,276		$	8,382		$	33,923	$	107,581
	Year Ended December 31, 2007
Revenues	$	261,493		$	—		$	201,662	$	463,155
Operating expenses		197,475			304			145,528		343,307
Operating income (loss)		64,018			(304	)		56,134		119,848
Interest and other expense, net		(7,820	)		—			1,618		(6,202	)
Income (loss) before income taxes		56,198			(304	)		57,752		113,646
Income tax expense (benefit)		19,540			(116	)		20,213		39,637
Net income (loss)		36,658			(188	)		37,539		74,009
Net loss attributable to noncontrolling interests		—			(92	)		—		(92	)
Net income attributable to Western Gas Partners, LP	$	36,658		$	(96	)	$	37,539	$	74,101

⁽¹⁾ The Partnership Historical information for 2009 includes the results attributable to the Chipeta acquisition since the results attributable to Chipeta were included in the amounts reported in the Partnership’s annual report on Form 10-K.

OUR OPERATIONS

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements, and the notes thereto, included in Item 8 and Item 1A of this annual report. 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. Unless the context otherwise requires, references to “we,” “us,” “our,” “the Partnership” or “Western Gas Partners” are intended to refer (i) to the business and operations of AGC and PGT from their inception through the closing date of our initial public offering and (ii) to Western Gas Partners, LP and its subsidiaries thereafter, combined with (a)  the business and operations of MIGC, the Powder River assets and the Granger assets since August 23, 2006 and (b) the business and operations of the Chipeta assets since August 10, 2006. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner, and “Parent” refers to Anadarko prior to our acquisition of assets from Anadarko. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership.

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

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periods including and subsequent to May 2008, with respect to the initial assets, periods including and subsequent to December 2008, with respect to the Powder River assets, periods including and subsequent to July 2009, with respect to the Chipeta assets, and periods including and subsequent to January 2010, with respect to the Granger assets.

Our results are driven primarily by the volumes of natural gas we gather, compress, process, treat or transport through our systems. For the year ended December 31, 2009, approximately 88% of our total revenues and 74% of our gathering, processing and transportation throughput volumes were attributable to transactions entered into with Anadarko.

In our gathering operations, we contract with producers and customers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering lines through which natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end users. We also treat a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation.

Effective January 1, 2008 and solely with respect to the gathering systems connected to our initial assets, we received a significant dedication from our largest customer, Anadarko. Specifically, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to such gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to such gathering systems, as those systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to these gathering systems.

Based on gross margin for the year ended December 31, 2009, approximately 71% of our services are provided pursuant to fee-based contracts under which we are paid a fixed fee based on the volume and thermal content of the natural gas we gather, process, compress, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead. Certain of our fee-based contracts contain keep-whole provisions.

Based on gross margin for the year ended December 31, 2009, approximately 24% of our services are provided pursuant to percent-of-proceeds and keep-whole contracts pursuant to which we have commodity price exposure. We have fixed-price swap agreements with Anadarko to manage the commodity price risk inherent in substantially all of our percent-of-proceeds and keep-whole contracts. See Note 6—Transactions with Affiliates of the notes to the consolidated financial statements included under Item 8 of this annual report.

For the year ended December 31, 2009, approximately 2% of our gross margin is attributable to drip condensate and approximately 3% of our gross margin is attributable to equity income from our interest in Fort Union, changes in our imbalance positions and other revenue.

We also have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering, compressing, treating, processing and transporting by our systems. We also bear a limited degree of commodity price risk through settlement of natural gas imbalances. Please read Item 7A of this annual report.

We provide a significant portion of our transportation services on our MIGC system through firm contracts that obligate our customers to pay a monthly reservation or demand charge, which is a fixed charge applied to firm contract capacity and owed by a customer regardless of the actual pipeline capacity used by that customer. When a customer uses the capacity it has reserved under these contracts, we are entitled to collect an additional commodity usage charge based on the actual volume of natural gas transported. These usage charges are typically a small percentage of the total revenues received from our firm capacity contracts. We also provide transportation services through interruptible contracts, pursuant to which a fee is charged to our customers based upon actual volumes transported through the pipeline.

As a result of our initial public offering, the Powder River acquisition, the Chipeta acquisition and the Granger acquisition, the results of operations, financial condition and cash flows vary significantly for 2009 and 2008 as compared to periods ending prior to our initial public offering. Please see the caption Items Affecting the Comparability of Our Financial Results, set forth below in this Item 7.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput, (2) gross margin, (3) operating and maintenance expenses, (4) general and administrative expenses, (5) Adjusted EBITDA and (6) distributable cash flow.

Throughput. Throughput is the most important operational variable in assessing our ability to generate revenues. In order to maintain or increase throughput on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by successful drilling of new wells by producers that are dedicated

3

to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors. During the year ended December 31, 2009, we added 57 receipt points to our systems with average initial throughput of approximately 3.8 MMcf/d per receipt point.

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

Gross margin. We define gross margin as total revenues less cost of product. We consider gross margin to provide information useful in assessing our results of operations and our ability to internally fund capital expenditures and to service or incur additional debt. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds and keep-whole processing contracts, (ii) costs associated with the valuation of our gas imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers which is thermally equivalent to condensate retained by us and sold to third parties and (iv) costs associated with our fuel-tracking mechanism, which tracks the difference between actual fuel usage and loss, and amounts recovered for estimated fuel usage and loss pursuant to our contracts. These expenses are subject to variability, although our exposure to commodity price risk attributable to our percent-of-proceeds and keep-whole contracts is mitigated through our commodity price swap agreements with Anadarko.

Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of such costs on the profitability of our assets and to evaluate the overall efficiency of our operations. Operation and maintenance expenses include, among other things, field labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf. For periods commencing on and subsequent to our acquisition of the Partnership Assets, certain of these expenses are incurred under and governed by our services and secondment agreement with Anadarko.

General and administrative expenses. To help ensure the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses through comparison to prior periods, the annual budget approved by our general partner’s board of directors, as well as to general and administrative expenses incurred by similar midstream companies. General and administrative expenses for periods prior to our acquisition of the Partnership Assets include reimbursements attributable to costs incurred by Anadarko and the general partner on our behalf and allocations of general and administrative costs by Anadarko and the general partner to us. For these periods, Anadarko received compensation or reimbursement through a management services fee. For periods subsequent to our acquisition of the Partnership Assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, we reimburse Anadarko for general and administrative expenses it and the general partner incur on our behalf pursuant to the terms of our omnibus agreement with Anadarko. Amounts required to be reimbursed to Anadarko under the omnibus agreement include those expenses attributable to our status as a publicly traded partnership, such as:

• expenses associated with annual and quarterly reporting;

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

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

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

In addition to the above, we are required pursuant to the terms of the omnibus agreement with Anadarko to reimburse Anadarko for allocable general and administrative expenses. The amount required to be reimbursed by us to Anadarko for certain allocated general and administrative expenses was capped at $6.9 million for the year ended December 31, 2009. In connection with the January 2010 Granger acquisition, the cap under the omnibus agreement was increased to $8.3 million for the year ended December 31, 2010, subject to adjustment to reflect expansions of our operations through the acquisition or construction of new assets or businesses and with the concurrence of the special committee of our general partner’s board of directors. If the omnibus agreement is not further amended by the parties, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement for periods subsequent to December 31, 2010. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses incurred by or allocated to us as a result of being a separate publicly traded entity. Public company expenses not subject to the cap contained in the omnibus agreement, excluding equity-based compensation, were $7.5 million and $4.5 million for the years ended December 31, 2009 and 2008, respectively.

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

4

expense, income tax expense, depreciation and amortization, less income from equity investments, interest income, income tax benefit and other income (expense).

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess, 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.

Distributable cash flow. We define “distributable cash flow” as Adjusted EBITDA, plus interest income, less net cash paid for interest expense, maintenance capital expenditures, and income taxes. We use distributable cash flow to 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. We believe this measure 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 did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2008 and, as such, did not differentiate between maintenance and capital expenditures prior to 2008 and do not report distributable cash flow for periods prior to 2008.

Distributable cash flow should not be considered an alternative to net income, earnings per unit, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. 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.

Reconciliation to GAAP measures. Adjusted EBITDA and distributable cash flow are not defined in GAAP. The GAAP measures most directly comparable to Adjusted EBITDA are net income attributable to Western Gas Partners, LP and net cash provided by operating activities and the GAAP measure most directly comparable to distributable cash flow is net income attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net income attributable to Western Gas Partners, LP or net cash provided by operating activities. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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.

5

The following tables present 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 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:

	Year Ended December 31,
	2009(1)			2008(1)			2007(1)
	(in thousands)
Reconciliation of Adjusted EBITDA to net income attributable to Western Gas Partners, LP
Adjusted EBITDA	$	141,563		$	185,078		$	160,772
Less:
Distributions from equity investee		5,487			5,128			1,349
Non-cash equity-based compensation expense		3,580			1,924			—
Expenses in excess of omnibus cap		842			—			—
Interest expense, net		9,955			364			6,187
Income tax expense(2)		6,975			32,198			39,694
Depreciation and amortization (2)		48,883			45,048			43,443
Impairment		—			9,354			—
Other expense, net		—			—			15
Add:
Equity income, net		6,982			4,736			4,017
Interest income, net		17,404			11,604			—
Other income, net (2)		49			179			—
Net income attributable to Western Gas Partners, LP	$	90,276		$	107,581		$	74,101
Reconciliation of Adjusted EBITDA to net cash provided by operating activities
Adjusted EBITDA	$	141,563		$	185,078		$	160,772
Adjusted EBITDA attributable to noncontrolling interests		12,462			9,422			—
Interest income (expense), net		7,449			11,240			(6,187	)
Expenses in excess of omnibus cap		(842	)		—			—
Non-cash equity-based compensation expense		(3,580	)		(1,924	)		—
Current income tax expense		(8,641	)		(31,204	)		(30,654	)
Other income (expense), net		54			196			(15	)
Distributions from equity investee less than (in excess of) equity income, net		1,495			(392	)		2,668
Changes in assets and liabilities:
Accounts receivable and natural gas imbalances		3,342			(6,101	)		(4,327	)
Accounts payable and accrued expenses		(17,626	)		19,000			9,280
Other, including changes in non-current assets and liabilities		(144)			607			(1,331	)
Net cash provided by operating activities	$	135,532		$	185,922		$	130,206

(1)

Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 and 2007 has been revised to include results attributable to the Chipeta assets and the Granger assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.

(2)

Includes the Partnership’s 51% share of depreciation and amortization, other income, net and income tax expense attributable to Chipeta.

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	Year Ended
	December 31,
	2009(1)		2008(1)
	(in thousands)
Reconciliation of distributable cash flow to net income attributable to Western Gas Partners, LP
Distributable cash flow	$	128,014	$	173,838
Less:
Distributions from equity investee		5,487		5,128
Non-cash share-based compensation expense		3,580		1,924
Expenses in excess of omnibus cap		842		—
Income tax expense (2)		6,975		32,198
Depreciation and amortization (2)		48,883		45,048
Impairments		—		9,354
Add:
Equity income, net		6,982		4,736
Cash paid for maintenance capital expenditures(2)		20,494		21,579
Interest income, net (non-cash settled)		504		901
Other income, net (2)		49		179
Net income attributable to Western Gas Partners, LP	$	90,276	$	107,581

(1)

Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 has been revised to include results attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.

(2)

Includes the Partnership’s 51% share of depreciation and amortization expense, other income, net, cash paid for maintenance capital expenditures and income tax expense attributable to Chipeta.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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

General and Administrative Expenses under the 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. Prior to our ownership of the Partnership Assets, our historical consolidated financial statements reflect a management services fee representing the general and administrative expenses attributable to the Partnership Assets. During the years ended December 31, 2009 and 2008, Anadarko billed us $6.9 million and $3.4 million, respectively, in allocated general and administrative expenses subject to the cap contained in the omnibus agreement. This amount is greater than amounts allocated to us by Anadarko for the aggregate management services fees reflected in our historical consolidated financial statements for periods prior to our ownership of the Partnership Assets and will increase in future periods as we acquire additional assets. In addition, our general and administrative expenses for the year ended December 31, 2009, included $0.8 million of expenses incurred by Anadarko and the general partner in excess of the cap contained in the omnibus agreement. Such expenses were recorded as a capital contribution from Anadarko and did not impact the Partnership’s cash flows. We also incurred $7.5 million and $4.5 million in public company expenses, excluding equity-based compensation, during the years ended December 31, 2009 and 2008, respectively. We did not incur public company expenses prior to our initial public offering in May 2008.

Interest expense on intercompany balances. For periods prior to our acquisition of the Partnership Assets, except for Chipeta, we incurred interest expense or earned interest income on current intercompany balances with Anadarko related to such assets. These intercompany balances were extinguished through non-cash transactions in connection with the closing of our initial public offering, the Powder River acquisition, Anadarko’s initial contribution of assets to Chipeta and the Granger acquisition. Therefore, interest expense and interest income attributable to these balances is reflected in our historical consolidated financial statements for the periods ending prior to our acquisition of the Partnership Assets, except for Chipeta, and for periods ending prior to June 1, 2008 (the date on which Anadarko initially contributed assets to Chipeta), with respect to Chipeta.

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

Term loan agreements and revolving credit agreement. In connection with the Powder River acquisition in December 2008, we entered into a five-year, $175.0 million term loan agreement with Anadarko, under which we pay interest at a fixed rate of 4.00% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. In connection with the Chipeta acquisition in July 2009, we entered into a three-year, 7.00% fixed rate, $101.5 million term loan agreement with Anadarko. In October 2009, we borrowed $100.0 million under our new revolving credit facility and used $2.0 million of cash on hand to refinance the $101.5 million three-year term loan with Anadarko and related accrued interest. In December 2009, we issued 6.9 million common units in connection with our 2009 equity offering and repaid the $100.0 million outstanding under our revolving credit facility. In January 2010, we borrowed $210.0 million under the revolving credit facility to partially fund the Granger acquisition. Interest expense on our notes and credit facilities will be incurred so long as debt remains outstanding.

Cash management. We expect to rely upon external financing sources, including commercial bank borrowings and long-term debt and equity issuances, to fund our acquisitions and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements. Prior to our acquisition of the Partnership Assets, except for Chipeta, all affiliate transactions related to such assets were net settled within our consolidated financial statements and were funded by Anadarko’s working capital. Effective on the date of our acquisition of the Partnership Assets, except for Chipeta, all affiliate and third-party transactions related to such assets are funded by our working capital. Prior to June 1, 2008 with respect to Chipeta, sales and purchases related to third-party transactions were received or paid in cash by Anadarko within the centralized cash management system and were settled with Chipeta through an adjustment to parent net investment. Subsequent to June 1, 2008, Chipeta cash-settled transactions directly with third parties and with Anadarko affiliates. This impacts the comparability of our cash flow statements, working capital analysis and liquidity.

Commodity price swap agreements. Our financial results for historical periods reflect commodity price changes, which, in turn, impact the financial results derived from our percent-of-proceeds and keep-whole processing contracts. Effective January 1, 2009, substantially all commodity price risk associated with our percent-of-proceeds and keep-whole processing contracts at the Hilight and Newcastle systems has been mitigated through our fixed-price commodity price swap agreements with Anadarko that extend through December 31, 2011, with an option to extend through 2013. Beginning on January 1, 2010, commodity price swap agreements were put in place to fix the margin we realize under both keep-whole and percentage-of-proceeds contracts applicable to natural gas processing activities at the Granger system. The commodity price swap arrangements for the Granger system expire in December 2014. See Note 6—Transactions with Affiliates and Note 13—Subsequent Events—Granger Acquisition of the notes to the consolidated financial statements included under Item 8 in this annual report.

Federal income taxes. We are generally not subject to federal or state income tax other than Texas margin tax. Federal and state income tax expense was recorded for periods ending prior to our acquisition of the Partnerships Assets, except for Chipeta. For periods including and subsequent to our acquisition of the Partnerships Assets, except for Chipeta, we are no longer subject to federal income tax and are only subject to Texas margin tax; therefore, income tax expense attributable to Texas margin tax will continue to be recognized in our consolidated financial statements. Income attributable to Chipeta was subject to federal and state income tax for periods prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes. We are required to make payments to Anadarko pursuant to a tax sharing agreement for our share of Texas margin tax included in any combined or consolidated returns of Anadarko.

Distributions. We made cash distributions to our unitholders and our general partner following our initial public offering in May 2008. During the years ended December 31, 2009 and 2008, the Partnership paid cash distributions to its unitholders of approximately $70.1 million and $24.8 million, respectively. On January 21, 2010, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.33 per unit for the three months ended December 31, 2009, which equates to approximately $21.4 million per full quarter, or approximately $85.6 million per full year, based on the number of common, subordinated and general partner units outstanding as of March 1, 2010.

Equity-based compensation plans. In connection with the closing of our initial public offering, our general partner adopted two new compensation plans: the Western Gas Partners, LP 2008 Long-Term Incentive Plan, or “LTIP,” and the Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan, or the “Incentive Plan.” Phantom unit grants have been made under the LTIP and incentive unit grants have been made under the Incentive Plan. These grants result in equity-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. For periods ending prior to May 14, 2008, equity-based compensation expense attributable to the LTIP and Incentive Plan is not reflected in our historical consolidated financial statements as there were no outstanding equity grants under either plan. For periods

8

including and subsequent to May 14, 2008, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko and the general partner to the Partnership for grants made under the LTIP and Incentive Plan as well as under the Anadarko Petroleum Corporation 1999 Stock Incentive Plan and the Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”). Equity-based compensation expense attributable to grants made under the LTIP will impact our cash flows from operating activities only to the extent cash payments are made to a participant in lieu of the actual issuance of common units to the participant upon the lapse of the relevant vesting period. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact our cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants who provided services to us pursuant to the omnibus agreement and such cash payments do not cause total annual reimbursements made by us to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth in that agreement for the periods to which such expense limit applies. Equity-based compensation granted under the Anadarko Incentive Plans does not impact our cash flow from operating activities. See equity-based compensation discussion included in Note 2 — Summary of Significant Accounting Policies and Note 6—Transactions with Affiliates of the notes to the consolidated financial statements included under Item 8 of this annual report.

Gas gathering agreements. For periods ending prior to January 1, 2008, our consolidated financial statements reflect the gathering fees we historically charged Anadarko under our affiliate cost-of-service-based arrangements with respect to the initial assets. Under these arrangements, we recovered, on an annual basis, our operation and maintenance, general and administrative and depreciation expenses in addition to earning a return on our invested capital. Effective January 1, 2008, we entered into new 10-year gas gathering agreements with Anadarko with respect to the initial assets. Pursuant to the terms of the new agreements, our fees for gathering and treating services rendered to Anadarko increased. The new fees were based on capital improvements and changes in our cost-of-service analysis. This increase was also due, in part, to compensate us for additional operation and maintenance expense that we incur as a result of us bearing all of the cost of employee benefits specifically identified and related to operational personnel working on our assets, as compared to bearing only those employee benefit costs reasonably allocated by Anadarko to us for the periods ending prior to January 1, 2008. Because our new gas gathering agreements are designed to fully recover these incremental costs, our revenues increased by an amount approximately equal to the incremental operation and maintenance expense. Although this change in methodology for computing affiliate gathering rates does not impact our net cash flows or net income, this methodology change impacts the components thereof as compared to periods ending prior to January 1, 2008. If we applied the methodology employed under our new gas gathering agreements with Anadarko to the year ended December 31, 2007, we estimate our historic gathering revenues and operation and maintenance expense would have increased by $3.1 million and our cash flow from operations would have remained unchanged.

Granger gas processing agreements. Effective October 1, 2009, contracts covering substantially all of the Granger assets’ affiliate throughput were converted from primarily keep-whole contracts into 10-year fee-based arrangements.

GENERAL TRENDS AND OUTLOOK

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

Impact of natural gas prices. The recent natural gas price environment has resulted in lower drilling activity, resulting in fewer new well connections and, in some cases, temporary curtailments of production throughout areas in which we operate. A continued low gas price environment may result in further reductions in drilling activity or temporary curtailments of production. We have no control over this activity. In addition, the recent or further decline in commodity prices could affect production rates and the level of capital invested by Anadarko and third parties in the exploration for and development of new natural gas reserves. To the extent opportunities are available, we will continue to connect new wells to our systems to mitigate the impact of natural production declines in order to maintain throughput on our systems. However, our success in connecting new wells to our systems is dependent on activities of natural gas producers and shippers.

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

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

9

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

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

Acquisition opportunities. As of December 31, 2009, Anadarko’s total domestic midstream asset portfolio, excluding assets we own and the Granger system, consisted of 12 gathering systems with an aggregate throughput of approximately 1.9 Bcf/d, and 10 processing and/or treating facilities. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time. In December 2008, we acquired the Powder River assets from Anadarko, in July 2009, we acquired the Chipeta assets from Anadarko and in January 2010, we acquired the Granger assets from Anadarko. As of December 31, 2009, Anadarko owns a 2.0% general partner interest in us, all of our IDRs and a 54.8% limited partner interest in us. Given Anadarko’s significant interests in us, we believe Anadarko will benefit from selling additional assets to us over time; however, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire or construct those assets. Should Anadarko choose to pursue additional midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. We may also pursue certain asset acquisitions from third parties to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s or third-party production. However, if we do not make additional acquisitions from Anadarko or third parties on economically acceptable terms, our future growth will be limited, and the acquisitions we make could reduce, rather than increase, our cash generated from operations on a per-unit basis.

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RESULTS OF OPERATIONS — OVERVIEW

OPERATING RESULTS

The following table and discussion presents a summary of our results of operations for the years ended December 31, 2009, 2008 and 2007:

	Year Ended December 31,
	2009(1)		2008(1)		2007(1)
	(in thousands)
Revenues
Gathering, processing and transportation of natural gas	$	173,795	$	160,454	$	127,330
Natural gas, natural gas liquids and condensate sales		187,593		402,274		327,249
Equity income and other, net		9,835		17,222		8,576
Total revenues		371,223		579,950		463,155
Operating expenses (2)
Cost of product		124,913		294,451		226,828
Operation and maintenance		60,613		64,249		52,867
General and administrative		24,306		20,089		12,680
Property and other taxes		10,293		8,977		7,340
Depreciation and amortization		51,090		46,522		43,592
Impairment		—		9,354		—
Total operating expenses		271,215		443,642		343,307
Operating income		100,008		136,308		119,848
Interest income (expense), net		7,449		11,240		(6,187	)
Other income (expense), net		54		196		(15	)
Income before income taxes		107,511		147,744		113,646
Income tax expense		6,975		32,255		39,637
Net income		100,536		115,489		74,009
Net income (loss) attributable to noncontrolling interests		10,260		7,908		(92	)
Net income attributable to Western Gas Partners, LP	$	90,276	$	107,581	$	74,101
Gross margin(3)	$	246,310	$	285,499	$	236,327
Adjusted EBITDA(3)		141,563		185,078		160,772
Distributable cash flow(3)		128,014		173,838		n/a

(1)	Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 and 2007 has been revised to include results attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.
(2)	Operating expenses include amounts charged by affiliates to us for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 6—Transactions with Affiliates of the notes to the consolidated financial statements under Item 8 of this annual report.
(3)	Gross margin, Adjusted EBITDA and distributable cash flow are defined above under the caption How we Evaluate Our Operations within this Item 7. Such caption also includes reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable measures calculated and presented in accordance with GAAP.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2009” refer to the comparison of the year ended December 31, 2009 to the year ended December 31, 2008. Similarly, any increases or decreases “for the year ended December 31, 2008” refer to the comparison of the year ended December 31, 2008 to the year ended December 31, 2007.

11

Executive Summary

Total revenues decreased by $208.7 million for the year ended December 31, 2009 and increased by $116.8 million for the year ended December 31, 2008. Gathering, processing and transportation revenues increased by $13.4 million; natural gas, NGL and condensate revenues decreased by $214.7 million and equity income and other revenues decreased by $7.4 million for the year ended December 31, 2009. Gathering, processing and transportation revenues increased by $33.1 million; natural gas, NGL and condensate revenues increased by $75.0 million and equity income and other revenues increased by $8.7 million for the year ended December 31, 2008.

Net income attributable to Western Gas Partners, LP decreased by $17.3 million for the year ended December 31, 2009, consisting of a $208.7 million decrease in revenues, a $3.8 million decrease in interest income, net due to an increase in interest expense from additional borrowings and a $2.4 million increase in net income attributable to noncontrolling interests due to increased Chipeta income, substantially offset by a $172.4 million decrease in total operating expenses primarily due to an $169.5 million decrease in cost of product from lower volumes and prices and a $25.3 million decrease in income tax expense.

Net income attributable to Western Gas Partners, LP increased by $33.5 million for the year ended December 31, 2008 consisting of a $116.8 million increase in total revenues driven by gathering rate increases, increased processing volumes, increased condensate sales, and an increase in other revenues from changes in gas imbalance positions and gas prices; a $17.4 million increase in interest income, net and a $7.4 million decrease in income tax expense. These items are partially offset by a $67.6 million increase in cost of product expense primarily from higher volumes and prices, an $8.0 million increase in net income attributable to noncontrolling interests due to increased Chipeta income and a $32.7 million increase in other operating expenses.

Operating Statistics

	2009		2008		∆(1)			2007		∆(1)
	(MMcf/d, except percentages and gross margin per Mcf)
Gathering and transportation throughput
Affiliates		761		832		(9	)%		910		(9	)%
Third parties		122		135		(10	)%		77		75	%
Total gathering and transportation throughput		883		967		(9	)%		987		(2	)%
Processing throughput (2)
Affiliates		451		323		40	%		82		294	%
Third parties		186		201		(7	)%		241		(17	)%
Total processing throughput		637		524		22	%		323		62	%
Equity investment throughput (3)		120		112		7	%		84		33	%
Total throughput		1,640		1,603		2	%		1,394		15	%
Throughput attributable to noncontrolling interest owners		180		124		45	%		—	nm (4)
Total throughput attributable to Western Gas Partners, LP		1,460		1,479		(1	)%		1,394		6	%
Gross margin per Mcf
Gross margin per Mcf	$	0.41	$	0.49		(16	)%	$	0.46		7	%
Gross margin per Mcf attributable to Western Gas Partners, LP	$	0.43	$	0.50		(14	)%	$	0.46		9	%

(1)	Represents the percentage change for the year ended December 31, 2009 or for the year ended December 31, 2008.
(2)	Includes 100% of Chipeta system volumes and 50% of Newcastle system volumes.
(3)	Represents our 14.81% share of Fort Union’s gross volumes.
(4)	Percent change is not meaningful.

Total throughput, which consists of affiliate, third-party and equity investment volumes, increased by 37 MMcf/d and 209 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Total throughput attributable to Western Gas Partners, LP, which excludes the noncontrolling interest owners’ proportionate share of Chipeta’s throughput, decreased by 19 MMcf/d for the year ended December 31, 2009 and increased by 85 MMcf/d for the year ended December 31, 2008.

12

Affiliate gathering and transportation throughput decreased by 71 MMcf/d and 78 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. The decrease for both the year ended December 31, 2009 and 2008 is primarily comprised of throughput decreases at the Pinnacle, Dew, Haley and Hugoton systems due to natural production declines and changes in contract terms, partially offset by affiliate throughput increases at the MIGC system. Contract terms for one Pinnacle customer changed in August 2008 when a producer chose to take its product in-kind and contract directly with us for gathering services, rather than to sell its production to our affiliate at the wellhead, resulting in a shift in volumes from affiliate to third-party. Affiliate volume increases for the MIGC system are primarily due to throughput from contracts entered into by our affiliate upon expiration of two third-party contracts in December 2008 and January 2009, which enabled an affiliate of Anadarko to increase its volumes, and a new affiliate contract that became effective in September 2007 in connection with expansion of the system’s capacity.

Third-party gathering and transportation throughput decreased by 13 MMcf/d for the year ended December 31, 2009 and increased by 58 MMcf/d for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 is primarily attributable to throughput decreases at the MIGC system, partially offset by third-party throughput increases at the Haley and Pinnacle systems. The declines experienced on the MIGC pipeline were primarily due to the expiration of two third-party contracts described above. The throughput increases on the Haley system were primarily due to third-party drilling activity which partially offset natural production declines. The increase in third-party throughput at the Pinnacle system is primarily due to changes in contract terms mentioned above resulting in a shift from affiliate to third-party throughput. The increase for the year ended December 31, 2008 is primarily attributable to throughput increases at the Hugoton and Haley systems primarily from third-party drilling activity, partially offset by third-party throughput decreases at the Pinnacle system resulting primarily from natural production declines.

Affiliate processing throughput increased by 128 MMcf/d and by 241 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Affiliate throughput increased primarily due to increased throughput at the Chipeta plant from initial start-up of the plant in early 2008 and the addition of the cryogenic train in April 2009, driven by our affiliates’ drilling activities in the Natural Buttes area, and due to increased throughput at the Granger system. Affiliate volume increases at the Granger system are due to drilling activity in the area and the release of capacity by a third party discussed in more detail below, increasing the capacity available to affiliates.

Third-party processing throughput decreased by 15 MMcf/d and by 40 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Third-party processing throughput decreased primarily due to decreased throughput at the Granger system partially offset by increased throughput at the Chipeta system due to completion of the refrigeration unit in December 2007. The throughput declines at the Granger system were primarily due to one third-party producer redirecting volumes processed at the Granger system pursuant to month-to-month agreements to its own processing facility.

Equity investment volumes increased by 8 MMcf/d and by 28 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively, primarily due to additional throughput from the Powder River area following expansion of the Fort Union system during the second half of 2008.

Natural Gas Gathering, Processing and Transportation Revenues

	2009		2008		∆			2007		∆
	(in thousands, except percentages)
Gathering, processing and transportation of natural gas:
Affiliates	$	146,707	$	130,524		12	%	$	105,168		24	%
Third parties		27,088		29,930		(9	)%		22,162		35	%
Total	$	173,795	$	160,454		8	%	$	127,330		26	%

Total gathering, processing and transportation of natural gas revenues increased by $13.3 million and by $33.1 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Revenues from affiliates increased by $16.2 million for the year ended December 31, 2009 primarily due to increased affiliate throughput at the Chipeta plant following completion of the cryogenic unit in April 2009, increased throughput at the MIGC system due to the third-party contract expirations that caused volumes and associated revenues to shift from third party to affiliate and higher rates at the Haley system due to changes in contract terms, partially offset by throughput decreases at the Pinnacle, Dew, Hugoton and Haley systems. Gathering, processing and transportation of natural gas revenues from affiliates increased by $25.4 million for the year ended December 31, 2008 primarily due to increased throughput at the Chipeta plant after completion of the refrigeration unit in December 2007, increased throughput at the MIGC system and higher rates at the Dew, Haley and Pinnacle

13

systems due to new contract terms, partially offset by throughput decreases at the Granger, Haley, Pinnacle, Dew and Hugoton systems.

Revenues from third parties decreased by $2.8 million for the year ended December 31, 2009, primarily due to third-party throughput decreases at the MIGC system attributable to the third-party contract expirations described above, partially offset by throughput increases at the Haley and Pinnacle systems. Revenues from third parties increased by $7.8 million for the year ended December 31, 2008 primarily due to increased third-party throughput at the Haley and Hugoton systems and higher gathering rates at the Haley system, partially offset by decreased third-party throughput at the Granger system.

Natural Gas, Natural Gas Liquids and Condensate Sales

	2009		2008		∆			2007		∆
	(in thousands, except percentages and average price per unit)
Natural gas sales:
Affiliates	$	48,536	$	131,626		(63	)%	$	82,468		60	%
Third parties		8		23		(65	)%		—	nm (1)
Total	$	48,544	$	131,649		(63	)%	$	82,468		60	%
Natural gas liquids sales:
Affiliates	$	131,595	$	254,370		(48	)%	$	234,955		8	%
Third parties		—		159		(100	)%		—	nm (1)
Total	$	131,595	$	254,529		(48	)%	$	234,955		8	%
Drip condensate sales:
Affiliates	$	—	$	—		0	%	$	7,054		(100	)%
Third parties		7,454		16,096		(54	)%		2,772		481	%
Total	$	7,454	$	16,096		(54	)%	$	9,826		64	%
Total natural gas, natural gas liquids and condensate sales:
Affiliates	$	180,131	$	385,996		(53	)%	$	324,477		19	%
Third parties		7,462		16,278		(54	)%		2,772		487	%
Total	$	187,593	$	402,274		(53	)%	$	327,249		23	%
Average price per unit:
Natural gas (per Mcf)	$	3.17	$	7.26		(56	)%	$	4.80		51	%
Natural gas liquids (per barrel)	$	29.32	$	60.18		(51	)%	$	48.28		25	%
Drip condensate (per barrel)	$	49.21	$	89.34		(45	)%	$	64.43		39	%

⁽¹⁾ Percent change is not meaningful

Total natural gas, NGL and condensate sales decreased by $214.7 million for the year ended December 31, 2009 and increased by $75.0 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 consisted of a $123.0 million decrease in NGL sales, an $83.1 million decrease in natural gas sales and an $8.6 million decrease in drip condensate sales. The increase for the year ended December 31, 2008 consisted of a $49.2 million increase in natural gas sales, a $19.6 million increase in NGL sales and a $6.3 million increase in drip condensate sales.

The decrease in natural gas sales for the year ended December 31, 2009 was primarily due to a $4.09 per Mcf, or 56%, decrease in the average price for natural gas sold and an approximate 1.6 MMcf, or 9%, decrease in the volume of natural gas sold. The increase in natural gas sales for the year ended December 31, 2008 was primarily due to a $2.46 per Mcf, or 51%, increase in the average price of residue sold as volumes remained relatively flat.

The decrease in NGL sales for the year ended December 31, 2009 was primarily due to a $30.86 per barrel (or “Bbl”), or 51%, decrease in the average price for NGLs sold, partially offset by a 329,000 Bbls, or 8%, increase in the volume of NGLs sold, primarily due to an increase in wellhead volumes delivered to the Granger system and improved NGL recoveries due to a change in the composition of the natural gas processed at the Granger system, partially offset by the suspension of operations of a plant at the Hilight system in September 2008 at which butane was purchased, processed into iso-butane and sold. The average natural gas and NGL prices for the year ended December 31, 2009 include $4.1 million of gains from commodity price swap agreements. The decrease in the NGL price per Bbl is due to the decrease in market prices, partially offset by the fixed prices at the Hilight and Newcastle systems under the commodity price swap agreements. The fixed prices under the swap agreements for 2009 were lower than 2008 market prices but higher than 2009 market prices. The increase in NGL sales for the year ended

14

December 31, 2008 was primarily due to an $11.90 per Bbl, or 25%, increase in the average price of NGLs sold, partially offset by an approximate 528,000 Bbls, or 11%, decrease in the volume of NGLs sold, primarily due to the Granger system.

The decrease in drip condensate sales for the year ended December 31, 2009 was primarily due to a $40.13 per Bbl, or 45%, decrease in average prices for drip condensate sold. Conversely, the increase for the year ended December 31, 2008 was due to a $24.91 per Bbl, or 39%, increase in the average price for condensate.

Equity Income and Other Revenues

	2009		2008		∆			2007		∆
	(in thousands, except percentages)
Equity income — affiliate	$	6,982	$	4,736		47	%	$	4,017		18	%
Other revenues, net:
Affiliates	$	1,595	$	4,553		(65	)%	$	2,127		114	%
Third parties		1,258		7,933		(84	)%		2,432		226	%
Total equity income and other revenues, net	$	9,835	$	17,222		(43	)%	$	8,576		101	%

Total equity income and other revenues decreased by $7.4 million for the year ended December 31, 2009 and increased by $8.6 million for the year ended December 31, 2008. During the year ended December 31, 2009, equity income from affiliates increased by approximately $2.2 million primarily from the system expansion at Fort Union and a decrease in that joint venture’s interest expense. During the year ended December 31, 2008, equity income from affiliates increased $0.7 million primarily due to increased throughput.

For the year ended December 31, 2009, other affiliate and third-party revenues decreased primarily due to changes in gas imbalance positions and related gas prices and $1.9 million of volume deficiency and indemnity payments received from two third parties during 2008. For the year ended December 31, 2008, the increase is primarily due to changes in our natural gas imbalance positions due to higher gas prices and the indemnity payment received from a third party during 2008.

Cost of Product and Operation and Maintenance Expenses

	2009		2008		∆			2007		∆
	(in thousands, except percentages and price per unit)
Cost of product	$	124,913	$	294,451		(58	)%	$	226,828		30	%
Operation and maintenance		60,613		64,249		(6	)%		52,867		22	%
Total cost of product and operation and maintenance expenses	$	185,526	$	358,700		(48	)%	$	279,695		28	%
Cost of product — average price per unit:
Natural gas (per Mcf)	$	3.79	$	9.29		(59	)%	$	5.43		71	%
Natural gas liquids (per Bbl)	$	9.27	$	23.77		(61	)%	$	21.66		10	%
Drip condensate (per MMBtu)	$	3.26	$	6.94		(53	)%	$	6.09		14	%

Cost of product expense decreased by $169.5 million for the year ended December 31, 2009 and increased by $67.6 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 includes an approximate $158.5 million decrease in cost of product expense attributable to the lower cost of natural gas and NGLs we purchase from producers due to lower market prices and lower net volumes. In addition, cost of product expense decreased $3.7 million 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, primarily due to lower market prices, and decreased $3.1 million due to a contract change at the Granger system related to volumes gathered at adjacent gathering systems owned by Anadarko and a third party, then processed at Granger. Effective in October 2009, fees previously paid by Granger are paid directly by the producer to the other gathering system owners. Cost of product expense also decreased $2.7 million due to lower fees resulting from the suspension of operations of the plant at the Hilight system in September 2008 and decreased $1.1 million due to a favorable change in the difference between actual versus contractual fuel recoveries. The value of natural gas volumes that are purchased by us to return to producers under keep-whole arrangements are recorded as cost of product expense. For the year ended December 31, 2009, the volume of natural gas purchased from producers decreased 9% and the volume of NGLs purchased from producers increased 8%. The increase in the volume of NGLs purchased is net of a decrease in volumes purchased resulting from the September 2008 suspension of operations of the plant at the Hilight system. Excluding the impact of the plant suspension, the volume of NGLs purchased would have increased approximately 20% primarily due to the increase in throughput at the Chipeta plant. The decrease in the volumes of natural gas purchased is primarily due to the increase in NGLs prices, the aforementioned change in contract terms for affiliate throughput at the Granger system effective in October 2009, which reduced the volumes purchased under keep-whole contracts, as well as an increase in NGL recoveries at the Chipeta system due to completion of the cryogenic unit in April 2009, partially offset by the increase in throughput at the Chipeta plant.

15

Cost of product expense for the year ended December 31, 2008 increased by $67.6 million, $55.3 million of which was attributable to the higher cost of natural gas and NGLs we purchased from producers, primarily due to higher market prices partially offset by lower volumes. In addition, cost of product expense increased $5.5 million due to a change in imbalance positions and related gas prices, increased $3.1 million due to an unfavorable change in the difference between actual versus contractual fuel recoveries, increased $2.5 million due to an increase in fees from higher volumes gathered at adjacent gathering systems and processed at the Granger system and increased $1.9 million from the higher cost of natural gas to compensate shippers for drip condensate retained by us and sold to third parties. These increases were slightly offset by a $1.6 million decrease in expenses attributable to a decline in NGLs volumes processed at the Highlight facility that produced iso-butane from NGLs. The volume of natural gas purchased from producers remained relatively flat and the volume of NGLs purchased from producers decreased 11% for the year ended December 31, 2008. The decrease in the volume of NGLs purchased is primarily due to the September 2008 suspension of operations of a plant at the Hilight system. Excluding the impact of the plant suspension, the volume of NGLs purchased would have decreased approximately 4%. This decrease in the volumes of NGLs purchased, excluding the impact of the plant suspension, is primarily due to the decrease in throughput for the Granger system, partially offset by the increase in throughput at the Chipeta plant which was placed in service in December 2007.

Operation and maintenance expense decreased by $3.6 million for the year ended December 31, 2009 and increased by $11.4 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 is primarily due to a $2.8 million decrease in operating fuel costs attributable to the plant suspension at the Hilight system in September 2008 and a $1.4 million decrease in plant repair costs at the Granger system, partially offset by a $0.8 million increase in operating expenses at the Chipeta plant and increases in costs related to employee incentive programs.

Operation and maintenance expense increased by $11.4 million for the year ended December 31, 2008 primarily due to a $7.4 million increase in labor and employee-related expenses primarily attributable to being charged by Anadarko for the full cost of these expenses. Specifically, contract modifications, beginning in 2008, entitled Anadarko to charge us additional labor and employee-related expenses in order for us to bear the full cost of operational personnel working our assets instead of bearing only those employee benefit costs reasonably allocated by Anadarko to us and included in our general and administrative expenses. These additional costs were taken into account when setting the gathering rates in our affiliate-based contracts for our initial assets that became effective in January 2008; thus, our revenues increased by the same amount. In addition, other increases in labor and employee-related expenses for the year ended December 31, 2008 were due to increases in benefits and incentive programs. Operating expenses also increased by $6.5 million due to operating expenses attributable to the Chipeta plant and the Granger system, partially offset by a $2.6 million decrease in compressor rental expenses.

Key Performance Metrics

	2009		2008		∆			2007			∆
	(in thousands, except percentages and gross margin per Mcf)
Gross margin
Gross margin	$	246,310	$	285,499		(14	)%		$	236,327		21	%
Gross margin per Mcf (1)	$	0.41	$	0.49		(16	)%		$	0.46		7	%
Gross margin per Mcf attributable to Western Gas Partners, LP (2)	$	0.43	$	0.50		(14	)%		$	0.46		9	%
Adjusted EBITDA (3)	$	141,563	$	185,078		(24	)%		$	160,772		15	%
Distributable cash flow (3)	$	128,014	$	173,838		(26	)%

(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 our 14.81% interest in income and volumes attributable to Fort Union. Calculating gross margin per Mcf separately for affiliates and third parties is not meaningful since a significant portion of throughput is delivered from third parties while the related residue gas and NGLs are sold to an affiliate.
(2)	Calculated as gross margin (total revenues less cost of product), excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product, divided by total throughput attributable to Western Gas Partners, LP. Calculation includes income and volumes attributable to our investment in Fort Union.
(3)	For a reconciliation of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures presented in accordance with GAAP, please read the caption How We Evaluate Our Operations within this Item 7.

Gross margin decreased by $39.2 million for the year ended December 31, 2009 and increased by $49.2 million for the year ended December 31, 2008. The decrease in gross margin for year ended December 31, 2009 is primarily due to the decrease in natural gas and NGL prices partially offset by a net increase in throughput. The impact of the decrease in market prices on our gross margin for the year ended December 31, 2009 was mitigated by our fixed-price contract structure. The increase in gross margin for the year ended December 31, 2008 is primarily due to the increase in natural gas and NGL prices and throughput.

Gross margin per Mcf attributable to Western Gas Partners, LP decreased by 14% and total gross margin per Mcf decreased by 16% for the year ended December 31, 2009, primarily due to lower processing margins and lower drip condensate margins.

16

Gross margin per Mcf attributable to Western Gas Partners, LP increased by 9% and total gross margin per Mcf increased by 7% for the year ended December 31, 2008, primarily due to higher processing margins and higher drip condensate margins.

Adjusted EBITDA. Adjusted EBITDA decreased by $43.5 million for the year ended December 31, 2009 and increased by $24.3 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 is primarily due to a $211.0 million decrease in total revenues, excluding equity income; a $1.7 million increase in general and administrative expenses, excluding non-cash equity-based compensation and expenses in excess of the omnibus cap; and a $3.0 million increase in the noncontrolling interest owners’ share of Adjusted EBITDA; partially offset by a $169.5 million decrease in cost of product; a $3.6 million decrease in operation and maintenance expenses and a $0.4 million increase in distributions from Fort Union. The increase in Adjusted EBITDA for the year ended December 31, 2008 is primarily due to a $116.1 million increase in total revenues, excluding equity income, and an approximately $3.8 million increase in distributions from Fort Union, partially offset by a $67.6 million increase in cost of product, an $11.4 million increase in operation and maintenance expenses, a $9.4 million increase in the noncontrolling interest owners’ share of Adjusted EBITDA and a $5.5 million increase in general and administrative expenses, excluding non-cash equity-based compensation.

Distributable cash flow. Distributable cash flow decreased by $45.8 million for the year ended December 31, 2009 primarily due to the $43.5 million decrease in Adjusted EBITDA and a $9.6 million increase in interest expense settled in cash, partially offset by a $6.2 million increase in interest income and a $1.1 million decrease in maintenance capital expenditures. We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2008 and, as such, did not differentiate between maintenance and capital expenditures prior to 2008 and do not present distributable cash flow for periods prior to 2008.

General and Administrative, Depreciation and Other Expenses

	2009		2008		∆			2007		∆
	(in thousands, except percentages)
General and administrative	$	24,306	$	20,089		21	%	$	12,680		58	%
Property and other taxes		10,293		8,977		15	%		7,340		22	%
Depreciation and amortization		51,090		46,522		10	%		43,592		7	%
Impairment		—		9,354	nm		(1)		—	nm		(1)
Total general and administrative, depreciation and other expenses	$	85,689	$	84,942		1	%	$	63,612		34	%

⁽¹⁾ Percent change is not meaningful

General and administrative, depreciation and other expenses increased by $0.7 million for the year ended December 31, 2009 as a $4.2 million increase in general and administrative expenses, a $1.3 million increase in property and other taxes primarily attributable to the Granger assets and a $4.6 million increase in depreciation and amortization expense were partially offset by a $9.4 million decrease in impairment expense. General and administrative expenses increased primarily due to incurring expenses attributable to being a publicly traded partnership for all of 2009, compared to approximately seven and a half months during the year ended December 31, 2008, and due to accounting and legal expenses attributable to the Chipeta acquisition. Depreciation and amortization expense increased for the year ended December 31, 2009 primarily due to assets placed in service during 2008 and 2009, including the Chipeta plant expansion completed in April 2009. Impairment expense for the year ended December 31, 2008 consisted of the $9.4 million charge recognized in connection with the plant suspension at the Hilight system prior to our acquisition of the Powder River assets.

General and administrative, depreciation and other expenses increased by $21.3 million for the year ended December 31, 2008. General and administrative expenses increased by $7.4 million for the year ended December 31, 2008, primarily due to incurring $3.0 million of expenses attributable to being a publicly traded partnership during and subsequent to May 2008, $2.2 million attributable to equity-based compensation and $1.5 million of accounting and legal expenses attributable to the Powder River acquisition, partially offset by a decrease in expenses charged pursuant to the management services fee prior to our acquisition of the Partnership assets. Depreciation and amortization expense increased by $2.9 million for the year ended December 31, 2008 due to depreciation on assets placed in service in 2008 and 2007, primarily attributable to the Chipeta plant placed in serviced in December 2007, our Pinnacle Bethel treating facility completed in July 2008 and previously leased Hugoton compression equipment contributed to us in November 2008.

17

Interest Income, Net

	2009			2008			∆			2007			∆
				(in thousands, except percentages)
Interest income (expense), net — affiliates
Interest income on note receivable from Anadarko	$	16,900		$	10,703			58	%	$	—		nm		(1)
Interest expense on notes payable to Anadarko		(8,953	)		(253	)	nm				—		nm
Interest income (expense), net		504			901			(44	)%		(6,187	)	nm
Credit facility fees		(143	)		(111	)		29	%		—			—
Total	$	8,308		$	11,240			(26	)%	$	(6,187	)	nm
Interest expense — third parties
Credit facility interest, fees and amortization	$	(859	)	$	—		nm			$	—		nm
Interest income (expense), net	$	7,449		$	11,240			(34	)%	$	(6,187	)	nm

⁽¹⁾ Percent change is not meaningful

Interest income, net for the year ended December 31, 2009, consisted of interest income on our $260.0 million note receivable from Anadarko entered into in connection with our initial public offering in May 2008 and interest earned on affiliate balances, partially offset by interest expense attributable to our $175.0 million term loan agreement entered into with Anadarko in connection with the Powder River acquisition; interest expense attributable to our $101.5 million term loan agreement entered into with Anadarko in connection with the Chipeta acquisition in July 2009 and repaid in October 2009; interest expense attributable to our revolving credit facility from October to December 2009; and commitment fees on our $350.0 million credit facility, $100.0 million portion of Anadarko’s $1.3 billion credit facility and our $30.0 million working capital facility. Interest income, net for the year ended December 31, 2008 consisted of interest income on our $260.0 million note receivable from Anadarko and interest earned on affiliate balances, partially offset by commitment fees for our credit facilities. Interest on affiliate balances changed from net interest expense on net payable balances for the year ended December 31, 2007 to net interest income on net receivable balances for the year ended December 31, 2008 primarily due to the settlement of intercompany balances attributable to our initial assets in connection with our May 2008 initial public offering.

Income Tax Expense

	2009			2008			∆			2007			∆
				(in thousands, except percentages)
Income before income taxes	$	107,511		$	147,744			(27	)%	$	113,646			30	%
Income tax expense (benefit)		6,975			32,255			(78	)%		39,637			(19	)%
Effective tax rate		6	%		22	%					35	%

The Partnership is not a taxable entity for U.S. federal income tax purposes. Income earned by the Partnership prior to our acquisition of the Partnership Assets, except for Chipeta, was subject to federal and state income tax while income earned by the Partnership after our acquisition of the Partnership Assets, except for Chipeta, was subject only to Texas margin tax. Income attributable to Chipeta was subject to federal and state income tax for periods prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes.

Income tax expense decreased by $25.3 million and by $7.4 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. The decrease in income tax expense for the year ended December 31, 2009 is primarily due to a change in the applicability of U.S. federal income tax to our income that occurred in connection with the initial public offering, the Powder River acquisition and the June 2008 formation of the Chipeta partnership. Income tax also decreased for the year ended December 31, 2009 due to a decrease in income attributable to the Granger system and a decrease in Texas margin tax expense attributable to the initial assets. In addition, our estimated income earned by our initial assets and the Powder River assets attributed to Texas relative to our total income decreased as compared to the prior year, which resulted in an approximately $0.6 million reduction of previously recognized deferred taxes during 2009. For 2009, our variance from the federal statutory rate is primarily attributable to our U.S. federal income tax status as a non-taxable entity as well as state income tax benefit.

Income tax expense decreased for the year ended December 31, 2008 primarily due to a change in the applicability of U.S. federal income tax to our income described above and a decrease in income attributable to the Granger system, partially offset by income tax expense attributable to the Chipeta assets for the first five months of 2008 following completion of the refrigeration unit in December 2007. For 2008, our variance from the federal statutory rate is primarily attributable to our U.S. federal income tax status as a non-taxable entity, partially offset by state income tax expense.

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Noncontrolling Interests

	2009		2008		∆			2007			∆
			(in thousands, except percentages)
Net income (loss) attributable to noncontrolling interests	$	10,260	$	7,908		30	%	$	(92	)	nm (1)

⁽¹⁾ Percent change is not meaningful

Net income attributable to noncontrolling interests increased by $2.4 million and $8.0 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Noncontrolling interests represent the aggregate 49% interest in Chipeta held by Anadarko and a third party. The increase in net income attributable to noncontrolling interests for the year ended December 31, 2009 is primarily due to higher throughput at the Chipeta plant, partially offset by lower NGL prices. The increase for the year ended December 31, 2008 is primarily due to an increase in volumes processed at the Chipeta plant as the refrigeration unit was placed in service in late 2007 and throughput increased to the plant’s initial capacity during the first quarter of 2008. The cryogenic unit was placed in service in April 2009, leading to further increased volumes and NGL recoveries during the balance of 2009.

LIQUIDITY AND CAPITAL RESOURCES

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

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

Our sources of liquidity as of December 31, 2009 include:

• approximately $54.0 million of working capital, which we define as the amount by which current assets exceed current liabilities;

• cash generated from operations;

• available borrowings under our $350.0 million revolving credit facility, which is expandable to $450.0 million;

• available borrowings of up to $100.0 million under Anadarko’s $1.3 billion credit facility;

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

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

• potential issuances of additional partnership securities.

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

In January 2010, we borrowed $210.0 million under our $350.0 million revolving credit facility in connection with the Granger acquisition. See Note 1—Description of Business and Basis of Presentation—Offerings and Acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.

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

Historical cash flow. The following table and discussion presents a summary of our net cash flows from operating activities, investing activities and financing activities as well as Adjusted EBITDA for the years ended December 31, 2009 and 2008.

For periods prior to our acquisition of the Partnership Assets, except for Chipeta, our net cash from operating activities and capital contributions from our Parent related to such assets were used to service our cash requirements, which included the funding of operating expenses and capital expenditures. Subsequent to our acquisition of the Partnership Assets, except for Chipeta, transactions with Anadarko and third parties related to such assets are cash-settled. Prior to June 1, 2008 with respect to Chipeta, sales and purchases related to third-party transactions were received or paid in cash by Anadarko within its centralized cash management system and were settled with Chipeta through an adjustment to parent net investment. Subsequent to June 1, 2008, Chipeta cash-settled transactions directly with third parties and with Anadarko affiliates.

	2009			2008			∆			2007			∆
				(in thousands, except percentages)
Net cash provided by (used in):
Operating activities	$	135,532		$	185,922			(27	)%	$	130,206			43	%
Investing activities		(171,321	)		(552,585	)		(69	)%		(149,013	)		271	%
Financing activities		69,699			402,737			(83	)%		18,349		nm		(1)
Net increase (decrease) in cash and cash equivalents	$	33,910		$	36,074			(6	)%	$	(458	)	nm		(1)

⁽¹⁾ Percent change is not meaningful

Operating Activities. Net cash provided by operating activities decreased by $50.4 million and increased by $55.7 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. For the year ended December 31, 2009, the decrease is primarily attributable to changes in working capital, lower gross margins, and higher general and administrative expenses as described in Results of Operations—Overview above. In addition, these items were partially offset by lower current income taxes and lower operations and maintenance expenses. For the year ended December 31, 2008, the increase in cash provided by operating activities is primarily attributable to gathering rate increases, increased condensate margins, revenues attributable to changes in gas imbalance positions and gas prices as well as increased net interest income, partially offset by higher cash operating expenses.

Investing Activities. Net cash used in investing activities decreased by $381.3 million for the year ended December 31, 2009 and increased by $403.6 million for the year ended December 31, 2008, respectively. Net cash used in investing activities for the year ended December 31, 2009 includes the $101.5 million cash consideration paid for the Chipeta acquisition. Net cash used in investing activities for the year ended December 31, 2008 includes our $260.0 million loan made to Anadarko in connection with our initial public offering and $175.0 million cash consideration paid for the Powder River acquisition. Investing cash flows included contributions to Fort Union of $8.1 million during the year ended December 31, 2008 related to the system expansion.

Capital expenditures decreased by $40.0 million and $33.1 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Capital expenditures include costs attributable to the Chipeta assets prior to the Chipeta acquisition and include the noncontrolling interest owners’ share of Chipeta’s capital expenditures. Expansion capital expenditures decreased by 44%, from $87.9 million during the year ended December 31, 2008 to $49.0 million during the year ended December 31, 2009, primarily due to capital expenditures during the full year ended December 31, 2008 for the Chipeta plant construction compared to capital expenditures for the cryogenic unit during the first six months of 2009, completion of the NGL pipeline at the tailgate of the Chipeta plant during the second quarter of 2008, expansion of the Bethel facility completed during 2008 and installation of a compressor station at the Hugoton system during 2008, offset by the acquisition of the Natural Buttes plant during the fourth quarter of 2009. In addition, maintenance capital expenditures decreased by 5%, from $21.6 million during the year ended December 31, 2008 to $20.5 million during the year ended December 31, 2009, primarily due to fewer well connections at the Haley, Hugoton and Pinnacle systems due to reduced drilling activity, partially offset by a compression overhaul at our Hugoton System, an upgrade to the control system at the Hilight facility and equipment replacements at the Bethel facility during 2009. We did not differentiate between maintenance and capital expenditures for the year ended December 31, 2007. Capital expenditures decreased by $33.1 million for the year ended December 31, 2008 primarily due to completion of the Chipeta refrigeration unit in December 2007, partially offset by expansion of the Chipeta plant cryogenic train during 2008, the expansion of the Bethel facility and the installation of the compressor station at the Hugoton system during 2008.

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Financing Activities. Net cash provided by financing activities decreased by $333.0 million for the year ended December 31, 2009 and increased by $384.4 million for the year ended December 31, 2008. Proceeds from financing activities during the year ended December 31, 2009 included $122.5 million from the 2009 equity offering as well as the July 2009 issuance and October 2009 repayment of the three-year term loan to Anadarko originally incurred in connection with the Chipeta acquisition, partially offset by $4.3 million of costs paid in connection with the revolving credit facility we entered into in October 2009. The term loan was refinanced in October 2009 with borrowings on our revolving credit facility, then such revolving credit facility borrowings were repaid in December 2009 with a portion of the net proceeds from our 2009 equity offering. Net cash provided by financing activities for the year ended December 31, 2008 included the receipt of $315.2 million of net proceeds from our initial public offering, partially offset by a $45.2 million reimbursement to Anadarko of offering proceeds. Proceeds from financing activities for the year ended December 31, 2008 also included $175.0 million from the issuance of the five-year term loan to Anadarko in connection with the Powder River acquisition.

For the year ended December 31, 2009, $70.1 million of cash distributions were paid to our unitholders, representing distributions for the fourth quarter of 2008 through the third quarter of 2009. Distributions to unitholders totaled $24.8 million during the year ended December 31, 2008, representing the partial distribution for the second quarter of 2008 and a full distribution for the third quarter of 2008. Net distributions to Anadarko attributable to pre-acquisition intercompany balances were $10.8 million during the year ended December 31, 2009, representing the net non-cash settlement of intercompany transactions attributable to the Chipeta assets and the Granger assets, compared to net distributions to Anadarko of $34.9 million for the year ended December 31, 2008, representing the net settlement of transactions attributable to the Powder River assets, the Chipeta assets and the Granger assets.

Financing proceeds for the year ended December 31, 2009 and for the year ended December 31, 2008 included $40.3 million and $55.4 million, respectively, of contributions from noncontrolling interest owners and Parent attributable to the Chipeta plant construction, for which the associated capital expenditures are included in investing activities above. Most of these contributions were received by Chipeta prior to our July 2009 acquisition of a 51% interest in Chipeta. Distributions from Chipeta to noncontrolling interest owners and Parent totaled $8.0 million and $37.9 million during the years ended December 31, 2009 and 2008, respectively, representing the distribution of Chipeta’s available cash. Distributions to noncontrolling interest owners and Parent during the year ended December 31, 2008 included a $19.7 million one-time distribution of part of the consideration paid by the third-party owner following the initial formation of Chipeta.

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

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

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

Total capital incurred for the year ended December 31, 2009 and 2008 was $59.2 million and $117.7 million, respectively. Capital incurred is presented on an accrual basis. Capital expenditures in the consolidated statement of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital expenditures for the years ended December 31, 2009 and 2008 were $69.5 million and $109.5 million, respectively. Capital expenditures for the year ended December 31, 2009 include $30.8 million attributable to the Chipeta assets prior to the Chipeta acquisition and include the noncontrolling interest owners’ share of Chipeta’s capital expenditures which were funded by contributions from the noncontrolling interest owners. Expansion capital expenditures represented approximately 71% and 80% of total capital expenditures for the years ended December 31, 2009 and 2008, respectively. We estimate our total capital expenditures, excluding any future acquisitions, to be $28 million to $32 million and our maintenance capital expenditures to be approximately 75% to 80% of total capital expenditures for the year ending December 31, 2010. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us, which are dependent, in part, on the drilling activities of Anadarko and third-party producers. From time to time, for projects with significant risk or capital exposure, we may secure indemnity provisions or throughput agreements. We expect to fund future capital expenditures from cash flows generated from our operations, interest income from our note receivable from Anadarko, borrowings under our revolving credit facility or Anadarko’s credit facility, the issuance of additional partnership units or debt offerings.

Distributions to unitholders. We expect to pay a quarterly distribution of $0.33 per unit per full quarter, which equates to approximately $21.4 million per full quarter, or approximately $85.6 million per full year, based on the number of common, subordinated and general partner units outstanding as of March 1, 2010. Our partnership agreement requires that we distribute all

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of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the year ended December 31, 2009, we paid cash distributions to our unitholders of approximately $70.1 million, representing the $0.32 per unit distribution for the quarter ended September 30, 2009, $0.31 per unit distribution for the quarter ended June 30, 2009 and $0.30 per unit distributions for each of the quarters ended March 31, 2009 and December 31, 2008. On January 21, 2010, the board of directors of our general partner declared a cash distribution to our unitholders of $0.33 per unit, or $21.4 million in aggregate, for the fourth quarter of 2009. The cash distribution was paid on February 12, 2010 to unitholders of record at the close of business on February 1, 2010.

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

The revolving credit facility contains various customary covenants, customary events of default and certain financial tests, including a maximum consolidated leverage ratio, as defined in the revolving credit facility, of 4.5 to 1.0 as of the end of each quarter and a minimum consolidated interest coverage ratio, as defined in the revolving credit facility, of 3.0 to 1.0 as of the end of each quarter. If we obtain two of the following three ratings: BBB- or better by Standard and Poor’s, Baa3 or better by Moody’s Investors Service or BBB- or better by Fitch Ratings Ltd. (the date of such ratings being the “Investment Grade Rating Date”), we will no longer be required to comply with certain of the foregoing covenants. All amounts due by us under the revolving credit facility are unconditionally guaranteed by certain of our wholly owned subsidiaries. The subsidiary guarantees will automatically terminate on the Investment Grade Rating Date.

On October 30, 2009, we used $100.0 million of our capacity under the revolving credit facility along with $2.0 million of cash on hand to refinance our $101.5 million, 7.00% fixed-rate, three-year term loan and settle related accrued interest. We entered into the three-year term loan agreement with Anadarko in July 2009 to finance a portion of the Chipeta acquisition. In December 2009, we repaid the amount outstanding under the revolving credit facility using a portion of the proceeds from the 2009 equity offering. In January 2010, we borrowed $210.0 million under the revolving credit facility to partially fund the Granger acquisition.

Anadarko’s credit facility. On March 4, 2008, Anadarko entered into a $1.3 billion credit facility under which we are a co-borrower. This credit facility is available for borrowings and letters of credit and permits us to utilize up to $100.0 million under the facility for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Anadarko. At December 31, 2009, the full $100.0 million was available for borrowing by us. The $1.3 billion credit facility expires in March 2013.

Interest on borrowings under the credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.50% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which was 0.44% at December 31, 2009, and the commitment fees on the facility are based on Anadarko’s senior unsecured long-term debt rating. Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, we are required to reimburse Anadarko for our allocable portion of commitment fees (0.11% of our committed and available borrowing capacity, including our outstanding balances, if any) that Anadarko incurs under its credit facility, or up to $0.1 million annually. Under certain of Anadarko’s credit and lease agreements, we and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. As of December 31, 2009, we and Anadarko were in compliance with all covenants. Should we or Anadarko fail to comply with any covenant in Anadarko’s credit facilities, we may not be permitted to borrow thereunder. Anadarko is a guarantor of our borrowings, if any, under the credit facility. We are not a guarantor of Anadarko’s borrowings under the credit facility.

Working capital facility. Concurrent with the closing of our initial public offering, we entered into a two-year, $30.0 million working capital facility with Anadarko as the lender. At December 31, 2009, no borrowings were outstanding under the working capital facility. The facility is available exclusively to fund working capital needs. Borrowings under the facility will bear interest at the same rate as would apply to borrowings under the Anadarko credit facility described above. We pay a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility, or up to $33,000 annually.

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

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

22

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

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

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

CONTRACTUAL OBLIGATIONS

Following is a summary of our obligations as of December 31, 2009:

			Asset		Note Payable				Credit
	Operating		Retirement		To Anadarko				Facility
	Leases		Obligations		Principal		Interest		Fees		Total
					(in thousands)
2010	$	970	$	—	$	—	$	7,000	$	1,872	$	9,842
2011		969		—		—		3,064		1,860		5,893
2012		799		—		—		3,064		1,558		5,421
2013		794		—		175,000		3,064		19		178,877
2014		311		—		—		—		—		311
Thereafter		—		14,924		—		—		—		14,924
Total	$	3,843	$	14,924	$	175,000	$	16,192	$	5,309	$	215,268

Operating leases: Anadarko leases compression equipment, office space and a warehouse used by us and charges rental payments to us. The amounts above represent the future minimum rent payments due under these operating leases.

Asset retirement obligations: When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties and equipment. Revisions to estimated asset retirement obligations can result from revisions to estimated inflation rates and discount rates, escalating retirement costs and changes in the estimated timing of settlement. For additional information see Note 10—Asset Retirement Obligations of the notes to the consolidated financial statements under Item 8 of this annual report.

Note payable to Anadarko: In connection with the Powder River acquisition, we entered into a five-year, $175.0 million term loan agreement with Anadarko which calls for interest at a fixed rate of 4.0% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years.

Credit facility fees: We are required to pay facility fees on our $350.0 million revolving credit facility, on our $100.0 million portion of Anadarko’s $1.3 billion credit facility and on our $30.0 million working capital facility as described under the caption Historical cash flow above within this Item 7.

Also see the caption Items Affecting the Comparability of Our Financial Results under Item 7 of this annual report for a discussion of contractual obligations effective with the initial public offering, including the omnibus agreement, expenses related to operating as a publicly traded partnership, the services and secondment agreement and equity-based compensation plans; the Powder River acquisition; the Chipeta acquisition and the Granger acquisition.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements in accordance with GAAP requires our management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and affect the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of properties and equipment, goodwill, asset retirement obligations, litigation, environmental liabilities, income taxes and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with the audit committee of our general partner. For additional information concerning our accounting policies, see the Note 2—Summary of Significant Accounting Policies of the notes to the consolidated financial statements included under Item 8 of this annual report.

Depreciation. Depreciation expense is generally computed using the straight-line method over the estimated useful life of the assets. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, depreciation estimates are reviewed to determine if any changes in the underlying assumptions are necessary. The weighted average life of our long-lived assets is approximately 23 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by approximately $6.1 million, which would result in a corresponding reduction in our operating income.

Impairment of tangible assets. Each reporting period, management assesses whether facts and circumstances indicate that the carrying amounts of property, plant and equipment may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.

In assessing long-lived assets for impairment, management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. Since a significant portion of our revenues arises from gathering and transporting natural gas production from Anadarko-operated properties, significant downward revisions in reserve estimates or changes in future development plans by Anadarko, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability. Such assessment requires application of judgment regarding the use and ultimate disposition of the asset, long-range revenue and expense estimates, global and regional economic conditions, including commodity prices and drilling activity by our customers, as well as other factors affecting estimated future net cash flows. The measure of impairment to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.

Impairment of goodwill. We evaluate whether goodwill has been impaired annually as of October 1, unless facts and circumstances make it necessary to test more frequently. Management has determined that we have one operating segment and two reporting units: (i) gathering and processing and (2) transportation. The carrying value of goodwill as of December 31, 2009 was $26.4 million and $4.8 million for the gathering and processing reporting unit and transportation reporting unit, respectively. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. Goodwill impairment assessment is a two-step process. Step one focuses on identifying a potential impairment by comparing the fair value of the reporting unit with the carrying amount of the reporting unit. If the fair value of the reporting unit exceeds its carrying amount, no further action is required. However, if the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to the implied fair value of the goodwill through a charge to operating expense based on a hypothetical purchase price allocation.

Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of reporting units for purposes of performing the goodwill impairment test. Management uses information available to make these fair value estimates, including market multiples of Adjusted EBITDA. Specifically, management estimates fair value by applying an estimated multiple to projected 2010 Adjusted EBITDA. Management considered the relatively few observable transactions in the market, as well as trading multiples for peers, to determine an appropriate multiple to apply against our projected Adjusted EBITDA. A lower fair value estimate in the future for any of our reporting units could result in a goodwill impairment. Factors that could trigger a lower fair-value estimate include sustained price declines, cost increases, regulatory or political environment changes, and other changes in market conditions such as decreased prices in market-based transactions for similar assets. Based on our most recent goodwill impairment test, we concluded that the fair

24

value of each reporting unit substantially exceeded the carrying value of the reporting unit. Therefore, no goodwill impairment was indicated and no goodwill impairment has been recognized in these consolidated financial statements.

Fair Value. Management estimates fair value in performing impairment tests for long-lived assets and goodwill as well as for the initial measurement of asset retirement obligations. When management is required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, management generally utilizes an income or multiples valuation approach. The income approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment, since the results are based on expected future events or conditions, such as sales prices; estimates of future throughput; capital and operating costs and the timing thereof; economic and regulatory climates and other factors. A multiples approach utilizes management’s best assumptions regarding expectations of projected EBITDA and multiple of that EBITDA that a buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have off-balance sheet arrangements other than operating leases. The information pertaining to operating leases required for this item is provided in Note 12—Commitments and Contingencies included in the notes to the consolidated financial statements under Item 8 of this annual report, which information is incorporated by reference.

RECENT ACCOUNTING DEVELOPMENTS

The information required for this item is provided under the caption New Accounting Standards in Note 2—Summary of Significant Accounting Policies included in the notes to the consolidated financial statements under Item 8 of this annual report which information is incorporated by reference.

25

EX-99.3

Exhibit 99.3

Item 8. Financial Statements and Supplementary Data

WESTERN GAS PARTNERS, LP
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F — 2
Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007	F — 3
Consolidated Balance Sheets as of December 31, 2009 and 2008	F — 4
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2009, 2008 and 2007	F — 5
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007	F — 6
Notes to the Consolidated Financial Statements	F — 7
Supplemental Quarterly Information	F — 31

WESTERN GAS PARTNERS, LP
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders
Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):

We have audited the accompanying consolidated balance sheets of Western Gas Partners, LP and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Western Gas Partners, LP and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Western Gas Partners, LP’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2010 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas
May 4, 2010

F - 2

WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2009(1)		2008(1)		2007(1)
	(in thousands, except per-unit data)
Revenues — affiliates
Gathering, processing and transportation of natural gas	$	146,707	$	130,524	$	105,168
Natural gas, natural gas liquids and condensate sales		180,131		385,996		324,477
Equity income and other		8,577		9,289		6,144
Total revenues — affiliates		335,415		525,809		435,789
Revenues — third parties
Gathering, processing and transportation of natural gas		27,088		29,930		22,162
Natural gas, natural gas liquids and condensate sales		7,462		16,278		2,772
Other		1,258		7,933		2,432
Total revenues — third parties		35,808		54,141		27,366
Total revenues		371,223		579,950		463,155
Operating expenses (2)
Cost of product		124,913		294,451		226,828
Operation and maintenance		60,613		64,249		52,867
General and administrative		24,306		20,089		12,680
Property and other taxes		10,293		8,977		7,340
Depreciation and amortization		51,090		46,522		43,592
Impairment		—		9,354		—
Total operating expenses		271,215		443,642		343,307
Operating income		100,008		136,308		119,848
Interest income (expense), net (3)		7,449		11,240		(6,187	)
Other income (expense), net		54		196		(15	)
Income before income taxes		107,511		147,744		113,646
Income tax expense		6,975		32,255		39,637
Net income		100,536		115,489		74,009
Net income (loss) attributable to noncontrolling interests		10,260		7,908		(92	)
Net income attributable to Western Gas Partners, LP	$	90,276	$	107,581	$	74,101
Limited partner interest in net income:
Net income attributable to Western Gas Partners, LP (4)	$	90,276	$	107,581		n/a	(5)
Less pre-acquisition income allocated to Parent		18,868		65,478		n/a
Less general partner interest in net income		1,428		842		n/a
Limited partner interest in net income	$	69,980	$	41,261		n/a
Net income per common unit — basic and diluted	$	1.25	$	0.78		n/a
Net income per subordinated unit — basic and diluted	$	1.24	$	0.77		n/a

(1)	Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 and 2007 has been revised to include results attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions.
(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. Cost of product expenses include product purchases from affiliates of $43.5 million, $116.9 million and $81.0 million for the years ended December 31, 2009, 2008 and 2007, respectively. Operation and maintenance expenses include charges from affiliates of $26.0 million, $25.7 million and $16.4 million for the years ended December 31, 2009, 2008 and 2007, respectively. General and administrative expenses include charges from affiliates of $18.6 million, $16.8 million and $12.7 million for the years ended December 31, 2009, 2008 and 2007, respectively. See Note 6—Transactions with Affiliates.
(3)	Interest income (expense), net includes income (expense), net from affiliates of $8.3 million, $11.2 million and ($6.2 million) for the years ended December 31, 2009, 2008 and 2007, respectively. See Note 6—Transactions with Affiliates.
(4)	General and limited partner interest in net income represents net income for periods including and subsequent to the Partnership’s acquisition of the Partnership Assets (as defined in Note 1—Description of Business and Basis of Presentation — Offerings and acquisitions). See also Note 5—Net Income per Limited Partner Unit.
(5)	Not applicable.

See accompanying notes to the consolidated financial statements.

F-3

WESTERN GAS PARTNERS, LP
CONSOLIDATED BALANCE SHEET

	December 31,		December 31,
	2009(1)		2008(1)
	(in thousands, except number of units)
ASSETS
Current assets
Cash and cash equivalents	$	69,984	$	36,074
Accounts receivable, net — third parties		4,076		7,113
Accounts receivable — affiliates		2,203		2,012
Natural gas imbalance receivables — third parties		266		3,585
Natural gas imbalance receivables — affiliates		448		1,422
Other current assets		3,287		1,380
Total current assets		80,264		51,586
Other assets		2,974		628
Note receivable — Anadarko		260,000		260,000
Property, plant and equipment
Cost		1,246,155		1,185,336
Less accumulated depreciation		252,778		202,523
Net property, plant and equipment		993,377		982,813
Goodwill		31,248		31,248
Equity investment		20,060		18,183
Total assets	$	1,387,923	$	1,344,458
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable — third parties	$	12,003	$	12,956
Accounts payable — affiliates		—		21,104
Natural gas imbalance payable — third parties		289		244
Natural gas imbalance payable — affiliates		1,319		1,198
Accrued ad valorem taxes		3,046		2,438
Income taxes payable		412		146
Accrued liabilities — third parties		8,717		17,183
Accrued liabilities — affiliates		470		153
Total current liabilities		26,256		55,422
Long-term liabilities
Note payable — Anadarko		175,000		175,000
Deferred income taxes		92,891		94,762
Asset retirement obligations and other		15,077		13,070
Total long-term liabilities		282,968		282,832
Total liabilities		309,224		338,254
Commitments and contingencies (Note 12)		—		—
Equity and partners’ capital
Common units (36,374,925 and 29,093,197 units issued and outstanding at December 31, 2009 and 2008, respectively)		497,230		368,050
Subordinated units (26,536,306 units issued and outstanding at December 31, 2009 and 2008)		276,571		275,917
General partner units (1,283,903 and 1,135,296 units issued and outstanding at December 31, 2009 and 2008, respectively)		13,726		10,988
Parent net investment		200,250		285,233
Total partners’ capital		987,777		940,188
Noncontrolling interests		90,922		66,016
Total equity and partners’ capital		1,078,699		1,006,204
Total liabilities, equity and partners’ capital	$	1,387,923	$	1,344,458

⁽¹⁾ Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 has been revised to include results attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions.

See accompanying notes to the consolidated financial statements.

F-4

WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL

				Partners’ Capital
	Parent Net			Limited Partners						General			Noncontrolling
	Investment			Common			Subordinated			Partner			Interests			Total
							(in thousands)
Balance at December 31, 2006 (1)	$	578,386		$	—		$	—		$	—		$	—		$	578,386
Contributions of property from Parent		21,942			—			—			—			—			21,942
Net pre-acquisition contributions from Parent		18,349			—			—			—			—			18,349
Net income		74,101			—			—			—			(92	)		74,009
Balance at December 31, 2007 (1)	$	692,778		$	—		$	—		$	—		$	(92	)	$	692,686
Net pre-acquisition distributions to Parent		(139,928	)		—			—			—			—			(139,928	)
Elimination of net deferred tax liabilities		126,936			—			—			—			—			126,936
Contribution of initial assets		(321,609	)		55,221			255,941			10,447			—			—
Acquisition of Powder River assets		(160,851	)		(13,866	)		—			(283	)		—			(175,000	)
Contribution of other assets from Parent		2,089			2,528			11,715			478			—			16,810
Reimbursement to Parent from offering proceeds		(45,161	)		—			—			—			—			(45,161	)
Issuance of common units to public, net of offering and other costs		—			315,161			—			—			—			315,161
Contributions from noncontrolling interest holders and Parent		88,465			—			—			—			73,105			161,570
Distributions to noncontrolling interest holders and Parent		(22,668	)		—			—			—			(15,201	)		(37,869	)
Non-cash equity-based compensation		—			324			—			—			—			324
Net income		65,478			20,841			20,420			842			7,908			115,489
Distributions to unitholders		—			(12,159	)		(12,159	)		(496	)		—			(24,814	)
Other		(296	)		—			—			—			296			—
Balance at December 31, 2008 (1)	$	285,233		$	368,050		$	275,917		$	10,988		$	66,016		$	1,006,204
Net pre-acquisition distributions to Parent		(11,079	)		—			—			—			—			(11,079	)
Acquisition of Chipeta assets		(112,744	)		11,068			—			225			—			(101,451	)
Issuance of common and general partner units, net of offering costs		—			120,080			—			2,459			—			122,539
Contributions from noncontrolling interest owners and Parent		20,544			—			—			—			19,718			40,262
Distributions to noncontrolling interest owners and Parent		(2,926	)		—			—			—			(5,072	)		(7,998	)
Non-cash equity-based compensation		—			366			—			—			—			366
Net income		18,868			37,035			32,945			1,428			10,260			100,536
Distributions to unitholders		—			(36,025	)		(32,640	)		(1,401	)		—			(70,066	)
Other		2,354			(3,344	)		349			27			—			(614	)
Balance at December 31, 2009(1)	$	200,250		$	497,230		$	276,571		$	13,726		$	90,922		$	1,078,699

⁽¹⁾ Financial information for 2009 has been revised to include activity attributable to the Granger assets and financial information for 2008, 2007 and 2006 has been revised to include activity attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions.

See accompanying notes to the consolidated financial statements.

F-5

WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009(1)			2008(1)			2007(1)
				(in thousands)
Cash flows from operating activities
Net income	$	100,536		$	115,489		$	74,009
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		51,090			46,522			43,592
Impairment		—			9,354			—
Deferred income taxes		(1,666	)		1,051			8,983
Changes in assets and liabilities:
Increase in accounts receivable		(950	)		(2,373	)		(3,934	)
(Increase) decrease in natural gas imbalance receivable		4,292			(3,728	)		(393	)
Increase (decrease) in accounts payable, accrued expenses and natural gas imbalance payable		(17,626	)		19,000			9,280
Change in other items, net		(144	)		607			(1,331	)
Net cash provided by operating activities		135,532			185,922			130,206
Cash flows from investing activities
Capital expenditures		(69,488	)		(109,490	)		(142,613	)
Acquisitions		(101,451	)		(175,000	)		—
Investment in equity affiliate		(382	)		(8,095	)		(6,400	)
Loan to Anadarko		—			(260,000	)		—
Net cash used in investing activities		(171,321	)		(552,585	)		(149,013	)
Cash flows from financing activities
Proceeds from issuance of common and general partner units, net of $5.5 million and $28.2 million in offering and other expenses for the years ended December 31, 2009 and 2008, respectively		122,539			315,161			—
Issuance of Notes Payable to Anadarko		101,451			175,000			—
Repayment of Note Payable to Anadarko		(101,451	)		—			—
Revolving credit facility issuance costs		(4,263	)		—			—
Reimbursement to Parent from offering proceeds		—			(45,161	)		—
Distributions to unitholders		(70,066	)		(24,814	)		—
Net pre-acquisition contributions from (distributions to) Anadarko		(10,775	)		(34,942	)		18,349
Contributions from noncontrolling interest owners and Parent		40,262			55,362			—
Distributions to noncontrolling interest owners and Parent		(7,998	)		(37,869	)		—
Net cash provided by financing activities		69,699			402,737			18,349
Net increase (decrease) in cash and cash equivalents		33,910			36,074			(458	)
Cash and cash equivalents at beginning of period		36,074			—			458
Cash and cash equivalents at end of period	$	69,984		$	36,074		$	—
Supplemental disclosures
Significant non-cash investing and financing transactions:
Contribution of initial assets from Parent	$	—		$	321,609		$	—
Elimination of net deferred tax liabilities	$	—		$	126,936		$	—
Property, plant and equipment and other assets contributed by Parent	$	—		$	123,018		$	21,942
(Increase) decrease in accrued capital expenditures	$	11,540		$	(9,761	)	$	(993	)
Interest paid	$	9,372		$	82		$	—
Interest received	$	16,900		$	7,887		$	—

⁽¹⁾  Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 and 2007 has been revised to include results attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions of the notes to the consolidated financial statements.

See accompanying notes to the consolidated financial statements.

F-6

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

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Basis of presentation. Western Gas Partners, LP (the “Partnership”) is a Delaware limited partnership formed in August 2007. As of December 31, 2009, the Partnership’s assets consisted of ten gathering systems, six natural gas treating facilities, six gas processing facilities, one NGL pipeline and one interstate pipeline. The Partnership’s assets are located in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, compressing, processing, treating and transporting natural gas for Anadarko Petroleum Corporation and its consolidated subsidiaries and third-party producers and customers. For purposes of these financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries; “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner; “Parent” refers to Anadarko prior to the Partnership’s acquisition of assets from Anadarko; and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership. The Partnership’s general partner is Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko.

The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. All significant intercompany transactions have been eliminated. The Partnership’s 50% undivided interest in the Newcastle system is consolidated on a proportionate basis.

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

Offerings and acquisitions.

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

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

Equity offering. On December 9, 2009, the Partnership closed its equity offering of 6,000,000 common units to the public at a price of $18.20 per unit. On December 17, 2009, the Partnership issued an additional 900,000 units to the public pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the equity offering. The December 9 and December 17, 2009 issuances are referred to collectively as the “2009 equity offering.” Net proceeds from the offering of approximately $122.5 million were used to repay $100.0 million outstanding under the Partnership’s revolving credit facility and to partially fund the January 2010 Granger acquisition referenced below. In connection with the 2009 equity offering, the Partnership issued 140,817 general partner units to the general partner.

F-7

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

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

Chipeta acquisition. In July 2009, the Partnership acquired certain midstream assets from Anadarko for (i) approximately $101.5 million in cash, which was financed by borrowing $101.5 million from Anadarko pursuant to the terms of a 7.0% fixed-rate, three-year term loan agreement, and (ii) the issuance of 351,424 common units and 7,172 general partner units. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. The acquisition consisted of a 51% membership interest in Chipeta Processing LLC (“Chipeta”), together with an associated NGL pipeline. Chipeta owns a natural gas processing plant complex, which includes two recently completed processing trains: a refrigeration unit completed in November 2007 and a cryogenic unit which was completed in April 2009. The 51% membership interest in Chipeta and associated NGL pipeline are referred to collectively as the “Chipeta assets” and the acquisition is referred to as the “Chipeta acquisition.”

In November 2009, Chipeta closed its acquisition of a compressor station and processing plant (the “Natural Buttes plant,” which was formerly known as the CIG 101 plant prior to the Partnership’s acquisition) from a third party for $9.1 million. The noncontrolling interest owners contributed $4.5 million to Chipeta during the year ended December 31, 2009 to fund their proportionate share of the Natural Buttes plant acquisition. The Natural Buttes plant is located in Uintah County, Utah.

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 plus cash on hand, and (ii) the issuance of 620,689 common units and 12,667 general partner units. The assets acquired represent Anadarko’s entire 100% ownership interest in the following assets located in Southwestern Wyoming: (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains, two refrigeration trains, an NGLs fractionation facility and ancillary equipment. These assets are referred to collectively as the “Granger assets” and the acquisition is referred to as the “Granger acquisition.”

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

Anadarko acquired MIGC, the Powder River assets and the Granger assets in connection with its August 23, 2006 acquisition of Western Gas Resources, Inc. (“Western”) and Anadarko acquired the Chipeta assets in connection with its August 10, 2006 acquisition of Kerr-McGee Corporation (“Kerr-McGee”). Because of Anadarko’s control of the Partnership through its ownership of the general partner, each acquisition of Partnership Assets, except for the Natural Buttes plant, 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. The Partnership’s historical financial statements, as presented in the Partnership’s annual report on Form 10-K for the year ended December 31, 2008, included the results attributable to the initial assets and the Powder River assets. The financial statements presented herein have been further recast to reflect the results attributable to the Chipeta assets and the Granger assets as if the Partnership had owned the 51% interest in Chipeta, the associated NGL pipeline and the Granger assets for all periods presented herein. Net income attributable to the Partnership Assets for periods prior to

F-8

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

the Partnership’s acquisition of such assets is not allocated to the limited partners for purposes of calculating net income per limited partner unit.

The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership Assets have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets and operated as a separate entity during the periods reported. In addition, certain amounts in prior periods have been reclassified to conform to the current presentation.

Limited partner and general partner units. The following table summarizes common, subordinated and general partner units issued during the years ended December 31, 2009 and 2008:

	Limited Partner Units				General
	Common		Subordinated		Partner Units		Total
Balance at December 31, 2007		—		—		—		—
Initial public offering and contribution of initial assets		26,536,306		26,536,306		1,083,115		54,155,727
Powder River acquisition		2,556,891		—		52,181		2,609,072
Balance at December 31, 2008		29,093,197		26,536,306		1,135,296		56,764,799
Chipeta acquisition		351,424		—		7,172		358,596
Equity offering		6,900,000		—		140,817		7,040,817
Long-Term Incentive Plan awards		30,304		—		618		30,922
Balance at December 31, 2009		36,374,925		26,536,306		1,283,903		64,195,134

In connection with the Granger acquisition in January 2010, the Partnership issued 620,689 common units to Anadarko and 12,667 general partner units to the Partnership’s general partner, which are not included in the table above.

Anadarko holdings of partnership equity. As of December 31, 2009, Anadarko indirectly held 1,283,903 general partner units representing a 2.0% general partner interest in the Partnership, 100% of the Partnership IDRs, 8,633,746 common units and 26,536,306 subordinated units. Anadarko’s common and subordinated unitholders owned an aggregate 54.8% limited partner interest in the Partnership. The public held 27,741,179 common units, representing a 43.2% limited partner interest in the Partnership.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of estimates. To conform to accounting principles generally accepted in the United States, 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 in the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results may differ.

Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. Changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates.

Property, plant and equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. The Partnership capitalizes all construction-related direct labor and material costs. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects which do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred.

Depreciation is computed over the asset’s estimated useful life using the straight-line method or half-year convention method, based on estimated useful lives and salvage values of assets. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, the Partnership makes estimates with respect to useful lives and salvage values that the Partnership believes are

F-9

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

reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

The Partnership evaluates its ability to recover the carrying amount of its long-lived assets and determines whether its long-lived assets have been impaired. Impairment exists 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.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset, or management’s intent to utilize the asset generally require management to reassess the cash flows related to long-lived assets.

During the year ended December 31, 2008, an impairment charge was recorded in connection with the suspension of operations of a plant at the Hilight System prior to its contribution to the Partnership. A reduction of the carrying value to fair value would represent a Level 3 fair value measure.

Equity-method investment. Fort Union is a joint venture among Copano Pipelines/Rocky Mountains, LLC (37.04%), Crestone Powder River L.L.C. (37.04%), Bargath, Inc. (11.11%) and the Partnership (14.81%). Fort Union owns a gathering pipeline and treating facilities in the Powder River Basin. The Parent is the construction manager and physical operator of the Fort Union facilities.

The Partnership’s investment in Fort Union is accounted for under the equity method of accounting. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners.

Management evaluates its equity-method investment for impairment whenever events or changes in circumstances indicate that the carrying value of such investment may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity-method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.

The investment balance at December 31, 2009 includes $3.2 million for the purchase price allocated to the investment in Fort Union in excess of Western’s historic cost basis. This balance was attributed to the difference between the fair value and book value of Fort Union’s gathering and treating facilities and is being amortized over the remaining life of those facilities. Investment earnings from Fort Union, net of investment amortization, are reported in equity income and other revenues — affiliates in the consolidated statements of income.

At December 31, 2009, Fort Union had expansion projects under construction and had project financing debt of $99.7 million outstanding, which is not guaranteed by the members. Fort Union’s lender has a lien on the Partnership’s interest in Fort Union.

Goodwill. 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. During 2009, the carrying amount of goodwill did not change. During 2008, the carrying amount of goodwill increased due to revisions in estimates of deferred tax liabilities recorded upon Anadarko’s acquisitions of Western. None of the Partnership’s goodwill is deductible for tax purposes.

F-10

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

Changes in the carrying amount of goodwill for 2009 and 2008 are as follows:

	Year Ended December 31,
	2009		2008
	(in thousands)
Balance at beginning of year	$	31,248	$	29,159
Change in goodwill associated with Anadarko’s 2006 acquisitions		—		2,089
Balance at end of year	$	31,248	$	31,248

The Partnership evaluates whether goodwill has been impaired. Impairment testing is performed annually as of October 1, unless facts and circumstances make it necessary to test more frequently. The Partnership has determined that it has one operating segment and two reporting units: (i) gathering and processing and (ii) transportation. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. Goodwill impairment assessment is a two-step process. Step one focuses on identifying a potential impairment by comparing the fair value of the reporting unit with the carrying amount of the reporting unit. If the fair value of the reporting unit exceeds its carrying amount, no further action is required. However, if the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to the implied fair value of the goodwill through a charge to operating expense based on a hypothetical purchase price allocation. No goodwill impairment has been recognized in these consolidated financial statements. A reduction of the carrying value of goodwill would represent a Level 3 fair value measure.

Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at its fair value measured using expected discounted future cash outflows of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.

Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities.

Level 2 — inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 — inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), goodwill impairment and initial recognition of asset retirement obligations.

The fair value of the note receivable from Anadarko reflects any premium or discount for the differential between the stated interest rate and quarter-end market rate, based on quoted market prices of similar debt instruments. See Note 6— Transactions with Affiliates for disclosures regarding the fair value of the note receivable from Anadarko.

F-11

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

The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. See Note 11—Debt and Interest Expense for disclosures regarding the fair value of debt.

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheet approximates fair value.

Segments. The Partnership’s operations are organized into a single business segment, the assets of which consist of natural gas gathering and processing systems, treating facilities, pipelines and related plants and equipment.

Revenue recognition. Under its fee-based arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of the natural gas it gathers or treats and recognizes gathering and treating revenues for its services at the time the service is performed.

Producers’ wells are connected to the Partnership’s gathering systems for delivery of natural gas to the Partnership’s processing or treating plants, where the natural gas is processed to extract NGLs or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered, compressed and delivered to pipelines for market delivery. Except for volumes taken in-kind by certain producers, an affiliate of Anadarko sells the natural gas and extracted NGLs attributable to processing activities. Under percent-of-proceeds contracts, revenue is recognized when the natural gas or NGLs are sold and the related product purchases are recorded as a percentage of the product sale.

Under keep-whole contracts, NGLs recovered by the processing facility are retained and sold. Producers are kept whole through the receipt of a thermally equivalent volume of residue gas at the tailgate of the plant. The keep-whole contract conveys an economic benefit to the Partnership when the individual values of the NGLs are greater as liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs are lower as liquids than as a component of the natural gas stream. Revenue is recognized from the sale of NGLs upon transfer of title.

Condensate recovered in the field and during processing is retained and sold. Depending upon contract terms, proceeds from condensate sales are either retained by the gatherer or processor or are credited to the producer. Revenue is recognized from the sale of condensate upon transfer of title.

The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. Revenues are also generated from interruptible contracts pursuant to which a fee is charged to the customer based on volumes transported through the pipeline. Revenues for transportation of natural gas are recognized over the period of firm transportation contracts or, in the case of usage fees and interruptible contracts, when the volumes are received into the pipeline. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission and reserves are established where appropriate. During the periods presented herein, there were no pending rate cases and no related reserves have been established.

Proceeds from the sale of residue gas, NGLs and condensate are recorded in natural gas, natural gas liquids and condensate revenues in the consolidated statements of income. Revenues attributable to the fixed-fee component of gathering and processing contracts as well as demand charges and commodity usage fees on transportation contracts are reported in gathering, processing and transportation of natural gas revenues in the consolidated statements of income.

Natural gas imbalances. The consolidated balance sheets include natural gas imbalance receivables and payables resulting from differences in gas volumes received into the Partnership’s systems and gas volumes delivered by the Partnership to customers. Natural gas volumes owed to or by the Partnership 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 the Partnership are valued at the Partnership’s weighted average cost of natural gas as of the balance sheet dates and are settled in-kind. As of December 31, 2009, natural gas imbalance receivables and payables were approximately $0.7 million and $1.6 million, respectively. As of December 31, 2008, natural gas imbalance receivables and payables were approximately $5.0 million and $1.4

F-12

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

million, respectively. Changes in natural gas imbalances are reported in other revenues or cost of product expense in the consolidated statements of income.

Inventory. The cost of natural gas and NGLs inventories are determined by the weighted average cost method on a location-by-location basis. Inventory is accounted for at the lower of weighted average cost or market value.

Environmental expenditures. The Partnership expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are probable and can be reasonably estimated.

Cash equivalents. The Partnership considers all highly liquid investments with an original maturity date of three months or less to be cash equivalents. The Partnership had approximately $70.0 million and $36.1 million of cash and cash equivalents as of December 31, 2009 and December 31, 2008, respectively.

Bad-debt reserve. The Partnership revenues are primarily from Anadarko, for which no credit limit is maintained. The Partnership analyzes its exposure to bad debt on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. For third-party accounts receivable, the amount of bad-debt reserve at December 31, 2009 and December 31, 2008 was approximately $114,000 and $60,000, respectively.

Equity-based compensation. Concurrent with the closing of the initial public offering, phantom unit awards were granted to independent directors of the general partner under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”), which permits the issuance of up to 2,250,000 units. The general partner awarded additional phantom units primarily to the general partner’s independent directors under the LTIP in May 2009. Upon vesting of each phantom unit, the holder will receive common units of the Partnership or, at the discretion of the general partner’s board of directors, cash in an amount equal to the market value of common units of the Partnership on the vesting date. Share-based compensation expense attributable to grants made under the LTIP will impact the Partnership’s cash flows from operating activities only to the extent cash payments are made to a participant in lieu of the actual issuance of common units to the participant upon the lapse of the relevant vesting period.

GAAP requires companies to recognize stock-based compensation as an operating expense. The Partnership amortizes stock-based compensation expense attributable to awards granted under the LTIP over the vesting periods applicable to the awards.

Additionally, 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”). Under the Incentive Plan, participants are granted Unit Value Rights (“UVRs”), Unit Appreciation Rights (“UARs”) and Dividend Equivalent Rights (“DERs”). UVRs and UARs granted under the Incentive Plan (i) are collectively valued at approximately $67.00 per unit as of December 31, 2009 and (ii) either vest ratably over three years or vest in two equal installments on the second and fourth anniversaries of the grant date, or earlier in connection with certain other events. Upon the occurrence of a UVR vesting event, each participant will receive a lump-sum cash payment (less any applicable withholding taxes) for each UVR. The UVRs may not be sold or transferred except to the general partner, Anadarko or any of its affiliates. After the occurrence of a UAR vesting event, each participant will receive a lump-sum cash payment (less any applicable withholding taxes) for each UAR that is exercised prior to the earlier of the 90th day after a participant’s voluntary termination and the 10^th anniversary of the grant date. DERs granted under the Incentive Plan vest upon the occurrence of certain events, become payable no later than 30 days subsequent to vesting and expire 10 years from the date of grant. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact the Partnership’s cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants who provided services to us pursuant to the omnibus agreement and such cash payments do not cause total annual reimbursements made by us to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth in that agreement for the periods to which such expense limit applies. Equity-based compensation granted under the Anadarko Incentive Plans does not impact the Partnership’s cash flow from operating activities. See Note 6—Transactions with Affiliates.

F-13

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

Income taxes. The Partnership generally is not subject to federal income tax, or state income tax other than Texas margin tax. Federal and state income tax expense with respect to the Partnership Assets was recorded for periods ending prior to the Partnership’s acquisition of the Partnership Assets, except for Chipeta. For periods including or subsequent to the Partnership’s acquisition of the Partnership Assets, except for Chipeta, the Partnership is no longer subject to federal income tax related to such assets and is only subject to Texas margin tax. Income attributable to Chipeta was subject to federal and state income tax for periods prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes. Accordingly, income tax expense attributable to Texas margin tax will continue to be recognized in the consolidated financial statements. For periods subsequent to the Partnership’s ownership of the Partnership Assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its share of Texas margin tax that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership.

The Partnership adopted the accounting standard for uncertain tax positions on January 1, 2007. The standard defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. The Partnership has no material uncertain tax positions at December 31, 2009 or 2008.

Net income per limited partner unit. Certain accounting standards address the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and undistributed earnings of the entity when, and if, it declares dividends on its securities. The accounting standards require securities that satisfy the definition of a “participating security” to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes to its unitholders an amount of cash equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period or any other economic or practical limitation on the ability to make a full distribution of all of the net income for the period. Earnings per unit is calculated by applying the provisions of the partnership agreement that govern actual cash distributions to the notional cash distribution amount, including giving effect to incentive distributions, when applicable, with such incentive distributions limited to the amount of available cash as defined in the partnership agreement. See Note 5—Net Income per Limited Partner Unit.

New accounting standards. The Partnership adopted new Financial Accounting Standards Board (“FASB”) staff guidance on fair-value measurement, effective January 1, 2009 which address the accounting for business combinations. This guidance expands financial disclosures, defines an acquirer and modifies the accounting for some business combination items. Under the guidance an acquirer is required to record 100% of assets and liabilities, including goodwill, contingent assets and contingent liabilities, at fair value. In addition, contingent consideration must be recognized at fair value at the acquisition date, acquisition-related costs must be expensed rather than treated as an addition to the assets acquired, and restructuring costs are required to be recognized separately from the business combination. The Partnership will apply these provisions to acquisitions of businesses from third parties that close after January 1, 2009. The guidance did not change the accounting for transfers of assets between entities under common control and, therefore, does not impact the Partnership’s accounting for asset acquisitions from Anadarko.

The Partnership adopted new accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of subsidiaries, effective January 1, 2009. Specifically, these standards require the recognition of noncontrolling interests (formerly referred to as minority interests) as a component of total equity. These standards establish a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. Dispositions of subsidiary equity are now required to be accounted for as equity transactions unless the Partnership loses control requiring deconsolidation, which would require gain or loss recognition in the statement of income. Noncontrolling interests, representing the interest in Chipeta held by Anadarko and a third party, are presented within equity for all periods presented. Finally, consolidated net income is presented to include the amounts attributable to the Parent, general and limited partners and the noncontrolling interests.

F-14

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

The Partnership adopted new accounting guidance effective January 1, 2009 that clarify that an equity method investor is required to continue to recognize an other-than-temporary impairment of its investment. In addition, an equity method investor should not separately test an investee’s underlying assets for impairment. However, an equity method investor should recognize its share of an impairment charge recorded by an investee. The initial adoption of this standard had no impact on the Partnership’s financial statements.

The Partnership also adopted new guidance which addresses the application of the two-class method in determining net income per unit for master limited partnerships having multiple classes of securities including limited partnership units, general partnership units and, when applicable, IDRs of the general partner. The guidance clarifies that the two-class method would apply to master limited partnerships, and provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. In addition, the Partnership adopted guidance addressing whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, required to be accounted for in calculating earnings per unit under the two-class method. The guidance requires companies to treat unvested equity-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per unit. The Partnership adopted these standards effective January 1, 2009 and has applied these provisions to all periods in which earnings per unit is presented. These standards did not impact earnings per unit for the periods presented herein.

The Partnership also adopted new guidance addressing subsequent events. The guidance does not change the Partnership’s accounting policy for subsequent events, but instead incorporates existing accounting and disclosure requirements related to subsequent events from auditing standards into GAAP. This standard defines subsequent events as either recognized subsequent events (events that provide additional evidence about conditions at the balance sheet date) or nonrecognized subsequent events (events that provide evidence about conditions that arose after the balance sheet date). Recognized subsequent events are recorded in the financial statements for the current period presented, while nonrecognized subsequent events are not. Both types of subsequent events require disclosure in the consolidated financial statements if those financial statements would otherwise be misleading. The adoption of this standard had no impact on the Partnership’s financial statements.

The FASB also issued new accounting standards that require the Partnership to disclose the fair value of financial instruments quarterly. The Partnership has disclosed the fair value of its note receivable from Anadarko and its long-term debt in Note 6—Transactions with Affiliates and Note 11—Debt and Interest Expense, respectively.

3. NONCONTROLLING INTERESTS

In July 2009, the Partnership acquired a 51% interest in Chipeta. Chipeta is a Delaware limited liability company formed in April 2008 to construct and operate a natural gas processing facility. As of December 31, 2009, Chipeta is owned 51% by the Partnership, 24% by Anadarko and 25% by a third-party member. The interests in Chipeta held by Anadarko and the third-party member are reflected as noncontrolling interests in the consolidated financial statements for all periods presented.

In connection with the Partnership’s acquisition of its 51% membership interest in Chipeta, the Partnership became party to Chipeta’s limited liability company agreement, as amended and restated as of July 23, 2009 (the “Chipeta LLC Agreement”), together with Anadarko and the third-party member. The Chipeta LLC Agreement provides that:

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

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

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

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

F-15

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

4. PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended June 30, 2008, the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During year ended December 31, 2009, the Partnership paid cash distributions to its unitholders of approximately $70.1 million, representing the $0.32 per-unit distribution for the quarter ended September 30, 2009, the $0.31 per-unit distribution for the quarter ended June 30, 2009 and $0.30 per-unit distributions for each of the quarters ended March 31, 2009 and December 31, 2008. During the year ended December 31, 2008, the Partnership paid cash distributions to its unitholders of approximately $24.8 million, representing the $0.1582 per-unit distribution for the quarter ended June 30, 2008 and the $0.30 per-unit distribution for the quarter ended September 30, 2008. See also Note 13—Subsequent Events concerning distributions approved in January 2010 for the quarter ended December 31, 2009.

Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures, to comply with applicable laws, debt instruments or other agreements, or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. It is intended that working capital borrowings be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.

Minimum quarterly distributions. The partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units are entitled to distributions of available cash each quarter in an amount equal to the “minimum quarterly distribution,” which is $0.30 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to subordinated units and, therefore, will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution. From its inception through December 31, 2009, the Partnership has paid equal distributions on common, subordinated and general partner units and there are no distributions in arrears on common units.

The subordination period will lapse at such time when the Partnership has paid at least $0.30 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. Also, if the Partnership has paid at least $0.45 per quarter (150% of the minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of such removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to preferred distributions on prior-quarter distribution arrearages. All subordinated units are held indirectly by Anadarko.

F-16

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

General partner interest and incentive distribution rights. The general partner is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, the Partnership’s general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

		Marginal Percentage
	Total Quarterly Distribution	Interest in Distributions
	Target Amount	Unitholders	General Partner
Minimum quarterly distribution	$0.300	98%	2%
First target distribution	up to $0.345	98%	2%
Second target distribution	above $0.345 up to $0.375	85%	15%
Third target distribution	above $0.375 up to $0.450	75%	25%
Thereafter	above $0.45	50%	50%

The table above assumes that the Partnership’s general partner maintains its 2% general partner interest, that there are no arrearages on common units and the general partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0% includes distributions paid to the general partner on its 2.0% general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.

5. NET INCOME PER LIMITED PARTNER UNIT

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

Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. However, because the initial public offering was completed on May 14, 2008, the number of units issued in connection with the initial public offering, including shares issued in connection with the partial exercise of the underwriters’ over-allotment option, is utilized for purposes of calculating basic earnings per unit for the 2008 periods that include May 14, 2008 as if the shares were outstanding from May 14, 2008. The common units and general partner units issued in connection with the Powder River acquisition, Chipeta acquisition and 2009 equity offering are included on a weighted-average basis for periods they were outstanding. The common units and general partner units issued in connection with the Granger acquisition in January 2010 are not included in the calculation of earnings per unit as they were not outstanding during the periods presented.

F-17

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

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

	Year Ended
	December 31,
	2009(1)		2008(1)
Net income attributable to Western Gas Partners, LP	$	90,276	$	107,581
Less pre-acquisition income allocated to Parent		18,868		65,478
Less general partner interest in net income		1,428		842
Limited partner interest in net income	$	69,980	$	41,261
Net income allocable to common units	$	37,035	$	20,841
Net income allocable to subordinated units		32,945		20,420
Limited partner interest in net income	$	69,980	$	41,261
Net income per limited partner unit — basic and diluted
Common units	$	1.25	$	0.78
Subordinated units	$	1.24	$	0.77
Total	$	1.24	$	0.78
Weighted average limited partner units outstanding — basic and diluted
Common units		29,684		26,680
Subordinated units		26,536		26,536
Total		56,220		53,216

⁽¹⁾ Financial information for 2009 and 2008 has been revised to include results attributable to the Granger assets and financial information for 2008 has been revised to include results attributable to the Chipeta assets. See Note 1—Description of Business and Basis of Presentation— Offerings and acquisitions.

6. TRANSACTIONS WITH AFFILIATES

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

Contribution of Partnership Assets to the Partnership. Concurrent with the closing of the initial public offering in May 2008, Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to the Partnership in exchange for a 2.0% general partner interest, 100% of the IDRs, 5,725,431 common units and 26,536,306 subordinated units. In connection with the Powder River acquisition in December 2008, Anadarko contributed the Powder River assets to the Partnership for consideration consisting of $175.0 million in cash, which was funded by a note from Anadarko, 2,556,891 common units and 52,181 general partner units. In connection with the Chipeta acquisition in July 2009, Anadarko contributed the Chipeta assets to the Partnership for consideration consisting of $101.5 million in cash, 351,424 common units and 7,172 general partner units. See Note 1—Description of Business and Basis of Presentation. See also Note 13—Subsequent Events concerning the January 2010 Granger acquisition.

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, except for Chipeta, third-party sales and purchases related such assets were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged the Partnership interest at a variable rate on outstanding affiliate balances attributable to such assets for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to parent net investment in connection with the initial public offering and the Powder River acquisition. Subsequent to our acquisition of the Partnership Assets, except for Chipeta, 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.

F-18

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

Prior to June 1, 2008, with respect to Chipeta (the date on which Anadarko initially contributed assets to Chipeta), sales and purchases related to third-party transactions were received or paid in cash by Anadarko within its centralized cash management system and were settled with Chipeta through an adjustment to parent net investment. Subsequent to June 1, 2008, Chipeta cash settled transactions directly with third parties and with Anadarko.

Note receivable from Anadarko. Concurrent with the closing of the initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest on the note is payable quarterly. The fair value of the note receivable from Anadarko was approximately $271.3 million and $198.1 million at December 31, 2009 and December 31, 2008, respectively. The fair value of the note reflects any premium or discount for the differential between the stated interest rate and quarter-end market rate, based on quoted market prices of similar debt instruments.

Notes payable to Anadarko. Concurrent with the closing of the Powder River acquisition in December 2008, the Partnership entered into a five-year, $175.0 million term loan agreement with Anadarko under which the Partnership pays Anadarko interest at a fixed rate of 4.00% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. See Note 11—Debt and Interest Expense.

Credit facilities. In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may borrow up to $100.0 million. Concurrent with the closing of the initial public offering, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. See Note 11—Debt and Interest Expense for more information on these credit facilities. See also Note 13—Subsequent Events—Granger acquisition regarding financing of the Granger acquisition.

Commodity price swap agreements. The Partnership entered into commodity price swap agreements with Anadarko in December 2008 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Hilight and Newcastle systems. In December 2009, the Partnership extended the swap agreements through December 2011. Beginning on January 1, 2009, the commodity price swap agreements fix the margin the Partnership will realize on its share of revenues under percent-of-proceeds contracts applicable to natural gas processing activities at the Hilight and Newcastle systems. In this regard, the Partnership’s notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to volumes equal in amount to the Partnership’s share of actual volumes processed at the Hilight and Newcastle systems. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument and are, therefore, not required to be measured at fair value. The Partnership reports its realized gains and losses on the commodity price swap agreements in natural gas, natural gas liquids and condensate sales — affiliates in its consolidated statements of income in the period in which the associated revenues are recognized. During the year ended December 31, 2009, the Partnership recorded realized gains of $4.1 million attributable to the commodity price swap agreements.

Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements outstanding as of December 31, 2009. The commodity price swap arrangements are for two years and the Partnership can extend the agreements, at its option, annually through December 2013. Also see Note 13—Subsequent Events—Granger acquisition for information on commodity price swap agreements entered into in January 2010.

	Year Ended December 31,
	2010		2011
	(per barrel)
Natural gasoline	$	63.20	$	68.50
Condensate	$	70.72	$	68.87
Propane	$	40.63	$	44.97
Butane	$	48.15	$	55.57
Iso butane	$	48.15	$	59.41
(per MMBtu)
Natural gas	$	5.61	$	5.61

F-19

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

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

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

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

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

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

Pursuant to the omnibus agreement, Anadarko 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. As of December 31, 2009, the Partnership’s reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership was capped at $6.9 million for the year ended December 31, 2009. In connection with the Granger acquisition, the cap under the omnibus agreement was increased to $8.3 million for the year ending December 31, 2010, subject to adjustment to reflect expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses and with the concurrence of the special committee of the Partnership’s general partner’s board of directors. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses allocated to or incurred by the Partnership as a result of being a publicly traded partnership. The consolidated financial statements of the Partnership include costs allocated by Anadarko pursuant to the omnibus agreement for periods including and subsequent to May 14, 2008. During the year ended December 31, 2009, Anadarko incurred $0.8 million of expenses in excess of the $6.9 million cap. Such expenses were recorded as a capital contribution from Anadarko and did not impact the Partnership’s cash flows. Expenses Anadarko and the general partner incurred on behalf of the Partnership subject to the cap in the omnibus agreement during the year ended December 31, 2008 did not exceed the cap.

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

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

Tax sharing agreement. Concurrent with the closing of the initial public offering, the Partnership and Anadarko entered into a tax sharing agreement pursuant to which the Partnership reimburses Anadarko for the Partnership’s share of Texas margin tax borne by Anadarko as a result of the Partnership’s results being included in a combined or consolidated tax return filed by Anadarko with respect to periods subsequent to the Partnership’s acquisition of the Partnership Assets. Anadarko may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. However, the Partnership is nevertheless required to

F-20

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

reimburse Anadarko for the tax the Partnership would have owed had the attributes not been available or used for the Partnership’s benefit, regardless of whether Anadarko pays taxes for the period.

Allocation of costs. Prior to the Partnership’s acquisition of the Partnership Assets, the consolidated financial statements of the Partnership include costs allocated by Anadarko in the form of a management services fee, which approximated the general and administrative costs attributable to the Partnership Assets. This management services fee was allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues or other contractual arrangements. Management believes these allocation methodologies are reasonable.

The employees supporting the Partnership’s operations are employees of Anadarko. Anadarko charges the Partnership its allocated share of personnel costs, including costs associated with Anadarko’s equity-based compensation plans, non-contributory defined pension and postretirement plans and defined contribution savings plan, through the management services fee or pursuant to the omnibus agreement and services and secondment agreement described above. In general, the Partnership’s reimbursement to Anadarko under the omnibus agreement or services and secondment agreements is either (i) on an actual basis for direct expenses Anadarko 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.

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

Long-term incentive plan. The general partner awarded phantom units primarily to the general partner’s independent directors under the LTIP in May 2008 and May 2009. The phantom units awarded to the independent directors vest one year from the grant date. The following table summarizes information regarding phantom units under the LTIP for the year ended December 31, 2009:

	Value per
	Unit		Units
Units outstanding at beginning of year	$	16.50		30,304
Vested	$	16.50		(30,304	)
Granted	$	15.02		21,970
Units outstanding at end of year	$	15.02		21,970

Compensation expense attributable to the phantom units granted under the LTIP is recognized entirely by the Partnership over the vesting period and was approximately $0.4 million and $0.3 million during the years ended December 31, 2009 and 2008, respectively.

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 Incentive Plan, as well as the Anadarko Incentive Plans.

The Partnership’s general and administrative expense for the years ended December 31, 2009 and 2008 included approximately $3.6 million and $1.9 million, respectively, of allocated equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans. A portion of these expenses are allocated to the Partnership by Anadarko as a component of compensation expense for the executive officers of the Partnership’s general partner and other employees pursuant to the omnibus agreement and employees who provide services to the Partnership pursuant to the services and secondment agreement. These amounts exclude compensation expense associated with the LTIP.

F-21

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

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

	Year Ended December 31,
	2009		2008			2007
	(in thousands)
Revenues	$	335,415	$	525,809		$	435,789
Operating expenses		88,054		159,377			110,110
Interest income, net		17,404		11,604			—
Interest expense		9,096		364			6,187
Distributions to unitholders		44,450		15,279			—
Contributions from noncontrolling interest owners		34,011		130,094	(1)		—
Distributions to noncontrolling interest owners		5,410		33,335			—

⁽¹⁾ Includes the $106.2 million initial contribution of assets to Chipeta in connection with Anadarko’s formation of Chipeta.

7. INCOME TAXES

The components of the Partnership’s income tax expense are as follows:

	Year Ended December 31,
	2009			2008		2007
	(in thousands)
Current income tax expense
Federal income tax expense	$	8,375		$	30,809	$	30,341
State income tax expense		266			395		313
Total current income tax expense		8,641			31,204		30,654
Deferred income tax expense
Federal income tax expense (benefit)		(1,315	)		8		9,527
State income tax expense (benefit)		(351	)		1,043		(544	)
Total deferred income tax expense (benefit)		(1,666	)		1,051		8,983
Total income tax expense	$	6,975		$	32,255	$	39,637

Total income taxes differed from the amounts computed by applying the statutory income tax rate to income before income taxes. The sources of these differences are as follows:

	Year Ended December 31,
	2009			2008			2007
	(in thousands, except percentages)
Income before income taxes	$	107,511		$	147,744		$	113,646
Statutory tax rate		35	%		35	%		35	%
Tax computed at statutory rate		37,629			51,710			39,776
Adjustments resulting from:
Partnership income not subject to federal taxes		(30,563	)		(18,919	)		—
State income taxes, net of federal tax benefit		(91	)		1,133			258
Tax status change		—			(1,674	)		—
Other		—			5			(397	)
Income tax expense	$	6,975		$	32,255		$	39,637
Effective tax rate		6	%		22	%		35	%

F-22

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

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows:

	As of December 31,
	2009			2008
	(in thousands)
Net operating loss and credit carryforwards	$	14		$	14
Net current deferred income tax assets		14			14
Depreciable property		(93,628	)		(95,752	)
Equity investment		152			—
Net operating loss and credit carryforwards		585			990
Net long-term deferred income tax liabilities		(92,891	)		(94,762	)
Total net deferred income tax liabilities	$	(92,877	)	$	(94,748	)

Credit carryforwards, which are available for utilization on future income tax returns, are as follows:

	December 31,		Statutory
	2009		Expiration
	(in thousands)
State credit	$	599		2026

8. CONCENTRATION OF CREDIT RISK

Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for the years ended December 31, 2009, 2008 and 2007. The percentage of revenues from Anadarko and the Partnership’s other customers are as follows:

	Year Ended December 31,
	2009			2008			2007
Anadarko		88	%		90	%		93	%
Other		12	%		10	%		7	%
Total		100	%		100	%		100	%

9. PROPERTY, PLANT AND EQUIPMENT

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

	Estimated		December 31,		December 31,
	useful life		2009		2008
			(dollars in thousands)
Land		n/a	$	354	$	354
Gathering systems		5 to 39 years		1,149,550		1,015,907
Pipeline and equipment		30 to 34.5 years		86,617		85,598
Assets under construction		n/a		7,552		81,469
Other		3 to 25 years		2,082		2,008
Total property, plant and equipment				1,246,155		1,185,336
Accumulated depreciation				252,778		202,523
Total net property, plant and equipment			$	993,377	$	982,813

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

Impairment. Prior to the Partnership’s acquisition of the Powder River assets, during the year ended December 31, 2008, a $9.4 million impairment was recognized related to the suspension of operations of a plant that produced iso-butane from NGLs at the Hilight system. Anadarko’s management determined the fair value of the asset based on estimates of significant unobservable inputs (level three in the GAAP fair value hierarchy), including current market values of similar equipment components.

F-23

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

10. ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations. Revisions in estimates for the periods presented relate primarily to revisions of current cost estimates, inflation rates and/or discount rates.

	Year Ended December 31,
	2009			2008			2007
				(in thousands)
Carrying amount of asset retirement obligations at beginning of period	$	13,070		$	13,340		$	12,613
Additions		1,272			1,248			102
Accretion expense		840			1,049			765
Revisions in estimates		(258	)		(2,567	)		(140	)
Carrying amount of asset retirement obligations at end of period	$	14,924		$	13,070		$	13,340

11. DEBT AND INTEREST EXPENSE

The Partnership’s outstanding debt as of December 31, 2009 and 2008 consists of its $175.0 million note payable to Anadarko due in 2013 issued in connection with the Powder River acquisition.

Term loan agreements

Five-year term loan. In December 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko in order to finance the cash portion of the consideration paid for the Powder River acquisition. The interest rate is fixed at 4.00% for the first two years and is a floating rate equal to three-month LIBOR plus 150 basis points for the final three years. The Partnership has the option to repay the outstanding principal amount in whole or in part commencing upon the second anniversary of the five-year term loan agreement.

The provisions of the five-year agreement are non-recourse to the Partnership’s general partner and limited partners and contain customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) certain events of bankruptcy or insolvency with respect to the Partnership; or (iii) a change of control. The fair value of the Partnership’s debt under the five-year term loan agreement approximate the carrying value at December 31, 2009 and December 31, 2008. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and quarter-end market rate.

Three-year term loan. In July 2009, the Partnership entered into a $101.5 million, 7.00% fixed-rate, three-year term loan agreement with Anadarko in order to finance the cash portion of the consideration paid for the Chipeta acquisition. The Partnership had the option to repay the outstanding principal amount in whole or in part upon five business days’ written notice and the Partnership repaid the three-year term loan and accrued interest on October 30, 2009.

Credit facilities

Revolving credit facility. In October 2009, the Partnership entered into a three-year senior unsecured revolving credit facility with a group of banks (the “revolving credit facility”). The aggregate initial commitments of the lenders under the revolving credit facility are $350.0 million and are expandable to a maximum of $450.0 million. As of December 31, 2009, the full $350.0 million was available for borrowing by the Partnership. The revolving credit facility matures in October 2012 and bears interest at LIBOR, plus applicable margins ranging from 2.375% to 3.250%. The Partnership is required to pay a quarterly facility fee ranging from 0.375% to 0.750% of the commitment amount (whether used or unused), based upon the Partnership’s consolidated leverage ratio, as defined in the revolving credit facility. The facility fee rate was 0.50% at December 31, 2009. In January 2010, the Partnership borrowed $210.0 million under the revolving credit facility in connection with the Granger acquisition.

The revolving credit facility contains customary covenants, customary events of default and certain financial tests, including a maximum consolidated leverage ratio, as defined in the revolving credit facility, of 4.5 to 1.0 as of the end of each quarter and a minimum consolidated interest coverage ratio, as defined in the revolving credit facility, of 3.0 to 1.0 as of the end of each quarter. If the Partnership obtains two of the following three ratings: BBB- or better by Standard and Poor’s, Baa3 or better by Moody’s Investors Service or BBB- or better by Fitch Ratings Ltd. (the date of such rating being the “Investment Grade Rating Date”), the Partnership will no longer be required to comply with certain of the foregoing covenants. All amounts due by the Partnership under the revolving credit facility are

F-24

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

unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. The subsidiary guarantees will terminate on the Investment Grade Rating Date.

Working capital facility. In May 2008, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. The facility is available exclusively to fund working capital needs. Borrowings under the facility will bear interest at the same rate that would apply to borrowings under the Anadarko credit facility described below. Pursuant to the omnibus agreement, the Partnership pays a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility, or up to $33,000 annually. The Partnership is required to reduce all borrowings under the working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility. At December 31, 2009, no borrowings were outstanding under the working capital facility.

Anadarko credit facility. In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may utilize up to $100.0 million to the extent that sufficient amounts remain available to Anadarko. Interest on borrowings under the credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.50%, or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which was 0.44% at December 31, 2009, and the commitment fees on the facility are based on Anadarko’s senior unsecured long-term debt rating. Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, the Partnership is required to reimburse Anadarko for its allocable portion of commitment fees (as of December 31, 2009, 0.11% of the Partnership’s committed and available borrowing capacity, including the Partnership’s outstanding balances, if any) that Anadarko incurs under its credit facility, or up to $0.1 million annually. Under certain of Anadarko’s credit and lease agreements, the Partnership and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. Should the Partnership or Anadarko fail to comply with any covenant in Anadarko’s credit facilities, the Partnership may not be permitted to borrow under the credit facility. Anadarko is a guarantor of the Partnership’s borrowings, if any, under the credit facility. The Partnership is not a guarantor of Anadarko’s borrowings under the credit facility. The $1.3 billion credit facility expires in March 2013. As of December 31, 2009, the full $100.0 million was available for borrowing by the Partnership.

At December 31, 2009, the Partnership was in compliance with all covenants under the five-year term loan agreement, the revolving credit facility, the working capital facility and Anadarko’s credit facility and Anadarko was in compliance with all covenants under its $1.3 billion credit facility.

Interest income (expense), net

The following table summarizes the amounts included in interest income (expense), net.

	Year Ended December 31,
	2009			2008			2007
	(in thousands)
Affiliate interest income (expense)
Interest income on note receivable from Anadarko	$	16,900		$	10,703		$	—
Interest (expense) on notes payable to Anadarko		(8,953	)		(253	)		—
Interest income (expense), net on intercompany balances		504			901			(6,187	)
Credit facility commitment fees — affiliates		(143	)		(111	)		—
Interest income (expense), net — affiliates		8,308			11,240			(6,187	)
Third-party interest expense and fees on credit facility		(859	)		—			—
Interest income (expense), net	$	7,449		$	11,240		$	(6,187	)

F-25

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

12. COMMITMENTS AND CONTINGENCIES

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

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

Lease commitments. Anadarko, on behalf of the Partnership, leases compression equipment used exclusively by the Partnership. As a result of lease modifications in October 2008, Anadarko became the owner of certain compression equipment and contributed the equipment to the Partnership, effectively terminating the lease. Anadarko, on behalf of the Partnership, continues to lease certain other compression equipment under leases expiring through January 2015. Rent expense associated with the compression equipment was approximately $1.0 million, $1.4 million and $1.5 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Anadarko also leases office space and a warehouse used by the Partnership from third parties. The office lease will expire on January 23, 2012 and there is no purchase option at the termination of the office lease. The lease for the warehouse includes an early termination clause. Rent expense associated with the office and warehouse leases was approximately $270,000 and $299,000 for the years ended December 31, 2009 and 2008, respectively. The amounts in the table below represent existing contractual lease obligations for the compression equipment, office and warehouse leases as of December 31, 2009 that may be assigned or otherwise charged to the Partnership (in thousands).

	Minimum Rental
	Payments
2010	$	970
2011		969
2012		799
2013		794
2014		311
Total	$	3,843

13. SUBSEQUENT EVENTS

Distributions. On January 21, 2010, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.33 per unit, or $21.4 million in aggregate. The cash distribution was paid on February 12, 2010 to unitholders of record at the close of business on February 1, 2010.

Granger acquisition. In January 2010, the Partnership acquired Anadarko’s entire 100% ownership interest in the Granger assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions and Note 6—Transactions with Affiliates.

In connection with the Granger acquisition, the Partnership also entered into five-year commodity price swap agreements with Anadarko effective January 1, 2010 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Granger system. Specifically, the commodity price swap agreements fix the margin the Partnership will realize under both keep-whole and percentage-of-proceeds contracts applicable to natural gas processing activities at the Granger system. In this regard, the Partnership’s notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to volumes equal in amount to the Partnership’s actual throughput subject to keep-whole or percentage-of-proceeds contracts at the Granger system. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument. The Partnership will recognize gains and losses on the commodity price swap agreements in the period in which the associated revenues are recognized. Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements for the Granger system.

F-26

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

	Year Ended December 31,
	2010		2011		2012		2013		2014
	(per barrel)
Ethane	$	28.85	$	29.31	$	29.78	$	30.10	$	30.53
Propane	$	48.76	$	50.07	$	50.93	$	51.56	$	52.37
Iso butane	$	64.07	$	66.03	$	67.22	$	68.11	$	69.23
Normal butane	$	60.03	$	61.82	$	62.92	$	63.74	$	64.78
Natural gasoline	$	73.62	$	75.99	$	77.37	$	78.42	$	79.74
Condensate	$	72.25	$	75.33	$	76.85	$	78.07	$	79.56
					(per MMBtu)
Natural gas	$	5.53	$	5.94	$	5.97	$	6.09	$	6.20

14. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

The Partnership filed a shelf registration statement on Form S-3 with the SEC, which became effective in August 2009, under which the Partnership may issue and sell up to $1.25 billion of debt and equity securities. Debt securities issued under the shelf may be guaranteed by one or more existing or future subsidiaries of the Partnership (the “Guarantor Subsidiaries”), each of which is a wholly owned subsidiary of the Partnership. The guarantees, if issued, would be full, unconditional, joint and several. The following condensed consolidating financial information reflects the Partnership’s stand-alone accounts, the combined accounts of the Guarantor Subsidiaries, the accounts of the Non-Guarantor Subsidiary, consolidating adjustments and eliminations, and the Partnership’s consolidated accounts for the each of the years in the two-year period ended December 31, 2009 and as of December 31, 2009 and December 31, 2008. The condensed consolidating financial information should be read in conjunction with the Partnership’s accompanying consolidated financial statements and related notes.

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

Statement of Income

	Year Ended December 31, 2009
	Western Gas					Non-
	Partners,			Guarantor		Guarantor
	LP			Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues	$	4,103		$	325,113	$	42,007	$	—		$	371,223
Operating expenses		18,063			232,074		21,078		—			271,215
Operating income (loss)		(13,960	)		93,039		20,929		—			100,008
Interest income, net		6,928			521		—		—			7,449
Other income, net		32			12		10		—			54
Equity income from consolidated subsidiaries		78,408			4,898		—		(83,306	)		—
Income before income taxes		71,408			98,470		20,939		(83,306	)		107,511
Income tax expense		—			6,975		—		—			6,975
Net income		71,408			91,495		20,939		(83,306	)		100,536
Net income attributable to noncontrolling interests		—			10,260		—		—			10,260
Net income attributable to Western Gas Partners, LP	$	71,408		$	81,235	$	20,939	$	(83,306	)	$	90,276

F-27

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

Statement of Income

	Year Ended December 31, 2008
	Western Gas					Non-
	Partners,			Guarantor		Guarantor
	LP			Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues	$	—		$	547,386	$	32,564	$	—		$	579,950
Operating expenses		9,124			418,157		16,361		—			443,642
Operating income (loss)		(9,124	)		129,229		16,203		—			136,308
Interest income (expense), net		10,323			917		—		—			11,240
Other income, net		139			6		51		—			196
Equity income from consolidated subsidiaries		41,871			—		—		(41,871	)		—
Income before income taxes		43,209			130,152		16,254		(41,871	)		147,744
Income tax expense		—			32,139		116		—			32,255
Net income		43,209			98,013		16,138		(41,871	)		115,489
Net income attributable to noncontrolling interests		—			7,908		—		—			7,908
Net income attributable to Western Gas Partners, LP	$	43,209		$	90,105	$	16,138	$	(41,871	)	$	107,581

F-28

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

Balance Sheet

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

Balance Sheet

	December 31, 2008
	Western Gas				Non-
	Partners,		Guarantor		Guarantor
	LP		Subsidiaries		Subsidiary		Eliminations			Consolidated
	(in thousands)
Current assets	$	33,774	$	53,638	$	2,999	$	(38,825	)	$	51,586
Note receivable — Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		523,756		—		—		(523,756	)		—
Net property, plant and equipment		273		824,250		158,290		—			982,813
Other long-term assets		628		49,431		—		—			50,059
Total assets	$	818,431	$	927,319	$	161,289	$	(562,581	)	$	1,344,458
Current liabilities	$	51,655	$	28,991	$	26,093	$	(51,317	)	$	55,422
Note payable — Anadarko		175,000		—		—		—			175,000
Other long-term liabilities		—		106,977		855		—			107,832
Total liabilities		226,655		135,968		26,948		(51,317	)		338,254
Partners’ capital and parent net investment		591,776		725,335		134,341		(511,264	)		940,188
Noncontrolling interests		—		66,016		—		—			66,016
Total liabilities, equity and partners’ capital	$	818,431	$	927,319	$	161,289	$	(562,581	)	$	1,344,458

F-29

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

Statement of Cash Flows

	Year Ended December 31, 2009
	Western Gas						Non-
	Partners,			Guarantor			Guarantor
	LP			Subsidiaries			Subsidiary			Eliminations			Consolidated
							(in thousands)
Cash flows from operating activities
Net income	$	71,408		$	91,495		$	20,939		$	(83,306	)		$100,536
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(78,408	)		(4,898	)		—			83,306			—
Depreciation, amortization and impairment		54			46,532			4,504			—			51,090
Change in other items, net		2,112			(15,618	)		(15,081	)		12,493			(16,094	)
Net cash provided by (used in) operating activities		(4,834	)		117,511			10,362			12,493			135,532
Net cash used in investing activities		—			(131,943	)		(39,378	)		—			(171,321	)
Net cash provided by financing activities		33,157			14,432			34,603			(12,493	)		69,699
Net increase in cash and cash equivalents	$	28,323		$	—		$	5,587		$	—		$	33,910
Cash and cash equivalents at beginning of period		33,307			—			2,767			—			36,074
Cash and cash equivalents at end of period	$	61,630		$	—		$	8,354		$	—		$	69,984

Statement of Cash Flows

	Year Ended December 31, 2008
	Western Gas						Non-
	Partners,			Guarantor			Guarantor
	LP			Subsidiaries			Subsidiary			Eliminations			Consolidated
							(in thousands)
Cash flows from operating activities
Net income	$	43,209		$	98,013		$	16,138		$	(41,871	)	$	115,489
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(41,871	)		—			—			41,871			—
Depreciation, amortization and impairment		39			52,829			3,008			—			55,876
Change in other items, net		51,512			(39,466	)		15,004			(12,493	)		14,557
Net cash provided by operating activities		52,889			111,376			34,150			(12,493	)		185,922
Net cash used in investing activities		(435,312	)		(63,345	)		(53,928	)		—			(552,585	)
Net cash provided by (used in) financing activities		415,730			(48,031	)		22,545			12,493			402,737
Net increase in cash and cash equivalents	$	33,307		$	—		$	2,767		$	—		$	36,074
Cash and cash equivalents at beginning of period		—			—			—			—			—
Cash and cash equivalents at end of period	$	33,307		$	—		$	2,767		$	—		$	36,074

F-30

WESTERN GAS PARTNERS, LP
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)

The following table presents a summary of the Partnership’s operating results by quarter for the years ended December 31, 2009 and 2008. Financial information for 2009 and 2008 has been revised to include results attributable to the Granger assets and financial information for 2008 has been revised to include results attributable to the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(in thousands, except per unit amounts)
2009
Revenues	$	89,160	$	93,757	$	95,006	$	93,300
Operating income	$	20,307	$	28,324	$	23,245	$	28,132
Net income attributable to Western Gas Partners, LP	$	20,586	$	25,403	$	20,330	$	23,957
Net income per limited partner unit(1)	$	0.30	$	0.32	$	0.30	$	0.33
2008
Revenues	$	152,573	$	174,565	$	157,943	$	94,869
Operating income	$	41,482	$	37,033	$	32,288	$	25,505
Net income attributable to Western Gas Partners, LP	$	25,686	$	27,894	$	29,636	$	24,365
Net income per limited partner unit(1)		—	$	0.15	$	0.32	$	0.30

⁽¹⁾  Includes net income attributable to the Partnership assets subsequent to the Partnership’s acquisition of the Partnership assets.

Cost of product expense for the fourth quarter of 2009 includes a $2.5 million out-of-period adjustment attributable to the Hilight system in which a reduction in cost of product expense related to the period from January 2008 to September 2009 was recorded in the fourth quarter of 2009. Of the adjustment, approximately $317,000, $149,000 and $152,000 is attributable to the first, second and third quarters of 2009, respectively, and approximately $364,000, ($12,000), $796,000 and $692,000 is attributable to the first, second, third and fourth quarters of 2008, respectively. Approximately $1.5 million of the adjustment attributable to 2008 is for periods prior to the Partnership’s acquisition of the asset and has no impact on the Partnership’s cash flows. The adjustment and out-of-period correction resulted in overstating earnings per limited partner unit for the year ended December 31, 2009 by $0.03 and understating earnings per limited partner unit by $0.01 for the year ended December 31, 2008. Management determined the adjustments were not material to the Partnership’s financial statements for the years ended December 31, 2009 or 2008 or to the Partnership’s interim financial statements and, accordingly, restatement of its previously reported interim or annual financials statements was not necessary.

F-31

EX-99.4

Exhibit 99.4

WESTERN GAS HOLDINGS, LLC

INDEX TO CONSOLIDATED BALANCE SHEET

Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheet as of December 31, 2009	3
Notes to the Consolidated Balance Sheet	4

WESTERN GAS HOLDINGS, LLC
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders
Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):

We have audited the accompanying consolidated balance sheet of Western Gas Holdings, LLC and subsidiaries as of December 31, 2009. This consolidated financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this consolidated financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit of a balance sheet includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit of a balance sheet also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the consolidated balance sheet provides a reasonable basis for our opinion.

In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Western Gas Holdings, LLC and subsidiaries as of December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas
May 4, 2010

2

WESTERN GAS HOLDINGS, LLC
CONSOLIDATED BALANCE SHEET

	December 31,
	2009
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	69,984
Accounts receivable, net — third parties		4,076
Accounts receivable — affiliates		2,203
Natural gas imbalance receivables — third parties		266
Natural gas imbalance receivables — affiliates		448
Other current assets		3,287
Total current assets		80,264
Other assets		2,974
Note receivable — Anadarko		260,000
Property, plant and equipment
Cost		1,246,155
Less accumulated depreciation		252,778
Net property, plant and equipment		993,377
Goodwill		31,248
Equity investment		20,060
Total assets	$	1,387,923
LIABILITIES AND EQUITY
Current liabilities
Accounts payable — third parties	$	12,003
Natural gas imbalance payable — third parties		289
Natural gas imbalance payable — affiliates		1,319
Accrued ad valorem taxes		3,046
Income taxes payable		412
Accrued liabilities — third parties		8,717
Accrued liabilities — affiliates		470
Equity-based compensation		1,500
Total current liabilities		27,756
Long-term liabilities
Note payable — Anadarko		175,000
Deferred income taxes		92,891
Equity-based compensation		2,600
Asset retirement obligations and other		15,077
Total long-term liabilities		285,568
Total liabilities		313,324
Commitments and contingencies (Note 10)		—
Equity
Member’s equity		209,876
Noncontrolling interests		864,723
Equity		1,074,599
Total liabilities and equity	$	1,387,923

See the accompanying notes to the consolidated balance sheet.

3

Notes to the consolidated balance sheet of Western Gas Holding, LLC

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Basis of presentation. Western Gas Holdings, LLC, is a Delaware limited liability company formed on August 21, 2007 to become the general partner of Western Gas Partners, LP (the Partnership), a Delaware limited partnership also formed in August 2007. Western Gas Holdings, LLC is an indirect wholly owned subsidiary of WGR Holdings, LLC (WGR Holdings), an indirect wholly owned subsidiary of Anadarko Petroleum Corporation.

The “Partnership” as used herein refers to Western Gas Partners, LP and its consolidated subsidiaries. The “Company” as used herein refers to Western Gas Holdings, LLC and its consolidated subsidiaries, including the Partnership. The “General Partner” as used herein refers to Western Gas Holdings, LLC, individually as the general partner of the Partnership and excluding the Partnership itself. “Anadarko” as used herein refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the General Partner and the Partnership. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the General Partner and the Partnership.

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

Description of business. The General Partner owns a 2.0% general partner interest in the Partnership, which constitutes substantially all of the General Partner’s business, and its primary purpose is to manage the affairs and operations of the Partnership. The Partnership’s assets consist of ten gathering systems, six natural gas treating facilities, six gas processing facilities, one NGL pipeline and one interstate pipeline. The Partnership’s assets are located in East and West Texas, the Rocky Mountains and the Mid-Continent. The Partnership is engaged in the business of gathering, compressing, processing, treating and transporting natural gas for Anadarko Petroleum Corporation and its consolidated subsidiaries (Anadarko) and third-party producers and customers.

Principles of consolidation. The accompanying consolidated balance sheet of the Company has been prepared in accordance with GAAP. The consolidated balance sheet includes the accounts of the General Partner and entities in which it holds a controlling financial interest. The General Partner consolidates the accounts of the Partnership in accordance with generally accepted accounting principles. The General Partner has no independent operations and no material assets outside those of the Partnership. The reconciling items between the Company’s consolidated balance sheet and that of the Partnership consist primarily of (i) the presentation of noncontrolling interest ownership in the Company’s net assets by the limited partners of the Partnership, (ii) the elimination of the General Partner’s investment in the Partnership with the General Partner’s underlying capital account in the Partnership and (iii) recognition of the liabilities for awards issued pursuant to the Western Gas Holdings, LLC Equity Incentive Plan as amended and restated (“Incentive Plan”). The Partnership’s borrowings are presented as a part of our consolidated debt. The General Partner will be liable, as general partner, for all of the Partnership’s debts (to the extent not paid from the Partnership’s assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. All significant intercompany transactions have been eliminated. Investments in non-controlled entities over which the Company exercises significant influence are accounted for using the equity method. The Partnership’s 50% undivided interest in the Newcastle system is consolidated on a proportionate basis. The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of financial position as of December 31, 2009.

Offerings and acquisitions.

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

Concurrent with the closing of the initial public offering, Anadarko contributed the assets and liabilities of Anadarko Gathering Company LLC (“AGC”), Pinnacle Gas Treating LLC (“PGT”) and MIGC LLC (“MIGC”) to the Partnership in exchange for 1,083,115 general partner units, representing a 2.0% general partner interest in the Partnership, 100% of the incentive distribution rights (“IDRs”), 5,725,431 common units and 26,536,306 subordinated units. The general partner units and IDRs are held by the General Partner. AGC, PGT and MIGC are referred to collectively as the “initial assets.” The

4

Notes to the consolidated balance sheet of Western Gas Holding, LLC

common units issued to Anadarko include 751,625 common units issued following the expiration of the underwriters’ over-allotment option and represent the portion of the common units for which the underwriters did not exercise their over-allotment option. See Note 3—Partnership Distributions for information related to the distribution rights of the common and subordinated unitholders and to the IDRs held by the General Partner.

Equity offering. On December 9, 2009, the Partnership closed its equity offering of 6,000,000 common units to the public at a price of $18.20 per unit. On December 17, 2009, the Partnership issued an additional 900,000 units to the public pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the equity offering. The December 9 and December 17, 2009 issuances are referred to collectively as the “2009 equity offering.” Net proceeds from the offering of approximately $122.5 million were used to repay $100.0 million outstanding under the Partnership’s revolving credit facility (see Note 9—Debt) and to partially fund the January 2010 Granger acquisition referenced below. In connection with the 2009 equity offering, the Partnership issued 140,817 general partner units to the General Partner.

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

Chipeta acquisition. In July 2009, the Partnership acquired certain midstream assets from Anadarko for (i) approximately $101.5 million in cash, which was financed by borrowing $101.5 million from Anadarko pursuant to the terms of a 7.0% fixed-rate, three-year term loan agreement, and (ii) the issuance of 351,424 common units and 7,172 general partner units, which were issued to the General Partner. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. The acquisition consisted of a 51% membership interest in Chipeta Processing LLC (“Chipeta”), together with an associated NGL pipeline. Chipeta owns a natural gas processing plant complex, which includes two recently completed processing trains: a refrigeration unit completed in November 2007 and a cryogenic unit which was completed in April 2009. The 51% membership interest in Chipeta and associated NGL pipeline are referred to collectively as the “Chipeta assets” and the acquisition is referred to as the “Chipeta acquisition.”

In November 2009, Chipeta closed its acquisition of a compressor station and processing plant (the “Natural Buttes plant,” which was formerly known as the CIG 101 plant prior to the Partnership’s acquisition) from a third party for $9.1 million. The noncontrolling interest owners contributed $4.5 million to Chipeta during the year ended December 31, 2009 to fund their proportionate share of the Natural Buttes plant acquisition. The Natural Buttes plant is located in Uintah County, Utah.

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 plus cash on hand, and (ii) the issuance of 620,689 common units and 12,667 general partner units. The assets acquired represent Anadarko’s entire 100% ownership interest in the following assets located in Southwestern Wyoming: (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains, two refrigeration trains, an NGLs fractionation facility and ancillary equipment. These assets are referred to collectively as the “Granger assets” and the acquisition is referred to as the “Granger acquisition.” The Granger acquisition is reflected herein as if the Partnership owned the Granger assets on December 31, 2009.

Presentation of Partnership acquisitions. For purposes of this consolidated balance sheet the initial assets, Powder River assets, Chipeta assets, and Granger assets are referred to collectively as the “Partnership Assets.” Anadarko acquired MIGC, the Powder River assets and the Granger assets in connection with its August 23, 2006 acquisition of Western Gas Resources, Inc. (“Western”) and Anadarko acquired the Chipeta assets in connection with its August 10, 2006 acquisition of Kerr-McGee Corporation (“Kerr-McGee”). Because of Anadarko’s control of the Partnership through its ownership of the General Partner, each acquisition of Partnership Assets, except for the Natural Buttes plant, 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. The assets the Partnership acquired from Anadarko are recorded at Anadarko’s carrying value prior to each transaction.

Receivables and payables between the Company and Anadarko have been identified in the consolidated balance sheet as balances with affiliates. Please see Note 4—Transactions with Affiliates.

5

Notes to the consolidated balance sheet of Western Gas Holding, LLC

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of estimates. To conform to accounting principles generally accepted in the United States, management makes estimates and assumptions that affect the amounts reported in the consolidated balance sheet and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable in the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results may differ.

Effects on the Company’s business and financial position resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. Changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates.

Property, plant and equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. The Company capitalizes all construction-related direct labor and material costs. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects which do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred.

Depreciation is computed over the asset’s estimated useful life using the straight-line method or half-year convention method, based on estimated useful lives and salvage values of assets. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, the Company makes estimates with respect to useful lives and salvage values that the Company believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

The Company evaluates its ability to recover the carrying amount of its long-lived assets and determines whether its long-lived assets have been impaired. Impairment exists 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.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset, or management’s intent to utilize the asset generally require management to reassess the cash flows related to long-lived assets.

No impairment charge for long lived assets has been recognized in the financial statements for the period presented. A reduction of the carrying value to fair value would represent a Level 3 fair value measure.

Equity-method investment. Fort Union is a joint venture among Copano Pipelines/Rocky Mountains, LLC (37.04%), Crestone Powder River L.L.C. (37.04%), Bargath, Inc. (11.11%) and the Partnership (14.81%). Fort Union owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities.

The Company’s investment in Fort Union is accounted for under the equity method of accounting. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require either 65% or unanimous approval of the owners.

Management evaluates its equity-method investment for impairment whenever events or changes in circumstances indicate that the carrying value of such investment may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity-method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.

6

Notes to the consolidated balance sheet of Western Gas Holding, LLC

The investment balance at December 31, 2009 includes $3.2 million for the purchase price allocated to the investment in Fort Union in excess of Western’s historic cost basis. This balance was attributed to the difference between the fair value and book value of Fort Union’s gathering and treating facilities and is being amortized over the remaining life of those facilities.

At December 31, 2009, Fort Union had expansion projects under construction and had project financing debt of $99.7 million outstanding, which is not guaranteed by the members. Fort Union’s lender has a lien on the Company’s interest in Fort Union.

Goodwill. 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. During 2009, the carrying amount of goodwill did not change.

The Company evaluates whether goodwill has been impaired. Impairment testing is performed annually as of October 1, unless facts and circumstances make it necessary to test more frequently. The Company has determined that it has one operating segment and two reporting units: (i) gathering and processing and (ii) transportation. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. Goodwill impairment assessment is a two-step process. Step one focuses on identifying a potential impairment by comparing the fair value of the reporting unit with the carrying amount of the reporting unit. If the fair value of the reporting unit exceeds its carrying amount, no further action is required. However, if the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to the implied fair value of the goodwill through a charge to operating expense based on a hypothetical purchase price allocation. A reduction of the carrying value of goodwill would represent a Level 3 fair value measure.

Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at its fair value measured using expected discounted future cash outflows of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.

Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities.

Level 2 — inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 — inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), goodwill impairment and initial recognition of asset retirement obligations.

The fair value of the note receivable from Anadarko reflects any premium or discount for the differential between the stated interest rate and quarter-end market rate, based on quoted market prices of similar debt instruments. See Note 4— Transactions with Affiliates for disclosures regarding the fair value of the note receivable from Anadarko.

The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance

7

Notes to the consolidated balance sheet of Western Gas Holding, LLC

sheet date for those debt instruments for which quoted market prices are not available. See Note 9—Debt for disclosures regarding the fair value of debt.

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheet approximates fair value.

Segments. The Partnership’s operations are organized into a single business segment, the assets of which consist of natural gas gathering and processing systems, treating facilities, pipelines and related plants and equipment.

Natural gas imbalances. The consolidated balance sheet includes natural gas imbalance receivables and payables resulting from differences in gas volumes received into the Partnership’s systems and gas volumes delivered by the Partnership to customers. Natural gas volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet date, and generally reflect market index prices. Other natural gas volumes owed to or by the Partnership are valued at the Partnership’s weighted average cost of natural gas as of the balance sheet date and are settled in-kind.

Inventory. The cost of natural gas and NGLs inventories are determined by the weighted average cost method on a location-by-location basis. Inventory is accounted for at the lower of weighted average cost or market value.

Environmental expenditures. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are probable and can be reasonably estimated.

Cash equivalents. The Company considers all highly liquid investments with an original maturity date of three months or less to be cash equivalents. The Company had approximately $70.0 million of cash and cash equivalents as of December 31, 2009.

Bad-debt reserve. The Company’s revenues are primarily from Anadarko, for which no credit limit is maintained. The Company analyzes its exposure to bad debt on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. For third-party accounts receivable, the amount of bad-debt reserve at December 31, 2009 was approximately $114,000.

Equity-based compensation. Concurrent with the closing of the initial public offering, phantom unit awards were granted to independent directors of the General Partner under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”), which permits the issuance of up to 2,250,000 units. The General Partner awarded additional phantom units primarily to the General Partner’s independent directors under the LTIP in May 2009. Upon vesting of each phantom unit, the holder will receive common units of the Partnership or, at the discretion of the General Partner’s board of directors, cash in an amount equal to the market value of common units of the Partnership on the vesting date. Share-based compensation expense attributable to grants made under the LTIP will impact the Company’s cash flows from operating activities only to the extent cash payments are made to a participant in lieu of the actual issuance of common units to the participant upon the lapse of the relevant vesting period.

GAAP requires companies to recognize stock-based compensation as an operating expense. The Company amortizes stock-based compensation expense attributable to awards granted under the LTIP over the vesting periods applicable to the awards.

Under the Western Gas Holdings, LLC Equity Incentive Plan as amended and restated (“Incentive Plan”), participants are granted Unit Value Rights (“UVRs”), Unit Appreciation Rights (“UARs”) and Dividend Equivalent Rights (“DERs”). UVRs and UARs granted under the Incentive Plan (i) are collectively valued at approximately $67.00 per unit as of December 31, 2009 and (ii) either vest ratably over three years or vest in two equal installments on the second and fourth anniversaries of the grant date, or earlier in connection with certain other events. Upon the occurrence of a UVR vesting event, each participant will receive a lump-sum cash payment (less any applicable withholding taxes) for each UVR. The UVRs may not be sold or transferred except to the General Partner, Anadarko or any of its affiliates. After the occurrence of a UAR vesting event, each participant will receive a lump-sum cash payment (less any applicable withholding taxes) for each unit appreciation right that is exercised prior to the earlier of the 90th day after a participant’s voluntary termination and the 10^th anniversary of the grant date. DERs granted under the Incentive Plan vest upon the occurrence of certain events, become payable no later than 30 days subsequent to vesting and expire 10 years from the date of grant. See Note 5—Equity Based Compensation.

Income taxes. The Company and the Partnership generally are not subject to federal income tax, or state income tax other than Texas margin tax. The Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its share of Texas margin tax that are included in any combined or consolidated returns filed by Anadarko. Accordingly, the Company’s consolidated deferred tax liability consists of the Partnership’s

8

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

estimated liability for this tax. The aggregate difference in the basis of the Company’s assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each partner’s tax attributes in the Company.

The Company adopted the accounting standard for uncertain tax positions on January 1, 2007. The standard defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. The Company has no material uncertain tax positions at December 31, 2009.

Limited partner and general partner units. The following table summarizes common, subordinated and general partner units issued by the Partnership during the year ended December 31, 2009:

	Limited Partner Units				General
	Common		Subordinated		Partner Units		Total
Balance at December 31, 2008		29,093,197		26,536,306		1,135,296		56,764,799
Chipeta acquisition		351,424		—		7,172		358,596
Equity offering		6,900,000		—		140,817		7,040,817
Long-Term Incentive Plan awards		30,304		—		618		30,922
Balance at December 31, 2009		36,374,925		26,536,306		1,283,903		64,195,134

In connection with the Granger acquisition in January 2010, the Partnership issued 620,689 common units to Anadarko and 12,667 general partner units to the Partnership’s general partner, which are not included in the table above.

All of the general partner units are held by the General Partner. As of December 31, 2009, WGR Holdings indirectly held 8,633,746 common units and 26,536,306 subordinated units, representing an aggregate 54.8% limited partner interest in the Partnership. The public held 27,741,179 common units, representing a 43.2% limited partner interest in the Partnership.

Noncontrolling interests in the Company. Noncontrolling interests on the Company’s consolidated balance sheet include affiliate and public ownership interests in the Partnership’s net assets through (1) the Partnership’s publicly traded common units owned by the public and (2) the Partnership’s common and subordinated units owned by Anadarko. In addition, the noncontrolling interests on the Company’s consolidated balance sheet include the ownership interests in Chipeta held by Anadarko and a third party. The noncontrolling interests related to the affiliate and public ownership in the Partnership reflects the sum of the allocation of the Partnership’s net income to the limited partners and contributions to the Partnership from the limited partners, partially offset by distributions paid to the limited partners.

New accounting standards. The Company adopted new Financial Accounting Standards Board (“FASB”) staff guidance on fair-value measurement, effective January 1, 2009 which address the accounting for business combinations. This guidance expands financial disclosures, defines an acquirer and modifies the accounting for some business combination items. Under the guidance an acquirer is required to record 100% of assets and liabilities, including goodwill, contingent assets and contingent liabilities, at fair value. In addition, contingent consideration must be recognized at fair value at the acquisition date, acquisition-related costs must be expensed rather than treated as an addition to the assets acquired, and restructuring costs are required to be recognized separately from the business combination. The Company will apply these provisions to acquisitions of businesses from third parties that close after January 1, 2009. The guidance did not change the accounting for transfers of assets between entities under common control and, therefore, does not impact the Company’s accounting for asset acquisitions from Anadarko.

The Company adopted new accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of subsidiaries, effective January 1, 2009. Specifically, these standards require the recognition of noncontrolling interests (formerly referred to as minority interests) as a component of total equity. These standards establish a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. Dispositions of subsidiary equity are now required to be accounted for as equity transactions unless the Company loses control requiring deconsolidation, which would require gain or loss recognition in the statement of income.

The Company adopted new accounting guidance effective January 1, 2009 that clarify that an equity method investor is required to continue to recognize an other-than-temporary impairment of its investment. In addition, an equity method investor should not separately test an investee’s underlying assets for impairment. However, an equity method investor should recognize its share of an impairment charge recorded by an investee. The initial adoption of this standard had no impact on the Company’s financial statements.

The Company also adopted new guidance addressing subsequent events. The guidance does not change the Company’s accounting policy for subsequent events, but instead incorporates existing accounting and disclosure requirements related to

9

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

subsequent events from auditing standards into GAAP. This standard defines subsequent events as either recognized subsequent events (events that provide additional evidence about conditions at the balance sheet date) or nonrecognized subsequent events (events that provide evidence about conditions that arose after the balance sheet date). Recognized subsequent events are recorded in the financial statements for the current period presented, while nonrecognized subsequent events are not. Both types of subsequent events require disclosure in the consolidated financial statements if those financial statements would otherwise be misleading. The adoption of this standard had no impact on the Company’s financial statements. Management has evaluated subsequent events through May 4, 2010, the date the financial statements were available to be issued.

3. PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended June 30, 2008, the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During year ended December 31, 2009, the Partnership paid cash distributions to its unitholders of approximately $70.1 million, including approximately $1.4 million of distributions paid to the General Partner. Distributions for the year ended December 31, 2009 consist of the $0.32 per-unit distribution for the quarter ended September 30, 2009, the $0.31 per-unit distribution for the quarter ended June 30, 2009 and $0.30 per-unit distributions for each of the quarters ended March 31, 2009 and December 31, 2008. See also Note 11—Subsequent Events concerning distributions approved in January 2010 for the quarter ended December 31, 2009.

Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, less the amount of cash reserves established by the General Partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures, to comply with applicable laws, debt instruments or other agreements, or to provide funds for distributions to its unitholders and to the General Partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. It is intended that working capital borrowings be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.

Minimum quarterly distributions. The partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units are entitled to distributions of available cash each quarter in an amount equal to the “minimum quarterly distribution,” which is $0.30 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to subordinated units and, therefore, will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution. From its inception through December 31, 2009, the Partnership has paid equal distributions on common, subordinated and general partner units and there are no distributions in arrears on common units.

The subordination period will lapse at such time when the Partnership has paid at least $0.30 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. Also, if the Partnership has paid at least $0.45 per quarter (150% of the minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the General Partner is removed without cause and the units held by the General Partner and its affiliates are not voted in favor of such removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to preferred distributions on prior-quarter distribution arrearages. All subordinated units are held indirectly by Anadarko.

10

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

General partner interest and incentive distribution rights. The General Partner, is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, the General Partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

			Marginal Percentage
	Total Quarterly Distribution		Interest in Distributions
	Target Amount		Unitholders			General Partner
Minimum quarterly distribution	$	0.300		98	%		2	%
First target distribution	up to $0.345			98	%		2	%
Second target distribution	above $0.345 up to $0.375			85	%		15	%
Third target distribution	above $0.375 up to $0.450			75	%		25	%
Thereafter	above $0.45			50	%		50	%

The table above assumes that the General Partner maintains its 2% general partner interest, that there are no arrearages on common units and the General Partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0% includes distributions paid to the General Partner on its 2.0% general partner interest and does not include any distributions that the General Partner may receive on limited partner units that it owns or may acquire.

4. TRANSACTIONS WITH AFFILIATES

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

Contribution of Partnership Assets to the Partnership. In connection with the Chipeta acquisition in July 2009, Anadarko contributed the Chipeta assets to the Partnership for consideration consisting of $101.5 million in cash and additional common and general partner units. See Note 1—Description of Business and Basis of Presentation. See also Note 11—Subsequent Events concerning the January 2010 Granger acquisition.

Note receivable from Anadarko. Concurrent with the closing of the initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest on the note is payable quarterly. The fair value of the note receivable from Anadarko was approximately $271.3 million at December 31, 2009. The fair value of the note reflects any premium or discount for the differential between the stated interest rate and quarter-end market rate, based on quoted market prices of similar debt instruments.

Note payable to Anadarko. Concurrent with the closing of the Powder River acquisition in December 2008, the Partnership entered into a five-year, $175.0 million term loan agreement with Anadarko under which the Partnership pays Anadarko interest at a fixed rate of 4.00% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. See Note 9—Debt.

Credit facilities. In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may borrow up to $100.0 million. Concurrent with the closing of the initial public offering, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. See Note 9—Debt for more information on these credit facilities. See also Note 11—Subsequent Events—Granger acquisition regarding financing of the Granger acquisition.

Commodity price swap agreements. The Partnership entered into commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Hilight and Newcastle systems. Beginning on January 1, 2009, the commodity price swap agreements fix the margin the Partnership will realize on its share of revenues under percent-of-proceeds contracts applicable to natural gas processing activities at the Hilight and Newcastle systems. In this regard, the Partnership’s notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to volumes equal in amount to the Partnership’s share of actual volumes processed at the Hilight and Newcastle systems. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument and are, therefore, not required to be measured at fair value.

11

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements outstanding as of December 31, 2009. The commodity price swap arrangements are for two years and the Partnership can extend the agreements, at its option, annually through December 2013. Also see Note 11—Subsequent Events—Granger acquisition for information on commodity price swap agreements entered into in January 2010.

	Year Ended December 31,
	2010		2011
	(per barrel)
Natural gasoline	$	63.20	$	68.50
Condensate	$	70.72	$	68.87
Propane	$	40.63	$	44.97
Butane	$	48.15	$	55.57
Iso butane	$	48.15	$	59.41

	(per MMBtu)
Natural gas	$	5.61	$	5.61

Omnibus agreement. Concurrent with the closing of the initial public offering, the General Partner and the Partnership entered into an omnibus agreement with Anadarko that addresses the following:

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

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

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

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

Pursuant to the omnibus agreement, Anadarko 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. As of December 31, 2009, the Partnership’s reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership was capped at $6.9 million for the year ended December 31, 2009. In connection with the Granger acquisition, the cap under the omnibus agreement was increased to $8.3 million for the year ending December 31, 2010, subject to adjustment to reflect expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses and with the concurrence of the special committee of the General Partner’s board of directors. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses allocated to or incurred by the Partnership as a result of being a publicly traded partnership.

Services and secondment agreement. Concurrent with the closing of the initial public offering, the General Partner and Anadarko entered into a services and secondment agreement pursuant to which specified employees of Anadarko are seconded to the General Partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the General Partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement is 10 years and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination before the applicable twelve-month period expires.

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

Tax sharing agreement. Concurrent with the closing of the initial public offering, the Partnership and Anadarko entered into a tax sharing agreement pursuant to which the Partnership reimburses Anadarko for the Partnership’s share of Texas margin tax borne by Anadarko as a result of the Partnership’s results being included in a combined or consolidated tax return filed by

12

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

Anadarko with respect to periods subsequent to the Partnership’s acquisition of the Partnership Assets. Anadarko may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. However, the Partnership is nevertheless required to reimburse Anadarko for the tax the Partnership would have owed had the attributes not been available or used for the Partnership’s benefit, regardless of whether Anadarko pays taxes for the period.

Allocation of costs. The employees supporting the Company’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.

5. EQUITY-BASED COMPENSATION

Equity-based compensation. Grants made under equity-based compensation plans result in equity-based compensation expense which is determined by reference to the fair value of equity compensation as of the date of the relevant equity grant. The following table summarizes information regarding UVRs, UARs and DERs issued under the Incentive Plan for the year ended December 31, 2009:

	UVRs			UARs			DERs
Outstanding at beginning of year		50,000			50,000			50,000
Granted		30,000			30,000			30,000
Vested or settled (1)		(16,667	)		—			—
Forfeited		(6,666	)		(6,666	)		(6,666	)
Outstanding at end of year		56,667			73,334			73,334
Weighted average value at December 31, 2009	$	50.00		$	17.00			—	(2)

(1)	UARs and DERs remain outstanding upon vesting until they are settled in cash, are forfeited or expire. As of December 31, 2009, 16,667 of the outstanding UARs and 3,334 of the DERs were vested.
(2)	The DERs have no attributed value as the General Partner has not declared or paid distributions since its inception.

The value per unit of the UVRs and UARs was based on the estimated fair value of the General Partner pursuant to the provisions of the Incentive Plan using a discounted cash flow and multiples valuation approach.

13

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

6. INCOME TAXES

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows:

	December 31, 2009
	(in thousands)
Net operating loss and credit carryforwards	$	14
Net current deferred income tax assets		14
Depreciable property		(93,628	)
Equity investment		152
Net operating loss and credit carryforwards		585
Net long-term deferred income tax liabilities		(92,891	)
Total net deferred income tax liabilities	$	(92,877	)

Credit carryforwards, which are available for utilization on future income tax returns, are as follows:

	December 31,		Statutory
	2009		Expiration
	(in thousands)
State credit	$	599		2026

7. PROPERTY, PLANT AND EQUIPMENT

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

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

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

8. ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations for the year ended December 31, 2009 (in thousands).

Carrying amount of asset retirement obligations at beginning of year	$	13,070
Additions		1,272
Accretion expense		840
Revisions in estimates		(258	)
Carrying amount of asset retirement obligations at end of year	$	14,924

9. DEBT

The Company’s outstanding debt as of December 31, 2009 consists of its $175.0 million note payable to Anadarko due in 2013 issued in connection with the Powder River acquisition.

Term loan agreements

Five-year term loan. In December 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko in order to finance the cash portion of the consideration paid for the Powder River acquisition. The interest rate is fixed at 4.00% for the first two years and is a floating rate equal to three-month LIBOR plus 150 basis points for the final

14

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

three years. The Partnership has the option to repay the outstanding principal amount in whole or in part commencing upon the second anniversary of the five-year term loan agreement.

The provisions of the five-year agreement are non-recourse to the General Partner and limited partners and contain customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) certain events of bankruptcy or insolvency with respect to the Partnership; or (iii) a change of control. The fair value of the debt under the five-year term loan agreement approximate the carrying value at December 31, 2009. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and quarter-end market rate.

Three-year term loan. In July 2009, the Partnership entered into a $101.5 million, 7.00% fixed-rate, three-year term loan agreement with Anadarko in order to finance the cash portion of the consideration paid for the Chipeta acquisition. The Partnership had the option to repay the outstanding principal amount in whole or in part upon five business days’ written notice and the Partnership repaid the three-year term loan and accrued interest on October 30, 2009.

Credit facilities

Revolving credit facility. In October 2009, the Partnership entered into a three-year senior unsecured revolving credit facility with a group of banks (the “revolving credit facility”). The aggregate initial commitments of the lenders under the revolving credit facility are $350.0 million and are expandable to a maximum of $450.0 million. As of December 31, 2009, the full $350.0 million was available for borrowing by the Partnership. The revolving credit facility matures in October 2012 and bears interest at LIBOR, plus applicable margins ranging from 2.375% to 3.250%. The Partnership is required to pay a quarterly facility fee ranging from 0.375% to 0.750% of the commitment amount (whether used or unused), based upon the Partnership’s consolidated leverage ratio, as defined in the revolving credit facility. The facility fee rate was 0.50% at December 31, 2009. In January 2010, the Partnership borrowed $210.0 million under the revolving credit facility in connection with the Granger acquisition.

The revolving credit facility contains various customary covenants, customary events of default and certain financial tests, including a maximum consolidated leverage ratio, as defined in the revolving credit facility, of 4.5 to 1.0 as of the end of each quarter and a minimum consolidated interest coverage ratio, as defined in the revolving credit facility, of 3.0 to 1.0 as of the end of each quarter. If the Partnership obtains two of the following three ratings: BBB- or better by Standard and Poor’s, Baa3 or better by Moody’s Investors Service or BBB- or better by Fitch Ratings Ltd. (the date of such rating being the “Investment Grade Rating Date”), the Partnership will no longer be required to comply with certain of the foregoing covenants. All amounts due by the Partnership under the revolving credit facility are unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. The subsidiary guarantees will terminate on the Investment Grade Rating Date.

Working capital facility. In May 2008, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. The facility is available exclusively to fund working capital needs. Borrowings under the facility will bear interest at the same rate that would apply to borrowings under the Anadarko credit facility described below. Pursuant to the omnibus agreement, the Partnership pays a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility, or up to $33,000 annually. The Partnership is required to reduce all borrowings under the working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility. At December 31, 2009, no borrowings were outstanding under the working capital facility.

Anadarko credit facility. In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may utilize up to $100.0 million to the extent that sufficient amounts remain available to Anadarko. Interest on borrowings under the credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.50%, or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which was 0.44% at December 31, 2009, and the commitment fees on the facility are based on Anadarko’s senior unsecured long-term debt rating. Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, the Partnership is required to reimburse Anadarko for its allocable portion of commitment fees (as of December 31, 2009, 0.11% of the Partnership’s committed and available borrowing capacity, including the Partnership’s outstanding balances, if any) that Anadarko incurs under its credit facility, or up to $0.1 million annually. Under certain of Anadarko’s credit and lease agreements, the Partnership and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. Should the Partnership or Anadarko fail to comply with any covenant in Anadarko’s credit facilities, the Partnership may not be permitted to borrow under the credit facility. Anadarko is a guarantor of the Partnership’s borrowings, if any, under the credit facility. The Partnership is not a guarantor of Anadarko’s borrowings under the credit facility. The $1.3 billion credit facility expires in March 2013. As of December 31, 2009, the full $100.0 million was available for borrowing by the Partnership.

15

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

At December 31, 2009, the Partnership was in compliance with all covenants under the five-year term loan agreement, the revolving credit facility, the working capital facility and Anadarko’s credit facility and Anadarko was in compliance with all covenants under its $1.3 billion credit facility.

10. COMMITMENTS AND CONTINGENCIES

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

Litigation and legal proceedings. From time to time, the Company 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 Company’s financial position.

Lease commitments. Anadarko leases compression equipment, office space and a warehouse used by the Company from a third party. The compression equipment leases will expire through January 2015. The office lease will expire on January 23, 2012 and there is no purchase option at the termination of the office lease. The warehouse lease includes an early termination clause. The amounts in the table below represent existing contractual lease obligations for the compression equipment, office and warehouse leases as of December 31, 2009 that may be assigned or otherwise charged to the Company (in thousands).

	Minimum Rental
	Payments
2010	$	970
2011		969
2012		799
2013		794
2014		311
Total	$	3,843

11. SUBSEQUENT EVENTS

Distributions. On January 21, 2010, the board of directors of the General Partner declared a cash distribution to the Partnership’s unitholders of $0.33 per unit, or $21.4 million in aggregate, including approximately $428,000 of distributions to the General Partner. The cash distribution was paid on February 12, 2010 to unitholders of record at the close of business on February 1, 2010. On April 20, 2010, the board of directors of the General Partner declared a cash distribution to the Partnership’s unitholders of $0.34 per unit, or $22.0 million in aggregate, including approximately $441,000 of distributions to the General Partner. The cash distribution is payable on May 12, 2010 to unitholders of record at the close of business on April 30, 2010.

Granger acquisition. In January 2010, the Partnership acquired Anadarko’s entire 100% ownership interest in the Granger assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions and Note 4—Transactions with Affiliates.

In connection with the Granger acquisition, the Partnership also entered into five-year commodity price swap agreements with Anadarko effective January 1, 2010 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Granger system. Specifically, the commodity price swap agreements fix the margin the Partnership will realize under both keep-whole and percentage-of-proceeds contracts applicable to natural gas processing activities at the Granger system. In this regard, the Partnership’s notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to volumes equal in amount to the Partnership’s actual throughput subject to keep-whole or percentage-of-proceeds contracts at the Granger system. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument. The Partnership will recognize gains and losses on the commodity price swap agreements in

16

Notes to the consolidated balance sheet of Western Gas Holdings, LLC

the period in which the associated revenues are recognized. Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements for the Granger system.

	Year Ended December 31,
	2010		2011			2012		2013		2014
	(per barrel)
Ethane	$	28.85	$	29.31		$	29.78	$	30.10	$	30.53
Propane	$	48.76	$	50.07		$	50.93	$	51.56	$	52.37
Iso butane	$	64.07	$	66.03		$	67.22	$	68.11	$	69.23
Normal butane	$	60.03	$	61.82		$	62.92	$	63.74	$	64.78
Natural gasoline	$	73.62	$	75.99		$	77.37	$	78.42	$	79.74
Condensate	$	72.25	$	75.33		$	76.85	$	78.07	$	79.56
					(per MMBtu)
Natural gas	$	5.53	$	5.94		$	5.97	$	6.09	$	6.20

17