8-K

UNITED STATES

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 22, 2012

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)

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

1201 Lake Robbins Drive

The Woodlands, Texas 77380-1046

(Address of principal executive offices) (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 (see General Instruction A.2. below):

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

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

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

¨ 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 January 17, 2012, 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 affiliates of Anadarko Petroleum Corporation (“Anadarko”), consisting of a 100% ownership interest in Mountain Gas Resources, LLC (or “MGR”), which owns (i) the Red Desert complex, located in the greater Green River Basin in southwestern Wyoming, including the Patrick Draw processing plant with a capacity of 125 MMcf/d, the Red Desert processing plant with a capacity of 48 MMcf/d, 1,295 miles of gathering lines, and related facilities; (ii) a 22% interest in Rendezvous Gas Services, LLC (“Rendezvous”), which owns a 338-mile mainline gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming; and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.” The consideration paid by the Partnership for the MGR acquisition consisted of (i) $458.6 million in cash, (ii) 632,783 common units of the Partnership and (iii) 12,914 general partner units of the Partnership issued to the Partnership’s general partner, Western Gas Holdings, LLC (the “general partner” or “GP”). The Partnership funded the cash consideration through (i) $299.0 million in borrowings under its revolving credit facility and (ii) $159.6 million of cash on hand. The terms of the MGR acquisition were approved by the Board of Directors of the GP and by the Board’s special committee on December 15, 2011. The MGR acquisition closed on January 13, 2012, with an effective date of January 1, 2012.

On March 27, 2012, 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 MGR assets 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 MGR acquisition was considered a transfer of net assets between entities under common control. As a result, the Partnership is required to recast its financial statements to include the activities of the MGR assets as of the date of common control. 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 MGR assets as if the Partnership owned the MGR assets since August 23, 2006, the date Anadarko acquired the MGR assets in connection with its acquisition of Western Gas Resources, Inc.

The Partnership’s Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”), as filed with the Securities and Exchange Commission (the “SEC”) on February 28, 2012, is hereby recast 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 filed under Part IV, Item 15 of the 2011 Form 10-K;

• the Selected Financial and Operating Data of the Partnership included herein on Exhibit 99.1 supersedes Part II, Item 6 of the 2011 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 Part II, Item 7 of the 2011 Form 10-K; and

• the Financial Statements and Supplementary Data of the Partnership included herein on Exhibit 99.3 supersedes Part II, Item 8 of the 2011 Form 10-K, except for the Report of Management, 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 91 and 92 of the 2011 Form 10-K, respectively, which are not impacted by this Current Report on Form 8-K.

There have been no revisions or updates to any other sections of the 2011 Form 10-K other than the revisions noted above. This Current Report on Form 8-K should be read in conjunction with the 2011 Form 10-K, and any references herein to Items 6, 7 and 8 under Part II of the 2011 Form 10-K refer to Exhibits 99.1, 99.2, and 99.3, respectively. 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, as well as future quarterly and annual reports on Form 10-Q and Form 10-K, respectively.

Item 9.01    Financial Statements and Exhibits.

(d)	Exhibits
	12.1	Computation of Ratio of Earnings to Fixed Charges.
	23.1	Consent of KPMG LLP.
	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.
	101.INS	XBRL Instance Document.
	101.SCH	XBRL Schema Document.
	101.CAL	XBRL Calculation Linkbase Document.
	101.LAB	XBRL Label Linkbase Document.
	101.PRE	XBRL Presentation Linkbase Document.
	101.DEF	XBRL Definition Linkbase Document.

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 22, 2012	By:	/s/ Donald R. Sinclair
		Donald R. Sinclair
		President and Chief Executive Officer

EXHIBIT INDEX

Exhibit
Number	Exhibit Title
12.1*	Computation of Ratio of Earnings to Fixed Charges.
23.1*	Consent of KPMG LLP.
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.
101.INS**	XBRL Instance Document.
101.SCH**	XBRL Schema Document.
101.CAL**	XBRL Calculation Linkbase Document.
101.LAB**	XBRL Label Linkbase Document.
101.PRE**	XBRL Presentation Linkbase Document.
101.DEF**	XBRL Definition Linkbase Document.

*     Filed herewith

**     Furnished herewith

EX-12.1

EXHIBIT 12.1

WESTERN GAS PARTNERS, LP

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
thousands	2011		2010		2009		2008		2007
Earnings:
Income before income taxes	$	207,364	$	178,899	$	148,654	$	205,136	$	178,741
Add:
Fixed charges		30,573		19,292		10,992		2,965		8,783
Distributions from equity investees		15,999		10,973		11,206		14,428		8,349
Amortization of capitalized interest		234		50		298		86		—
Less:
Equity income		11,261		7,628		7,923		11,118		10,145
Net income before taxes attributable to noncontrolling interests		14,103		11,005		10,260		7,965		—
Earnings	$	228,806	$	190,581	$	152,967	$	203,532	$	185,728
Fixed charges:
Interest expense	$	30,345	$	18,794	$	9,955	$	364	$	4,965
Interest component of lease expense		228		498		1,037		2,601		3,818
Fixed charges	$	30,573	$	19,292	$	10,992	$	2,965	$	8,783
Ratio of earnings to fixed charges		7.5x		9.9x		13.9x		68.6x		21.1x

These ratios were computed by dividing earnings by fixed charges. For this purpose, earnings include pre-tax income before adjustment for income or loss from equity investees, plus fixed charges to the extent they affect current year earnings, amortization of capitalized interest and distributed income of equity investees, then subtracting equity income, noncontrolling interests in pre-tax income from subsidiaries that did not incur fixed charges, and interest capitalized during the year. Fixed charges include interest expensed and capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and estimates of interest within rental expenses.

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. 333-174043) and Form S-8 (No. 333-151317), of Western Gas Partners, LP and subsidiaries of our report dated May 22, 2012, with respect to the consolidated balance sheets of Western Gas Partners, LP and subsidiaries as of December 31, 2011 and 2010, 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, 2011, which report appears in the Current Report on Form 8-K of Western Gas Partners, LP and subsidiaries dated May 22, 2012.

/s/ KPMG LLP

Houston, Texas

May 22, 2012

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 Anadarko Gathering Company LLC (“AGC”), Pinnacle Gas Treating LLC (“PGT”) and MIGC LLC (“MIGC”), which we refer to as our “initial assets.” In December 2008, we closed the Powder River acquisition with Anadarko, which included (i) 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, LLC (“Fort Union”). In July 2009, we closed on the acquisition of Chipeta Processing LLC (“Chipeta”) with Anadarko. We closed on the acquisitions of Anadarko’s Granger and Wattenberg assets in January 2010 and August 2010, respectively. In September 2010, we acquired a 10% interest in White Cliffs Pipeline, LLC (“White Cliffs”), which consisted of a 9.6% third-party interest, and a 0.4% interest from Anadarko. In January 2012, we closed the acquisition of Mountain Gas Resources, LLC (“MGR”) with Anadarko, and the assets and operations of MGR, including the Red Desert complex and the 22% interest in Rendezvous Gas Services, LLC (“Rendezvous”), are reflected herein on a retroactive basis. Anadarko acquired MIGC, the Powder River assets, the Granger assets and the MGR assets in connection with its August 23, 2006, acquisition of Western and acquired the Chipeta assets and Wattenberg assets in connection with its August 10, 2006, acquisition of Kerr-McGee. Anadarko made its initial investment in White Cliffs on January 29, 2007. In February 2011, we acquired the Platte Valley gathering system and processing plant from a third party, and in July 2011, we acquired the Bison gas treating facility from Anadarko, who began construction of the Bison assets in 2009 and placed them in service in June 2010. See Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Our acquisitions from Anadarko 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, the Granger assets and the MGR assets, from August 23, 2006, thereafter, (b) the financial results and operations of the Chipeta assets and Wattenberg assets, from August 10, 2006, thereafter, (c) the 0.4% interest in White Cliffs from January 29, 2007, thereafter, and (d) the financial results and operations of the Bison assets which Anadarko placed in service in 2009.

The information in the following table should be read together with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of Exhibit 99.2 to this Current Report on Form 8-K:

thousands except per-unit data,	Summary Financial Information
throughput and gross margin per Mcf	2011			2010			2009			2008			2007
Statement of Income Data (for the year ended):
Total revenues	$	823,265		$	663,274		$	619,764		$	922,314		$	731,297
Costs and expenses		502,168			394,276			392,808			615,456			465,224
Depreciation, amortization and impairments		111,904			91,010			90,692			116,381			82,396
Total operating expenses		614,072			485,286			483,500			731,837			547,620
Operating income		209,193			177,988			136,264			190,477			183,677
Interest income (expense), net		(1,785	)		1,449			10,762			13,110			(4,965	)
Other income (expense), net		(44	)		(538	)		1,628			1,549			29
Income tax expense (1)		19,018			21,702			22,159			53,254			62,925
Net income		188,346			157,197			126,495			151,882			115,816
Net income (loss) attributable to noncontrolling interests		14,103			11,005			10,260			7,908			(92	)
Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235		$	143,974		$	115,908
Key Performance Measures (for the year ended):
Gross margin	$	495,894		$	416,798		$	380,890		$	457,599		$	393,964
Adjusted EBITDA attributable to Western Gas Partners, LP (2)		324,323			265,024			223,766			304,056			264,277
Distributable cash flow (2)		281,975			237,769			203,376			270,154			n/a
General partner interest in net income (3)		8,599			3,067			1,428			842			n/a
Limited partners’ interest in net income (3)		131,560			111,064			69,980			41,261			n/a
Net income per common unit (basic and diluted) (3)	$	1.64		$	1.66		$	1.25		$	0.78			n/a
Net income per subordinated unit (basic and diluted) (3)	$	1.28		$	1.61		$	1.24		$	0.77			n/a
Distributions per unit	$	1.6550		$	1.4400		$	1.2600		$	0.7582			n/a
Balance Sheet Data (at period end):
Net property, plant and equipment	$	2,052,224		$	1,753,762		$	1,714,006		$	1,693,735		$	1,617,163
Total assets		2,837,626			2,263,094			2,246,321			2,202,023			1,832,397
Total long-term liabilities		843,724			649,345			568,183			569,256			530,611
Total equity and partners’ capital	$	1,917,306		$	1,562,029		$	1,627,818		$	1,554,790		$	1,243,763
Cash Flow Data (for the year ended):
Net cash flows provided by (used in):
Operating activities	$	327,171		$	263,749		$	212,765		$	279,702		$	216,955
Investing activities		(472,951	)		(885,507	)		(223,128	)		(607,455	)		(199,922	)
Financing activities		345,265			578,848			44,273			363,854			(17,513	)
Capital expenditures	$	142,946		$	138,000		$	121,295		$	164,360		$	192,522
Operating Data (volumes in MMcf/d):
Gathering, treating and transportation throughput (4)		1,321			1,181			1,229			1,339			1,442
Processing throughput (5)		962			815			808			557			458
Equity investment throughput (6)		198			228			225			304			289
Total throughput		2,481			2,224			2,262			2,200			2,189
Throughput attributable to noncontrolling interests		242			197			180			124			—
Throughput attributable to Western Gas Partners, LP		2,239			2,027			2,082			2,076			2,189
Gross margin per Mcf (7)	$	0.55		$	0.51		$	0.46		$	0.57		$	0.49
Gross margin per Mcf attributable to Western Gas Partners, LP(8)	$	0.58		$	0.54		$	0.48		$	0.58		$	0.49

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⁽¹⁾ Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, including and subsequent to our acquisition of the Partnership assets, except for the Chipeta assets, was subject only to Texas margin tax, while income earned prior to our acquisition of the Partnership assets, except for the Chipeta assets, was subject to federal and state income tax. Income attributable to Chipeta was subject to federal and state income tax 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 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽²⁾  Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) and Distributable cash flow are not defined in the generally accepted accounting principles in the United States (“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 Exhibit 99.2 to this Current Report on Form 8-K. 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 expansion capital expenditures prior to 2008.

⁽³⁾  Net income for periods including and subsequent to our acquisitions of the Partnership assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. Prior to our acquisition of the Partnership assets, all income is attributed to the Parent. All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4. Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽⁴⁾  Excludes average NGL pipeline volumes from the Chipeta assets of 24 MBbls/d, 14 MBbls/d, 11 MBbls/d and 3 MBbls/d for the years ended December 31, 2011, 2010, 2009 and 2008, respectively. The line was placed in service in 2008, therefore no volumes were excluded for 2007.

⁽⁵⁾  Consists of 100% of the Chipeta, Granger and Hilight system volumes, 100% of the Red Desert complex volumes and 50% of Newcastle system volumes for all periods presented, as well as throughput beginning March 2011 attributable to the Platte Valley system.

⁽⁶⁾  Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes and excludes 4 MBbls/d and 3 MBbls/d of oil pipeline volumes for the years ended December 31, 2011 and 2010, respectively, representing our 10% share of average White Cliffs pipeline volumes. Our 10% share of White Cliffs volumes for 2009 was not material. The White Cliffs pipeline was placed in service in 2009 therefore no volumes were excluded for 2008 and 2007.

⁽⁷⁾ Average for period. Calculated as gross margin (total revenues less cost of product) divided by total natural gas throughput, including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union, and our 22% interest in income and volumes attributable to Rendezvous.

⁽⁸⁾  Average for period. Calculated as gross margin, excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product, divided by total throughput attributable to Western Gas Partners, LP. Calculation includes income attributable to our investments in Fort Union, White Cliffs and Rendezvous in addition to volumes attributable to our investments in Fort Union and Rendezvous.

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EX-99.2

EXHIBIT 99.2

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

EXECUTIVE SUMMARY

We are a growth-oriented master limited partnership (“MLP”) organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently operate in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged primarily in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko and third-party producers and customers. Including the effect of the acquisition of Mountain Gas Resources, LLC (“MGR”), our assets consist of thirteen gathering systems, seven natural gas treating facilities, ten natural gas processing facilities, two NGL pipelines, one interstate gas pipeline, one intrastate gas pipeline, and interests in two gas gathering systems and a crude oil pipeline accounted for under the equity method.

Significant financial highlights during the year ended December 31, 2011, include the following:

• We completed two acquisitions: the February acquisition of the Platte Valley gathering system and processing plant from a third party, and the July acquisition of Anadarko’s Bison gas treating facility located in the Powder River Basin in northeastern Wyoming. See Acquisitions under Items 1 and 2 of our 2011 Form 10-K for additional information.

• Our stable operating cash flow enabled us to raise our distribution to $0.44 per unit for the fourth quarter of 2011, representing a 5% increase over the distribution for the third quarter of 2011, a 16% increase over the distribution for the fourth quarter of 2010, and our eleventh consecutive quarterly increase.

• We entered into an amended and restated $800.0 million senior unsecured revolving credit facility (the “RCF”) to amend and restate our $450.0 million revolving credit facility and issued $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “Notes”). See Liquidity and Capital Resources within this Item 7 for additional information.

• We issued an aggregate 9,602,813 common units to the public, generating net proceeds of $335.3 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds from the two offerings were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.

Significant operational highlights during the year ended December 31, 2011, include the following:

• Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.58 per Mcf for the year, representing a 7% increase compared to the year ended December 31, 2010.

• Throughput attributable to Western Gas Partners, LP totaled 2,239 MMcf/d for the year, representing a 10% increase compared to the same period in 2010.

OUR OPERATIONS

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our consolidated financial statements and notes to consolidated financial statements, which are included in Item 8 of Exhibit 99.3 to this Current Report on Form 8-K. Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner is Western Gas Holdings, LLC (the “general partner”), a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” or “Parent” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner.

References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of December 31, 2011. Because of Anadarko’s control of the Partnership through its ownership of our general partner, each acquisition of Partnership assets, except for those from third parties, was considered a transfer of net assets between entities under common control (see Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). As a result, after each acquisition of assets from Anadarko, we are required to recast our financial statements to include the activities of the Partnership assets as of the date of common control. As such, our historical financial statements have been recast in this Current Report on Form 8-K to include the results attributable to MGR and Bison as if we owned such assets for all periods presented. The consolidated financial statements for periods prior to our 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 we had owned the assets during the periods reported. 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. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and also refers to Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”).

Our results are driven primarily by the volumes of natural gas and NGLs we gather, process, treat or transport through our systems. For the year ended December 31, 2011, approximately 77% of our total revenues and 70% of our throughput (excluding equity investment throughput) was attributable to transactions 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.

We received significant dedications from our largest customer, Anadarko, solely with respect to the gathering systems connected to the Wattenberg field and the gathering systems included in our initial assets. 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 long as additional wells are connected to these gathering systems.

For the year ended December 31, 2011, approximately 65% of our gross margin was attributed to fee-based contracts, under which a fixed fee is received based on the volume and thermal content of the natural gas we gather, process, 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. Fee-based gross margin includes equity income from our interests in Fort Union, White Cliffs and Rendezvous. Certain of our fee-based contracts contain keep-whole provisions.

For the year ended December 31, 2011, approximately 35% of our gross margin was attributed to percent-of-proceeds and keep-whole contracts, pursuant to which we have commodity price exposure, including gross margin attributable to condensate sales. 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 5. Transactions with Affiliates of the Notes to Consolidated Financial Statements included under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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We also have indirect exposure to commodity price risk in that persistent low natural gas prices have caused and may continue to cause our current or potential customers to delay drilling or shut in production in certain areas, which would reduce the volumes of natural gas available for our systems. We also bear a limited degree of commodity price risk through settlement of natural gas imbalances. Please read Item 7A of our 2011 Form 10-K.

As a result of our initial public offering and subsequent acquisitions from Anadarko and third parties, the results of operations, financial position and cash flows may vary significantly for 2011, 2010 and 2009 as compared to future periods. 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 an essential operating variable we use 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 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, 2011, and including the effect of the MGR acquisition, we added 112 receipt points to our systems, with initial throughput of approximately 1.0 MMcf/d per receipt point.

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 purchases and sales of natural gas, condensate and NGLs 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, equipment rentals, 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, to 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 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 incurred 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 the following:

• expenses associated with annual and quarterly reporting;

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

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• 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, pursuant to the terms of the omnibus agreement with Anadarko, we are required to reimburse Anadarko for allocable general and administrative expenses. See further detail under Items Affecting the Comparability of Our Financial Results – General and administrative expenses under the omnibus agreement below and Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Adjusted EBITDA. We define “Adjusted EBITDA” as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, expense in excess of the omnibus cap, interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, other income and other nonrecurring adjustments that are not settled in cash. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:

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

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

• 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 (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures and income taxes. We 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 Distributable cash flow is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships.

Distributable cash flow should not be considered an alternative to net income, earnings per unit, operating income, cash flows 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. Our definitions of Adjusted EBITDA and Distributable cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility.

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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.

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

	Year Ended December 31,
thousands	2011			2010			2009
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	324,323		$	265,024		$	223,766
Less:
Distributions from equity investees		15,999			10,973			11,206
Non-cash equity-based compensation expense		13,754			4,787			3,580
Expenses in excess of omnibus cap		—			133			842
Interest expense		30,345			18,794			9,955
Income tax expense		19,018			21,702			22,159
Depreciation, amortization and impairments (1)		109,151			88,188			88,486
Other expense (1)		3,683			2,393			—
Add:
Equity income, net		11,261			7,628			7,923
Interest income, net – affiliates		28,560			20,243			20,717
Other income (1) (2)		2,049			267			57
Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235
Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	324,323		$	265,024		$	223,766
Adjusted EBITDA attributable to noncontrolling interests		16,850			13,823			12,462
Interest income (expense), net		(1,785	)		1,449			10,762
Expenses in excess of omnibus cap		—			(133	)		(842	)
Non-cash equity-based compensation expense		(13,754	)		(4,787	)		(3,580	)
Current income tax expense		(16,414	)		(12,114	)		(22,109	)
Other income (expense), net (2)		(1,628	)		(2,122	)		61
Distributions from equity investees less than (in excess of) equity income, net		(4,738	)		(3,345	)		(3,283	)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		(3,571	)		802			6,961
Accounts payable, accrued liabilities and natural gas imbalance payable		23,092			2,734			(14,267	)
Other		4,796			2,418			2,834
Net cash provided by operating activities	$	327,171		$	263,749		$	212,765

⁽¹⁾  Includes our 51% share of depreciation, amortization and impairments; other expense; and other income attributable to Chipeta.

⁽²⁾  Excludes income of $1.6 million for each of the years ended December 31, 2011, 2010 and 2009, related to a component of a gas processing agreement accounted for as a capital lease. Refer to Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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	Year Ended December 31,
thousands except Coverage ratio	2011			2010		2009
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP
Distributable cash flow	$	281,975		$	237,769	$	203,376
Less:
Distributions from equity investees		15,999			10,973		11,206
Non-cash equity-based compensation expense		13,754			4,787		3,580
Expenses in excess of omnibus cap		—			133		842
Income tax expense		19,018			21,702		22,159
Depreciation, amortization and impairments (1)		109,151			88,188		88,486
Other expense (1)		3,683			2,393		—
Add:
Equity income, net		11,261			7,628		7,923
Cash paid for maintenance capital expenditures (1)		28,293			24,854		27,335
Capitalized interest		420			—		—
Cash paid for income taxes		190			507		—
Interest income, net (non-cash settled)		11,660			3,343		3,817
Other income (1) (2)		2,049			267		57
Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192	$	116,235
Distribution declared for the year ended December 31, 2011 (3)
Limited partners		143,734
General partner		8,847
Total	$	152,581
Coverage ratio		1.85	x

⁽¹⁾  Includes our 51% share of depreciation, amortization and impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to Chipeta.

⁽²⁾  Excludes income of $1.6 million for each of the years ended December 31, 2011, 2010 and 2009, related to a component of a gas processing agreement accounted for as a capital lease. Refer to Note 1. Summary of Significant Accounting Policies in the Notes to the Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽³⁾  Reflects distributions of $1.655 per unit declared for the year ended December 31, 2011.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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

Affiliate contracts. Effective October 1, 2009, contracts covering substantially all of the Granger assets’ affiliate throughput were converted from primarily keep-whole contracts into a ten-year fee-based arrangement and, effective July 1, 2010, contracts covering all of Wattenberg’s affiliate throughput were converted from primarily keep-whole contracts into a ten-year fee-based agreement. These contract changes will impact the comparability of the statements of income and cash flows. See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Commodity price swap agreements. We have commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to the actual volume of our natural gas, condensate and NGLs purchased and sold at the Hilight, Hugoton, Newcastle, Granger and Wattenberg assets, with various expiration dates through September 2015.

6

In December 2011, we extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2013, and also entered into price swap agreements related to the MGR acquisition, with forward-starting effective dates beginning January 1, 2012, and extending through December 31, 2016. See Note 5. Transactions with Affiliates and Note 12. Subsequent Event in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Federal income taxes. Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, including and subsequent to our acquisition of the Partnership assets was subject only to Texas margin tax, while income earned prior to our acquisition of the Partnership assets was subject to federal and state income tax.

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. 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, 2011, 2010 and 2009, Anadarko billed us $11.8 million, $9.0 million and $6.9 million, respectively, in allocated general and administrative expenses, which, prior to December 31, 2010, were subject to the cap contained in the omnibus agreement. For the year ended December 31, 2011, Anadarko, in accordance with the partnership agreement and omnibus agreement, determined, in its reasonable discretion, amounts to be allocated to us in exchange for services provided under the omnibus agreement. In addition, our general and administrative expenses for the years ended December 31, 2010 and 2009, included $0.1 million and $0.8 million, respectively, of expenses incurred by Anadarko and the general partner in excess of the cap contained in the omnibus agreement. Such expenses were recorded as capital contributions from Anadarko and did not impact the Partnership’s cash flows. The amounts charged under the omnibus agreement are 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. We also incurred $7.7 million, $8.0 million and $7.5 million in public company expenses, excluding equity-based compensation, during the years ended December 31, 2011, 2010 and 2009, respectively.

Interest 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 of Chipeta, the Granger acquisition, Wattenberg acquisition, 0.4% interest in White Cliffs, Bison acquisition and MGR acquisition. Therefore, interest expense and interest income attributable to these balances are reflected in our historical consolidated financial statements for the periods ending prior to our acquisition of the Partnership assets, except for Chipeta.

Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

Platte Valley acquisition. In February 2011, we acquired a natural gas gathering system and cryogenic gas processing facilities, collectively referred to as the “Platte Valley assets,” financed with borrowings under our revolving credit facility. These assets, acquired from a third-party, have been recorded in the Partnership’s consolidated financial statements at their estimated fair values on the acquisition date under the acquisition method of accounting. Results of operations attributable to the Platte Valley assets have been included our consolidated statements of income beginning on the acquisition date in the first quarter of 2011.

The fair values of the plant and processing facilities, related equipment, and intangible assets acquired were based on the market, cost and income approaches. The liabilities assumed include certain amounts associated with environmental contingencies estimated by management. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. See Note 1. Summary of Significant Accounting Policies, Note 2. Acquisitions and Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for further information.

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GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends. Our expectations are based on our assumptions 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 relatively low natural gas price environment, which has persisted over the past three years, has led to lower levels of drilling activity served by certain of our assets. Several of our customers, including Anadarko, have reduced activity levels in certain areas, shifting capital toward liquid-rich opportunities that offer higher margins and superior economics to producers. This trend has resulted in fewer new well connections and, in some cases, temporary curtailments of production. 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 the activities of natural gas producers and shippers.

Changes in regulations. Our operations and the operations of our customers have been, and at times in the future may be, affected by political developments and are subject to an increasing number of complex federal, state, tribal, local and other laws and regulations such as production restrictions, permitting delays, limitations on hydraulic fracturing and environmental protection regulations. We and/or our customers must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. For example, regulation of hydraulic fracturing is currently primarily conducted at the state level through permitting and other compliance requirements. If proposed federal legislation is adopted, it could establish an additional level of regulation and permitting. Any changes in statutory regulations or delays in the issuance of required permits may impact both the throughput on and profitability of our systems.

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, MLPs have accessed the 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 inflation. Although inflation in the U.S. has been relatively low in recent years, the U.S. economy could experience a significant inflationary effect from, among other things, the governmental stimulus plans enacted since 2008. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates. Interest rates were at or near historic lows at certain times during 2011. Should interest rates rise, our financing costs would increase accordingly. Additionally, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and an associated implied distribution yield. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, reduce debt or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors would face similar circumstances.

Acquisition opportunities. Anadarko’s total domestic midstream asset portfolio, excluding the assets we own, consists of sixteen gathering systems and eight processing and/or treating facilities with an aggregate throughput of approximately 1.9 Bcf/d, in addition to equity investments in two midstream projects not yet in service. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time.

8

Including the effect of the MGR acquisition, Anadarko owns a 2.0% general partner interest in us, all of our IDRs and a 43.6% 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 flows generated from operations on a per-unit basis.

RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations for the years ended December 31, 2011, 2010 and 2009:

		MMMMMM			MMMMMM			MMMMMM
	Year Ended December 31,
thousands	2011			2010			2009
Gathering, processing and transportation of natural gas and natural gas liquids	$	301,329		$	253,273		$	246,466
Natural gas, natural gas liquids and condensate sales		502,383			396,037			361,645
Equity income and other, net		19,553			13,964			11,653
Total revenues (1)		823,265			663,274			619,764
Total operating expenses (1)		614,072			485,286			483,500
Operating income		209,193			177,988			136,264
Interest income, net – affiliates		28,560			20,243			20,717
Interest expense		(30,345	)		(18,794	)		(9,955	)
Other income (expense), net		(44	)		(538	)		1,628
Income before income taxes		207,364			178,899			148,654
Income tax expense		19,018			21,702			22,159
Net income		188,346			157,197			126,495
Net income attributable to noncontrolling interests		14,103			11,005			10,260
Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235
Key Performance Metrics (2)
Gross margin	$	495,894		$	416,798		$	380,890
Adjusted EBITDA attributable to Western Gas Partners, LP	$	324,323		$	265,024		$	223,766
Distributable cash flow	$	281,975		$	237,769		$	203,376

⁽¹⁾  Revenues include affiliate amounts earned by the Partnership from services provided to our affiliates, as well as from the sale of residue gas, condensate and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽²⁾  Gross margin, Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) and Distributable cash flow are defined 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, 2011” refer to the comparison of the year ended December 31, 2011 to the year ended December 31, 2010, any increases or decreases “for the year ended December 31, 2010” refer to the comparison of the year ended December 31, 2010 to the year ended December 31, 2009.

9

Operating Statistics

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
throughput in MMcf/d	2011		2010		D		2009		D
Gathering, treating and transportation (1)		1,321		1,181		12 %		1,229		(4)%
Processing (2)		962		815		18 %		808		1 %
Equity investment (3)		198		228		(13)%		225		1 %
Total throughput (4)		2,481		2,224		12 %		2,262		(2)%
Throughput attributable to noncontrolling interests		242		197		23 %		180		9 %
Total throughput attributable to Western Gas Partners, LP		2,239		2,027		10 %		2,082		(3)%

⁽¹⁾  Excludes average NGL pipeline volumes from the Chipeta assets of 24 MBbls/d, 14 MBbls/d, and 11 MBbls/d for the years ended December 31, 2011, 2010, and 2009, respectively.

⁽²⁾  Includes 100% of the Chipeta, Granger and Hilight system volumes, 100% of the Red Desert complex volumes and 50% of Newcastle system volumes for all periods presented, as well as throughput beginning March 2011 attributable to the Platte Valley system.

⁽³⁾  Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes and excludes 4 MBbls/d and 3 MBbls/d of oil pipeline volumes for the years ended December 31, 2011 and 2010, respectively, representing our 10% share of average White Cliffs pipeline volumes. Our 10% share of White Cliffs volumes for 2009 was not material.

⁽⁴⁾  Includes affiliate, third-party and equity-investment volumes.

Gathering, treating and transportation throughput increased by 140 MMcf/d for the year ended December 31, 2011, primarily due to the startup of the Bison assets in June 2010 and throughput increases at the Wattenberg system due to increased drilling activity in the area. These increases were partially offset by lower throughput at the MIGC system resulting from the January 2011 expiration of certain contracts that were not renewed due to the startup of the third-party owned Bison pipeline, and throughput decreases at the Haley, Pinnacle, Dew and Hugoton systems resulting from natural production declines and reduced drilling activity in those areas. Gathering, treating and transportation throughput decreased by 48 MMcf/d for the year ended December 31, 2010, primarily due to throughput decreases at Pinnacle, Haley, Dew, Hugoton and an MGR gathering system, resulting from natural production declines and reduced drilling activity in those areas as a result of low natural gas prices. These declines were partially offset by throughput increases at the Wattenberg system due to increased drilling activity and recompletions driven by favorable producer economics in the area and the startup of the Bison assets in June 2010.

Processing throughput increased by 147 MMcf/d for the year ended December 31, 2011, primarily due to the additional throughput from the Platte Valley system acquired in February 2011, as well as throughput increases at the Chipeta and Hilight systems, resulting from drilling activity in these areas driven by the relatively high liquid content of the gas volumes produced. These increases were partially offset by lower throughput at the Red Desert complex resulting from volumes being diverted away upon the resumption of a competing plant in 2011 that experienced an outage in 2010. Processing throughput increased by 7 MMcf/d for the year ended December 31, 2010, primarily due to increased throughput at the Chipeta system due to increased drilling activities in the Natural Buttes areas and at the Granger system resulting from the temporary redirection of volumes from competing systems during the last half of 2010.

Equity investment volumes decreased by 30 MMcf/d for the year ended December 31, 2011, due to lower throughput at the Fort Union system following the startup of the Bison pipeline. Equity investment volumes increased by 3 MMcf/d for the year ended December 31, 2010, due to a throughput increase of 7 MMcf/d at Rendezvous, partially offset by a 4 MMcf/d decrease in volumes at the Fort Union system as a result of reduced drilling activity in the area.

10

Natural Gas Gathering, Processing and Transportation Revenues

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Gathering, processing and transportation of natural gas and natural gas liquids	$	301,329	$	253,273		19%	$	246,466		3%

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $48.1 million for the year ended December 31, 2011, due to the acquisition of the Platte Valley system in February 2011, the June 2010 startup of the Bison assets, and increased fee revenue at the Wattenberg system as a result of changes in affiliate contract terms (from primarily keep-whole and percentage-of-proceeds arrangements to fee-based arrangements), effective July 2010. These increases were partially offset by decreased fee revenue at MIGC due to the January 2011 expiration of certain contracts, decreased volume due to natural declines at the Haley, Hugoton and Dew systems and decreased volume processed at the Red Desert complex resulting from volumes being diverted away upon the resumption of a competing plant in 2011 that experienced an outage in 2010. Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $6.8 million for the year ended December 31, 2010, due to the June 2010 startup of Bison and increased fee revenue at the Wattenberg and Granger systems. This increase resulted from changes in affiliate contract terms effective in July 2010 at Wattenberg and in October 2009 at Granger, from primarily keep-whole and percentage-of-proceeds agreements to fee-based agreements. In addition, revenues increased due to higher rates at the Pinnacle, Hugoton and Wattenberg systems. These increases were partially offset by decreased throughput at the Pinnacle, Haley, Dew and Hugoton systems.

Natural Gas, Natural Gas Liquids and Condensate Sales

		000000000		000000000		000000000		000000000		000000000
thousands except percentages and     per-unit amounts	Year Ended December 31,
	2011		2010		D		2009		D
Natural gas sales	$	129,939	$	91,452		42%	$	93,092		(2)%
Natural gas liquids sales		345,646		279,915		23%		250,572		12 %
Drip condensate sales		26,798		24,670		9%		17,981		37 %
Total	$	502,383	$	396,037		27%	$	361,645		10 %
Average price per unit:
Natural gas (per Mcf)	$	5.30	$	5.17		3%	$	3.86		34 %
Natural gas liquids (per Bbl)	$	47.72	$	39.94		19%	$	30.06		33 %
Drip condensate (per Bbl)	$	72.86	$	70.50		3%	$	47.87		47 %

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $106.3 million for the year ended December 31, 2011, which consisted of a $65.7 million increase in NGLs sales, a $38.5 million increase in natural gas sales and a $2.1 million increase in drip condensate sales.

The increase in NGLs sales was primarily due to the acquisition of the Platte Valley system in February 2011, higher throughput at the Chipeta and Hilight systems and increased commodity prices impacting the Red Desert complex at which commodity price swap agreements were not effective until January 1, 2012 (see Note 12. Subsequent Event in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K), partially offset by changes in affiliate contract terms at the Wattenberg system allowing the producer to take its product in kind.

The increase in natural gas sales was due to a 38% increase in volumes sold, resulting from the acquisition of the Platte Valley system in February 2011 and higher throughput at the Hilight system due to increased third-party drilling in the area. The increase in drip condensate sales for the year ended December 31, 2011, was primarily due to a higher average sales price at the Wattenberg and Hugoton systems and Platte Valley sales.

11

Total natural gas, natural gas liquids and condensate sales increased by $34.4 million for the year ended December 31, 2010, consisting of a $29.3 million and $6.7 million increase in NGLs sales and drip condensate sales, respectively, partially offset by a $1.6 million decrease in natural gas sales. The increase in NGLs sales is primarily attributable to a 33% increase in the average price of NGLs for 2010. This increase was partially offset by a 16% decrease in the volume of NGLs sold primarily due to the changes in affiliate contract terms at the Granger and Wattenberg systems effective in October 2009 and July 2010, respectively, allowing the producer to take its liquids and gas in-kind.

The decrease in natural gas sales was due to a 27% decrease in the volume of natural gas sold primarily due to the changes in affiliate contract terms at the Granger and Wattenberg systems. The decrease was partially offset by a 34% increase in the average natural gas sales price. Natural gas and NGL prices pursuant to the commodity price swap agreements for the Granger system in 2010 were higher than 2009 market prices, and natural gas and NGL prices pursuant to the 2010 commodity price swap agreements for the Hilight and Newcastle systems were higher than 2009 commodity swap prices. The increase in drip condensate sales for the year ended December 31, 2010, was primarily due to a $22.63 per Bbl, or 47%, increase in the average price of condensate at the Hugoton and Wattenberg systems.

The average natural gas and NGLs prices for the year ended December 31, 2011 and 2010, include the effects of commodity price swap agreements attributable to sales for the Granger, Wattenberg, Hilight, Newcastle and Hugoton systems. See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Equity Income and Other Revenues

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Equity income	$	11,261	$	7,628		48%	$	7,923		(4)%
Other revenues, net		8,292		6,336		31%		3,730		70 %
Total	$	19,553	$	13,964		40%	$	11,653		20 %

Equity income increased by $3.6 million for the year ended December 31, 2011, primarily due to the acquisition of an additional 9.6% interest in White Cliffs in September 2010.

Other revenues, net increased by $2.0 million for the year ended December 31, 2011, primarily due to collection of deficiency fees, predominantly associated with MGR gathering agreements. Other revenues, net increased by $2.6 million for the year ended December 31, 2010, primarily due to changes in gas imbalance positions at the Hilight, MIGC, Hugoton and Wattenberg systems and reimbursements from a third-party customer at the Pinnacle system for both installation costs and a shared equipment arrangement that ended in the third quarter of 2009.

Cost of Product and Operation and Maintenance Expenses

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Cost of product	$	327,371	$	246,476		33%	$	238,874		3 %
Operation and maintenance		119,104		103,887		15%		106,590		(3)%
Total cost of product and operation and maintenance expenses	$	446,475	$	350,363		27%	$	345,464		1 %

Including the effects of commodity price swap agreements attributable to purchases for the Granger, Wattenberg, Hilight, Newcastle and Hugoton systems, cost of product expense increased by $80.9 million for the year ended December 31, 2011, primarily consisting of a $51.5 million increase due to increased throughput at the Hilight and Chipeta systems and a $44.4 million increase due to the acquisition of the Platte Valley system. These increases were partially offset by a $9.0 million decrease due to decreased throughput at the Red Desert complex and a $6.2 million decrease due to changes in gas imbalance positions.

12

Including the effects of commodity price swap agreements attributable to purchases for the Granger, Wattenberg, Hilight, Newcastle and Hugoton systems, cost of product expense increased by $7.6 million for the year ended December 31, 2010, primarily due to a $19.6 million increase in NGL purchases as a result of higher prices, partially offset by a $1.1 million decrease due to a decrease in the actual cost of fuel compared to the contractual cost of fuel, and a $1.4 million decrease due to changes in gas imbalance positions. The overall increase was also partially offset by a $9.0 million decrease in gathering fees paid by the Granger system for volumes gathered at adjacent gathering systems owned by Anadarko and a third party, then processed at Granger. Effective in October 2009, fees previously paid by Granger are now paid directly by the producer to the other gathering system owners.

See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for further discussion of the commodity price swap agreements.

Operation and maintenance expense increased by $15.2 million for the year ended December 31, 2011, primarily due to the acquisition of the Platte Valley system and the June 2010 startup of the Bison assets, partially offset by lower compressor lease expenses resulting from the purchase of compressors used at the Wattenberg system leased during 2010.

Operation and maintenance expense decreased by $2.7 million for the year ended December 31, 2010, primarily due to lower compressor lease expenses resulting from the purchase of previously leased compressors used at the Granger and Wattenberg systems during 2010, lower electricity expense at the Chipeta system, lower chemical expenses and lower contract labor. The decrease in compressor lease expense for the year ended December 31, 2010, was offset by an increase in depreciation expense discussed below under General and Administrative, Depreciation and Other Expenses. In addition, the decrease in operating expense was partially offset by higher field personnel expenses, primarily attributable to merit increases, and a $2.0 million increase due to the startup of the Bison assets in June 2010.

General and Administrative, Depreciation and Other Expenses

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
General and administrative	$	39,114	$	29,640		32%	$	33,171		(11)%
Property and other taxes		16,579		14,273		16%		14,173		1 %
Depreciation, amortization and impairments		111,904		91,010		23%		90,692		— %
Total general and administrative,
depreciation and other expenses	$	167,597	$	134,923		24%	$	138,036		(2)%

General and administrative expenses increased by $9.5 million for the year ended December 31, 2011, due to an increase of $7.2 million in noncash payroll expenses primarily due to an increase in the collective value of awards under the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated, from $215.00 per unit to $634.00 per unit and an increase of $2.7 million in corporate and management personnel costs allocated to us pursuant to the omnibus agreement. Property and other taxes increased by $2.3 million for the year ended December 31, 2011, primarily due to the ad valorem tax for the Platte Valley, Bison and Wattenberg assets. Depreciation, amortization and impairments increased by $20.9 million for the year ended December 31, 2011, primarily attributable to the addition of the Platte Valley and Bison assets, depreciation associated with capital projects completed and capitalized at the Wattenberg, Hugoton and Hilight systems, and impairment expense due to the indefinite postponement of an expansion project at the Red Desert complex. See Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

General and administrative expenses decreased by $3.5 million for the year ended December 31, 2010, due to the management fee allocated to the Granger assets and Wattenberg assets during the year ended December 31, 2009, then discontinued effective January 2010 and July 2010, respectively, upon contribution of the assets to us. This decrease was partially offset by an increase in corporate and management personnel costs allocated to us pursuant to the omnibus agreement. Depreciation, amortization and impairments increased by approximately $0.3 million for the year ended December 31, 2010, comprised of a $5.5 million increase in depreciation, offset by a $5.2 million decrease in impairment expense. The increase in depreciation expense is primarily attributable to capital projects completed at the Chipeta, Hilight and Hugoton systems, the addition of the Bison assets, and previously leased compressors used at the Granger and Wattenberg systems purchased and contributed to the Partnership during 2010. The decrease in impairment expense is primarily due to a $6.1 million charge taken during the year ended December 31, 2009, as a result of the write-down of an idle MGR pipeline for which no future cash flows were expected. No similar impairment expense was recorded in 2010.

13

Interest Income and Interest Expense

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Interest income on note receivable	$	16,900	$	16,900		— %	$	16,900		— %
Interest income, net on affiliate balances		11,660		3,343		nm  (1)		3,817		(12)%
Interest income, net – affiliates (2)	$	28,560	$	20,243		41 %	$	20,717		(2)%
Third Parties
Interest expense on long-term debt	$	(20,533)	$	(8,530)		141 %	$	(304)		nm
Amortization of debt issuance costs
and commitment fees (3)		(5,297)		(3,340)		59 %		(555)		nm
Capitalized interest		420		—		nm		—		nm
Affiliates
Interest expense on notes payable to Anadarko		(4,935)		(6,828)		(28)%		(8,953)		(24)%
Credit facility commitment fees		—		(96)		(100)%		(143)		(33)%
Interest expense	$	(30,345)	$	(18,794)		61 %	$	(9,955)		89 %

⁽¹⁾  Percent change is not meaningful (“nm”).

⁽²⁾  Represents interest income recognized on the note receivable from Anadarko. Also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

⁽³⁾  For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees related to the Notes.

Interest expense increased by $11.6 million for the year ended December 31, 2011, due to interest expense incurred on the Notes issued in May 2011 as well as $1.3 million of accelerated amortization expense related to the early repayment of the Wattenberg term loan in March 2011 (described in Liquidity and Capital Resources). The increase was partially offset by lower interest expense on amounts outstanding on our RCF during 2011, a decrease in interest expense on the Note Payable to Anadarko which was amended in December 2010 reducing the interest rate from 4.00% to 2.82% for the remainder of the term, and the repayment of the Wattenberg term loan.

Interest expense increased by $8.8 million for the year ended December 31, 2010, primarily due to interest expense incurred on the amounts outstanding during 2010 under the Wattenberg term loan, our RCF and related commitment fees, and expense incurred on intercompany borrowings associated with assets we acquired.

See Note 10. Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Other Income (Expense), Net

		0000000000		0000000000		0000000000		0000000000		0000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Other income (expense), net	$	(44)	$	(538)		(92)%	$	1,628		(133)%

Other income (expense), net for the year ended December 31, 2011, primarily consists of the $1.9 million loss realized on an interest-rate swap agreement entered into in March 2011 and terminated in May 2011 in connection with the offering of the Notes. Other income (expense), net for the year ended December 31, 2010, primarily relates to financial agreements entered into in April 2010 to fix the underlying ten-year Treasury rates with respect to a potential note issuance that was under consideration at that time. Upon reaching our decision not to issue the notes in May 2010, we terminated the agreements at a cost of $2.4 million. For each of the years ended December 31, 2011 and 2010, the aforementioned loss amounts were partially offset by $1.6 million of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition.

14

Income Tax Expense

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Income before income taxes	$	207,364	$	178,899		16 %	$	148,654		20 %
Income tax expense		19,018		21,702		(12)%		22,159		(2)%
Effective tax rate		9%		12%				15%

We are not a taxable entity for U.S. federal income tax purposes, although the portion of our income apportionable to Texas is subject to Texas margin tax. Income attributable to (a) the MGR assets prior to and including December 2011, (b) the Bison assets prior to and including June 2011, (c) the Wattenberg assets prior to and including July 2010 and (d) the Granger assets prior to and including January 2010 were subject to federal and state income tax, resulting in an overall lower income tax expense for the year ended December 31, 2011. Income earned by the Granger, Wattenberg and Bison assets for periods subsequent to January 2010, July 2010 and June 2011, respectively, was subject only to Texas margin tax on the portion of their incomes apportionable to Texas.

For 2011, 2010, and 2009, our variance from the federal statutory rate, which is zero percent as a non-taxable entity, is primarily attributable to federal and state taxes on income attributable to Partnership assets pre-acquisition and our share of Texas margin tax.

Noncontrolling Interests

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Net income attributable to noncontrolling interests	$	14,103	$	11,005		28%	$	10,260		7%

For the year ended December 31, 2011, and 2010, net income attributable to noncontrolling interests increased by $3.1 million and $0.7 million, respectively, primarily due to the higher volumes at the Chipeta system.

Key Performance Metrics

		000000000		000000000		000000000		000000000		000000000
thousands except percentages     and gross margin per Mcf	Year Ended December 31,
	2011		2010		D		2009		D
Gross margin	$	495,894	$	416,798		19%	$	380,890		9%
Gross margin per Mcf (1)		0.55		0.51		8%		0.46		11%
Gross margin per Mcf attributable to
Western Gas Partners, LP (2)		0.58		0.54		7%		0.48		13%
Adjusted EBITDA attributable to
Western Gas Partners, LP (3)		324,323		265,024		22%		223,766		18%
Distributable cash flow (3)	$	281,975	$	237,769		19%	$	203,376		17%

⁽¹⁾  Average for period. Calculated as gross margin (total revenues less cost of product) divided by total natural gas throughput, including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union and our 22% interest in income and volumes attributable to Rendezvous.

⁽²⁾  Average for period. Calculated as gross margin, excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product, divided by total throughput attributable to Western Gas Partners, LP. Calculation includes income attributable to our investments in Fort Union, White Cliffs and Rendezvous in addition to volumes attributable to our investments in Fort Union and Rendezvous.

⁽³⁾  For a reconciliation of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read the descriptions above under the captions How We Evaluate Our Operations within this Item 7.

15

Gross margin and Gross margin per Mcf. Gross margin increased by $79.1 million for the year ended December 31, 2011, primarily due to the acquisition of the Platte Valley system; the startup of the Bison assets in June 2010; higher margins at the Wattenberg and Chipeta systems, due to an increase in volumes (including the impact of commodity price swap agreements at the Wattenberg system); higher margins at our Red Desert complex due to increased NGL prices during 2011 combined with decreased cost of product as a result of lower volumes processed; and the increase in our interest in White Cliffs from 0.4% to 10% in September 2010. These increases were partially offset by lower gross margin at the MIGC system due to the expiration of certain firm transportation contracts in January 2011 and lower gross margins at the Haley and Hugoton systems due to naturally declining production volumes. For the year ended December 31, 2011, gross margin per Mcf increased by 8% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 7%, primarily due to higher margins combined with lower volumes at our Red Desert complex as noted above; the acquisition of the Platte Valley system in 2011; and changes in the throughput mix of the portfolio.

Gross margin increased by $35.9 million for the year ended December 31, 2010, primarily due to higher fee revenue at the Granger and Wattenberg systems resulting from the change in affiliate contract terms, as well as higher throughput volumes at those systems; the startup of Bison in June 2010; and higher margins at our Red Desert complex due to higher NGL prices and a slight increase in volumes sold. This increase is offset by lower throughput at the Pinnacle, Haley and Dew systems. For the year ended December 31, 2010, gross margin per Mcf increased by 11% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 13%, primarily due to the changes in contract terms mentioned above and changes in the throughput mix within our portfolio.

Adjusted EBITDA. Adjusted EBITDA increased by $59.3 million for the year ended December 31, 2011, primarily due to a $156.4 million increase in total revenues excluding equity income, partially offset by an $80.9 million increase in cost of product, a $15.2 million increase in operation and maintenance expenses and a $0.6 million increase in general and administrative expenses, excluding non-cash equity-based compensation and expenses in excess of the 2010 omnibus cap.

Adjusted EBITDA increased by $41.3 million for the year ended December 31, 2010, primarily due to a $43.8 million increase in total revenues excluding equity income, a $4.0 million decrease in general and administrative expenses excluding non-cash equity-based compensation and expenses in excess of the omnibus cap, and a $2.7 million decrease in operation and maintenance expenses, partially offset by a $7.6 million increase in cost of product.

Distributable cash flow. Distributable cash flow increased by $44.2 million for the year ended December 31, 2011, primarily due to the $59.3 million increase in Adjusted EBITDA and a $0.3 million decrease in cash paid for income taxes, partially offset by a $12.0 million increase in net cash paid for interest expense and a $3.4 million increase in cash paid for maintenance capital expenditures.

Distributable cash flow increased by $34.4 million for the year ended December 31, 2010, primarily due to the $41.3 million increase in Adjusted EBITDA and a $2.5 million decrease in cash paid for maintenance capital expenditures, partially offset by an $8.8 million increase in net cash paid for interest expense and a $0.5 million increase in cash paid for income taxes.

16

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders and have increased our quarterly distribution each quarter since the second quarter of 2009. On January 18, 2012, the board of directors of our general partner declared a cash distribution to our unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

Management continuously monitors our leverage position and coordinates its capital expenditure program, quarterly distributions and acquisition strategy with its expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance outstanding debt balances with longer-term notes. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statement. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Please read Item 1A—Risk Factors in our 2011 Form 10-K.

17

Working capital. As of December 31, 2011, we had $179.9 million of working capital, which we define as the amount by which current assets exceed current liabilities. Working capital is an indication of our liquidity and potential need for short-term funding. Our working-capital requirements are driven by changes in accounts receivable and accounts payable and factors such as credit extended to, and the timing of collections from, our customers and the level and timing of our spending for maintenance and expansion activity.

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

• maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput and related cash flows; or

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

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

		MMMMMM		MMMMMM		MMMMMM
	Year Ended December 31,
thousands	2011		2010		2009
Acquisitions	$	330,794	$	752,827	$	101,451
Expansion capital expenditures	$	114,557	$	113,100	$	93,768
Maintenance capital expenditures		28,389		24,900		27,527
Total capital expenditures (1)	$	142,946	$	138,000	$	121,295
Capital incurred (2)	$	148,348	$	143,223	$	109,168

⁽¹⁾  Capital expenditures for the years ended December 31, 2011, 2010 and 2009, includes $2.7 million, $101.2 million and $82.8 million, respectively, of pre-acquisition capital expenditures for the MGR, Bison, Wattenberg and Granger assets and includes the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners.

⁽²⁾  Capital incurred for the years ended December 31, 2011, 2010 and 2009, includes $0.9 million, $105.0 million and $76.0 million, respectively, of pre-acquisition capital incurred for the MGR, Bison, Wattenberg and Granger assets and includes the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

Acquisitions include the MGR, Bison, Platte Valley, White Cliffs, Wattenberg, Granger and Chipeta acquisitions as outlined in Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

18

Capital expenditures, excluding acquisitions, increased by $4.9 million for the year ended December 31, 2011. Expansion capital expenditures increased by $1.5 million for the year ended December 31, 2011, primarily due to an increase of $39.5 million in expenditures primarily at our Chipeta, Bison, Highlight and Wattenberg systems, partially offset by the purchase of previously leased compressors at the Wattenberg system during the year ended December 31, 2010, for $37.5 million. Maintenance capital expenditures increased by $3.5 million, primarily as a result of maintenance projects at the Wattenberg system and higher well connects at the Hilight system, partially offset by fewer well connections at the Haley and Hugoton systems in 2011 and improvements at the Granger system completed during 2010.

Capital expenditures increased by $16.7 million for the year ended December 31, 2010. Excluding cash paid for acquisitions, expansion capital expenditures for the year ended December 31, 2010, increased by $19.3 million, primarily due to Anadarko commencing the construction of the Bison assets in 2009 and placing them in service in June 2010, in addition to the purchase of previously leased compressors at the Granger and Wattenberg systems during 2010 prior to the Granger and Wattenberg acquisitions, offset by the indefinite postponement of an expansion project at the Red Desert complex, completion of the cryogenic unit at the Chipeta plant and a compressor overhaul at the Hugoton system during 2009. In addition, maintenance capital expenditures decreased by $2.6 million, primarily as a result of fewer well connections.

We estimate our total capital expenditures for the year ending December 31, 2012, including our 51% share of Chipeta’s capital expenditures and excluding acquisitions, to be $410 million to $460 million and our maintenance capital expenditures to be approximately 6% to 10% of total capital expenditures. Expected 2012 capital projects include our 51% share of the costs associated with the completion of a second cryogenic train at the Chipeta plant and the construction of new cryogenic processing plants in Colorado and Texas. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us, which are dependent, in part, on the drilling activities of Anadarko and third-party producers. We expect to fund future capital expenditures from cash flows generated from our operations, interest income from our note receivable from Anadarko, borrowings under our RCF, the issuance of additional partnership units or debt offerings.

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

	Year Ended December 31,
thousands	2011			2010			2009
Net cash provided by (used in):
Operating activities	$	327,171		$	263,749		$	212,765
Investing activities		(472,951	)		(885,507	)		(223,128	)
Financing activities		345,265			578,848			44,273
Net increase (decrease) in cash and cash equivalents	$	199,485		$	(42,910	)	$	33,910

Operating Activities. Net cash provided by operating activities increased by $63.4 million for the year ended December 31, 2011, primarily due to the following items:

• a $156.4 million increase in revenues, excluding equity income; and

• a $19.7 million increase due to changes in accounts payable balances and other items.

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

• an $80.9 million increase in cost of product expense;

• a $15.2 million increase in operation and maintenance expenses;

• an $11.6 million increase in interest expense;

• a $4.3 million increase in current income tax expense;

• a $2.3 million increase in property and other tax expense; and

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• a $1.3 million decrease due to changes in accounts receivable balances.

Net cash provided by operating activities increased by $51.0 million for the year ended December 31, 2010, primarily due to the following items:

• a $43.8 million increase in revenues, excluding equity income;

• a $12.7 million increase due to changes in accounts payable balances and other items;

• a $10.0 million decrease in current income tax expense; and

• a $2.7 million decrease in operation and maintenance expenses.

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

• an $8.8 million increase in interest expense;

• a $7.6 million increase in cost of product expense; and

• a $2.2 million decrease due to changes in accounts receivable balances.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2011, included the following:

• $302.0 million of cash paid for the Platte Valley acquisition;

• $142.9 million of capital expenditures;

• $25.0 million of cash paid for the Bison acquisition; and

• $3.8 million for equipment purchases from Anadarko.

Net cash used in investing activities for the year ended December 31, 2010, included the following:

• $473.1 million paid for the Wattenberg acquisition;

• $241.7 million of cash paid for the Granger acquisition;

• $138.0 million of capital expenditures; and

• $38.0 million paid for the White Cliffs acquisition.

Offsetting these amounts were $5.6 million of proceeds from the sale of idle compressors to Anadarko and the sale of an idle refrigeration unit at the Granger system to a third party.

Net cash used in investing activities for the year ended December 31, 2009, included the following:

• $121.3 million of capital expenditures; and

• $101.5 million paid for the Chipeta acquisition in July 2009.

See the sub-caption Capital expenditures above within this Liquidity and Capital Resources discussion.

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Financing Activities. Net cash provided by financing activities for the year ended December 31, 2011, included the following:

• $493.9 million of net proceeds from our Notes offering in May 2011;

• $303.0 million of borrowings to fund the Platte Valley acquisition;

• $250.0 million repayment of the Wattenberg term loan (described below) using borrowings from our RCF;

• $202.8 million of net proceeds from our September 2011 equity offering; and

• $132.6 million of net proceeds from our March 2011 equity offering.

Proceeds from both our March 2011 equity offering and Notes offering in May 2011 were used in the $619.0 million repayment of amounts outstanding under our RCF.

Net distributions to Parent attributable to pre-acquisition intercompany balances were $53.0 million during 2011, representing the net non-cash settlement of intercompany transactions attributable to the Bison and MGR assets.

Net cash provided by financing activities for the year ended December 31, 2010, included the following:

• $450.0 million of borrowings to partially fund the Wattenberg acquisition;

• $210.0 million to partially fund the Granger acquisition;

• $246.7 million of net proceeds from the November 2010 equity offering; and

• $99.1 million of net proceeds from the May 2010 equity offering.

Proceeds from both our May 2010 and November 2010 equity offerings were used in the $361.0 million repayment of amounts outstanding under our RCF.

Net contributions from Parent attributable to pre-acquisition intercompany balances were $39.4 million during 2010, representing the net non-cash settlement of intercompany transactions attributable to the Granger, Wattenberg, Bison and MGR assets.

Net cash provided by financing activities for the year ended December 31, 2009, included the following:

• $122.5 million of proceeds from the December 2009 equity offering;

• $101.5 million issuance of the three-year term loan to Anadarko in connection with the Chipeta acquisition, partially offset by its repayment in October 2009; and

• $4.3 million of costs paid in connection with the RCF we entered into in October 2009.

Proceeds from our December 2009 equity offering were used in the $101.5 million repayment of amounts outstanding under our RCF.

Net distributions to Parent attributable to pre-acquisition intercompany balances were $36.2 million during 2009, representing the net non-cash settlement of intercompany transactions attributable to the Chipeta, Granger, Wattenberg, Bison and MGR assets.

For the years ended December 31, 2011, 2010 and 2009 we paid $140.1 million, $94.2 million and $70.1 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $33.6 million, $2.1 million and $40.3 million during the years ended December 31, 2011, 2010 and 2009, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $17.5 million, $13.2 million and $8.0 million, for the years ended December 31, 2011, 2010 and 2009, respectively, representing the distributions for the four preceding quarterly periods ended September 30^th of the respective year.

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Debt and credit facilities. As of December 31, 2011, our outstanding debt consisted of $494.2 million of the Notes and the $175.0 million note payable to Anadarko. See Note 10. Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

5.375% Senior Notes due 2021. In May 2011, we completed the offering of $500.0 million aggregate principal amount of the Notes at a price to the public of 98.778% of the face amount of the Notes. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the Notes is paid semi-annually on June 1 and December 1 of each year, with payments commencing on December 1, 2011. Proceeds from the offering of the Notes (net of the underwriting discount of $3.3 million and debt issuance costs) were used to repay the then-outstanding balance on the RCF, with the remainder used for general partnership purposes.

The Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. We may redeem the Notes, in whole or in part, at any time before March 1, 2021, at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such Notes (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined in the indenture governing the Notes) plus 40 basis points, plus, in either case, accrued and unpaid interest, if any, on the principal amount being redeemed to such redemption date. On or after March 1, 2021, the Notes will be redeemable and repayable, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the Notes to be redeemed, plus accrued interest on the Notes to be redeemed to the date of redemption.

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees will be released if the Subsidiary Guarantors are released from their obligations under our RCF.

The Notes indenture contains customary events of default including, among others, (i) default in any payment of interest on any debt securities when due that continues for 30 days; (ii) default in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii) certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing the Notes also contains covenants that limit, among other things, our ability, as well as that of the Subsidiary Guarantors to (i) create liens on our principal properties; (ii) engage in sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease or transfer substantially all of our properties or assets to another entity. At December 31, 2011, we were in compliance with all covenants under the Notes.

Note payable to Anadarko. In December 2008, we entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 4.00% until November 2010. The term loan agreement was amended in December 2010 to fix the interest rate at 2.82% through maturity in 2013. We have the option, at any time, to repay the outstanding principal amount in whole or in part.

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

Revolving credit facility. In March 2011, we entered into an amended and restated $800.0 million senior unsecured RCF and borrowed $250.0 million under the RCF to repay the Wattenberg term loan (described below). The RCF amended and restated our $450.0 million credit facility, which was originally entered into in October 2009. The RCF matures in March 2016 and bears interest at London Interbank Offered Rate (“LIBOR”) plus applicable margins currently ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, plus applicable margins currently ranging from 0.30% to 0.90%. We are also required to pay a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon our senior unsecured debt rating.

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The RCF contains covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of our business, sell all or substantially all of our assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and certain financial tests as of the end of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization (“Consolidated EBITDA”) for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio (which is defined as the ratio of Consolidated EBITDA for the most recent four consecutive fiscal quarters to consolidated interest expense for such period) of 2.0 to 1.0.

All amounts due under the RCF are unconditionally guaranteed by our wholly owned subsidiaries. We will no longer be required to comply with the minimum consolidated interest coverage ratio, as well as the subsidiary guarantees and certain of the aforementioned covenants, if we obtain two of the following three ratings: BBB- or better by Standard & Poor’s, Baa3 or better by Moody’s Investors Service, or BBB- or better by Fitch Ratings. As of December 31, 2011, no amounts were outstanding under the RCF, and $800.0 million was available for borrowing. See Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for borrowing activity under our RCF in January 2012, related to the MGR acquisition. At December 31, 2011, we were in compliance with all covenants under the RCF.

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

Registered securities. We may issue an indeterminate amount of common units and various debt securities under our effective shelf registration statement on file with the U.S. Securities and Exchange Commission.

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

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

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

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

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CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual cash obligations as of December 31, 2011, including the contractual obligations of MGR. See Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K. The table below excludes amounts classified as current liabilities on the consolidated balance sheets, other than the current portions of the categories listed within the table. It is expected that the majority of the excluded current liabilities will be paid in cash in 2012.

	Obligations by Period
thousands	2012		2013		2014		2015		2016		Thereafter		Total
Long-term debt
Principal	$	—	$	175,000	$	—	$	—	$	—	$	500,000	$	675,000
Interest		31,810		32,043		26,875		26,875		26,875		119,967		264,445
Asset retirement obligations		875		—		—		1,694		470		61,106		64,145
Capital expenditures		30,203		—		—		—		—		—		30,203
Credit facility fees		2,005		2,000		2,000		2,000		460		—		8,465
Environmental obligations		1,679		481		481		160		160		349		3,310
Operating leases		261		228		168		168		168		103		1,096
Total	$	66,833	$	209,752	$	29,524	$	30,897	$	28,133	$	681,525	$	1,046,664

Debt and credit facility fees. For additional information on notes payable and credit facility fees required under our RCF, see Note 10. Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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, changes in retirement costs and the estimated timing of settlement. For additional information see Note 9. Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Capital expenditures. Included in this amount are capital obligations related to our expansion projects. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual obligations made in advance of the actual expenditures. See Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Environmental obligations. We are subject to various environmental-remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We regularly monitor the remediation and reclamation process and the liabilities recorded and believe our environmental obligations are adequate to fund remedial actions to comply with present laws and regulations. For additional information on environmental obligations, see Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Operating leases. Anadarko, on our behalf, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting our operations, for which it charges us rent. The amounts above represent existing contractual operating lease obligations that may be assigned or otherwise charged to us pursuant to the reimbursement provisions of the omnibus agreement. See Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

For additional information on contracts, obligations and arrangements we enter into from time to time, see Note 5. Transactions with Affiliates and Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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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 Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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 25 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by approximately $11.2 million, which would result in a corresponding reduction in our operating income.

Impairments of tangible assets. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the Partnership assets acquired by us from Anadarko are initially recorded at Anadarko’s historic carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. Property, plant and equipment balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts 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 impairments, 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, processing and transporting the 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 impairments 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.

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Impairments of 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. Accordingly, our goodwill balance does not reflect, and in some cases is significantly higher than, the difference between the consideration paid by us for acquisitions from Anadarko compared to the fair value of the net assets on the acquisition date. We evaluate whether goodwill has been impaired annually, as of October 1, or more often as facts and circumstances warrant. 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, 2011, was $77.3 million for the gathering and processing reporting unit and $4.8 million for the transportation reporting unit. 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 earnings before interest, taxes, depreciation, and amortization (“EBITDA”). Specifically, management estimates fair value by applying an estimated multiple to projected 2012 EBITDA. Management considered observable transactions in the market, as well as trading multiples for peers, to determine an appropriate multiple to apply against our projected 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, throughput 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 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.

Impairments of intangible assets. Our intangible asset balance at December 31, 2011, represents the fair value, net of amortization, of the contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011. These long-term contracts, which dedicate certain customers’ field production to the acquired gathering and processing system, provide an extended commercial relationship with the existing customers whereby we will have the opportunity to gather and process future production from the customers’ acreage. Customer relationships are amortized on a straight-line basis over 50 years, which is the estimated productive life of the reserves covered by the underlying acreage ultimately expected to be produced and gathered or processed through the Partnership’s assets subject to current contractual arrangements.

Management assesses intangible assets for impairment, together with the related underlying long-lived assets, whenever events or changes in circumstances indicate that the carrying amount of the respective asset may not be recoverable. Impairments exist when an asset’s carrying amount exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the tested asset. When alternative courses of action to recover the carrying amount 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 tested 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. No intangible asset impairment has been recognized in connection with these assets.

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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 and the initial recognition of environmental obligations assumed in third-party acquisitions. 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 utilizes the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions. 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 multiple 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 any off-balance sheet arrangements other than operating leases. The information pertaining to operating leases required for this item is provided under Note 11. Commitments and Contingencies included in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

RECENT ACCOUNTING DEVELOPMENTS

Recently issued accounting standard not yet adopted. In September 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that permits an initial assessment of qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount for goodwill impairment testing purposes. Thus, determining a reporting unit’s fair value is not required unless, as a result of the qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount. This ASU is effective prospectively beginning January 1, 2012. Adoption of this ASU will have no impact on our consolidated financial statements.

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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	2
Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009	3
Consolidated Balance Sheets as of December 31, 2011 and 2010	4
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2011, 2010 and 2009	5
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009	6
Notes to Consolidated Financial Statements	7
Supplemental Quarterly Information	39

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 (the Partnership) and subsidiaries as of December 31, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

May 22, 2012

2

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
thousands except per-unit amounts	2011 (1)			2010 (1)			2009 (1)
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	217,852		$	192,286		$	181,477
Natural gas, natural gas liquids and condensate sales		417,547			369,903			330,855
Equity income and other, net		13,598			9,439			9,518
Total revenues – affiliates		648,997			571,628			521,850
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		83,477			60,987			64,989
Natural gas, natural gas liquids and condensate sales		84,836			26,134			30,790
Other, net		5,955			4,525			2,135
Total revenues – third parties		174,268			91,646			97,914
Total revenues		823,265			663,274			619,764
Operating expenses
Cost of product (2)		327,371			246,476			238,874
Operation and maintenance (2)		119,104			103,887			106,590
General and administrative (2)		39,114			29,640			33,171
Property and other taxes		16,579			14,273			14,173
Depreciation, amortization and impairments		111,904			91,010			90,692
Total operating expenses		614,072			485,286			483,500
Operating income		209,193			177,988			136,264
Interest income, net – affiliates		28,560			20,243			20,717
Interest expense (3)		(30,345	)		(18,794	)		(9,955	)
Other income (expense), net		(44	)		(538	)		1,628
Income before income taxes		207,364			178,899			148,654
Income tax expense		19,018			21,702			22,159
Net income		188,346			157,197			126,495
Net income attributable to noncontrolling interests		14,103			11,005			10,260
Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235
Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235
Pre-acquisition net (income) loss allocated to Parent		(34,084	)		(32,061	)		(44,827	)
General partner interest in net (income) loss (4)		(8,599	)		(3,067	)		(1,428	)
Limited partners’ interest in net income (4)	$	131,560		$	111,064		$	69,980
Net income per common unit – basic and diluted	$	1.64		$	1.66		$	1.25
Net income per subordinated unit – basic and diluted (5)	$	1.28		$	1.61		$	1.24

⁽¹⁾  Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

⁽²⁾  Cost of product includes product purchases from Anadarko (as defined in Note 1) of $83.7 million, $95.7 million and $95.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. Operation and maintenance includes charges from Anadarko of $51.3 million, $46.4 million and $41.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. General and administrative includes charges from Anadarko of $31.9 million, $23.8 million and $27.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. See Note 5.

⁽³⁾  Includes affiliate (as defined in Note 1) interest expense of $4.9 million, $6.9 million and $9.1 million for years ended December 31, 2011, 2010 and 2009, respectively. See Note 10.

⁽⁴⁾  Represents net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 1). See also Note 4.

⁽⁵⁾  All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4.

See accompanying Notes to Consolidated Financial Statements.

3

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
thousands except number of units	2011 (1)		2010 (1)
ASSETS
Current assets
Cash and cash equivalents	$	226,559	$	27,074
Accounts receivable, net (2)		22,703		11,607
Other current assets (3)		7,186		5,944
Total current assets		256,448		44,625
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		2,638,013		2,239,808
Less accumulated depreciation		585,789		486,046
Net property, plant and equipment		2,052,224		1,753,762
Goodwill and other intangible assets		134,994		82,136
Equity investments		109,817		114,462
Other assets		24,143		8,109
Total assets	$	2,837,626	$	2,263,094
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables (4)	$	26,600	$	17,058
Accrued ad valorem taxes		8,186		6,262
Income taxes payable		495		160
Accrued liabilities (5)		41,315		28,240
Total current liabilities		76,596		51,720
Long-term debt – third parties		494,178		299,000
Note payable – Anadarko		175,000		175,000
Deferred income taxes		107,377		126,846
Asset retirement obligations and other		67,169		48,499
Total long-term liabilities		843,724		649,345
Total liabilities		920,320		701,065
Equity and partners’ capital
Common units (90,140,999 and 51,036,968 units issued and outstanding at December 31, 2011 and 2010, respectively)		1,495,253		810,717
Subordinated units (zero and 26,536,306 units issued and outstanding at December 31, 2011 and 2010, respectively) (6)		—		282,384
General partner units (1,839,613 and 1,583,128 units issued and outstanding at December 31, 2011 and 2010, respectively)		31,729		21,505
Parent net investment		269,600		356,961
Total partners’ capital		1,796,582		1,471,567
Noncontrolling interests		120,724		90,462
Total equity and partners’ capital		1,917,306		1,562,029
Total liabilities, equity and partners’ capital	$	2,837,626	$	2,263,094

⁽¹⁾  Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

⁽²⁾  Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of zero and $1.8 million as of December 31, 2011 and 2010, respectively.

⁽³⁾  Other current assets includes natural gas imbalance receivables from affiliates of $0.5 million and zero as of December 31, 2011 and 2010, respectively.

⁽⁴⁾  Accounts and natural gas imbalance payables includes amounts payable to affiliates of $5.9 million and $1.5 million as of December 31, 2011 and 2010, respectively.

⁽⁵⁾  Accrued liabilities include amounts payable to affiliates of $0.3 million and $0.6 million as of December 31, 2011 and 2010, respectively.

⁽⁶⁾  All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

See accompanying Notes to Consolidated Financial Statements.

4

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL

	Partners’ Capital
thousands	Parent Net Investment			Common Units			Subordinated Units			General Partner  Units			Noncontrolling Interests			Total
Balance at December 31, 2008 (1)	$	833,819		$	368,050		$	275,917		$	10,988		$	66,016		$	1,554,790
Net income		44,827			37,035			32,945			1,428			10,260			126,495
Issuance of common and general partner units, net of offering expenses		—			120,080			—			2,459			—			122,539
Contributions from noncontrolling interest owners		20,544			—			—			—			19,718			40,262
Distributions to noncontrolling interest owners		(2,926	)		—			—			—			(5,072	)		(7,998	)
Distributions to unitholders		—			(36,025	)		(32,640	)		(1,401	)		—			(70,066	)
Acquisition from affiliates		(112,744	)		11,068			—			225			—			(101,451	)
Net pre-acquisition contributions from (distributions to) Parent		(36,505	)		—			—			—			—			(36,505	)
Non-cash equity-based compensation and other		2,354			(2,978	)		349			27			—			(248	)
Balance at December 31, 2009 (1)	$	749,369		$	497,230		$	276,571		$	13,726		$	90,922		$	1,627,818
Net income		32,061			68,410			42,654			3,067			11,005			157,197
Issuance of common and general partner units, net of offering expenses		—			338,483			—			7,320			—			345,803
Contributions from noncontrolling interest owners		—			—			—			—			2,053			2,053
Distributions to noncontrolling interest owners		—			—			—			—			(13,222	)		(13,222	)
Distributions to unitholders		—			(55,108	)		(36,885	)		(2,201	)		—			(94,194	)
Acquisitions from affiliates		(684,487	)		(49,662	)		—			(631	)		—			(734,780	)
Net pre-acquisition contributions from (distributions to) Parent		44,335			—			—			—			—			44,335
Contribution of other assets from Parent		—			10,500			—			215			—			10,715
Elimination of net deferred tax liabilities		214,464			—			—			—			—			214,464
Non-cash equity-based compensation and other		1,219			864			44			9			(296	)		1,840
Balance at December 31, 2010 (1)	$	356,961		$	810,717		$	282,384		$	21,505		$	90,462		$	1,562,029
Net income		34,084			110,542			21,018			8,599			14,103			188,346
Conversion of subordinated units to common units (2)		—			272,222			(272,222	)		—			—			—
Issuance of common and general partner units, net of offering expenses		—			328,345			—			6,972			—			335,317
Contributions from noncontrolling interest owners		—			—			—			—			33,637			33,637
Distributions to noncontrolling interest owners		—			—			—			—			(17,478	)		(17,478	)
Distributions to unitholders		—			(102,091	)		(31,180	)		(6,847	)		—			(140,118	)
Acquisition from affiliates		(92,666	)		66,313			—			1,353			—			(25,000	)
Contributions of equity-based compensation from Parent		—			9,472			—			194			—			9,666
Net pre-acquisition contributions from (distributions to) Parent		(50,851	)		—			—			—			—			(50,851	)
Elimination of net deferred tax liabilities		22,072			—			—			—			—			22,072
Non-cash equity-based compensation and other		—			(267	)		—			(47	)		—			(314	)
Balance at December 31, 2011 (1)	$	269,600		$	1,495,253		$	—		$	31,729		$	120,724		$	1,917,306

⁽¹⁾  Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, 2009, and 2008, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

⁽²⁾  All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

See accompanying Notes to Consolidated Financial Statements.

5

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
thousands	2011 (1)			2010 (1)			2009 (1)
Cash flows from operating activities
Net income	$	188,346		$	157,197		$	126,495
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		111,904			91,010			90,692
Deferred income taxes		2,604			9,588			50
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		(881	)		424			2,669
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net		23,092			2,734			(14,267	)
Change in other items, net		2,106			2,796			7,126
Net cash provided by operating activities		327,171			263,749			212,765
Cash flows from investing activities
Capital expenditures		(142,946	)		(138,000	)		(121,295	)
Acquisitions from affiliates		(28,837	)		(734,780	)		(101,451	)
Acquisitions from third parties		(301,957	)		(18,047	)		—
Investments in equity affiliates		(93	)		(310	)		(382	)
Proceeds from sale of assets to affiliates		382			2,805			—
Proceeds from sale of assets to third parties		500			2,825			—
Net cash used in investing activities		(472,951	)		(885,507	)		(223,128	)
Cash flows from financing activities
Borrowings, net of debt issuance costs		1,055,939			660,000			101,451
Repayments of debt		(869,000	)		(361,000	)		(101,451	)
Revolving credit facility issuance costs		—			(12	)		(4,263	)
Proceeds from issuance of common and general partner units, net of offering expenses		335,317			345,803			122,539
Distributions to unitholders		(140,118	)		(94,194	)		(70,066	)
Contributions from noncontrolling interest owners		33,637			2,053			40,262
Distributions to noncontrolling interest owners		(17,478	)		(13,222	)		(7,998	)
Net contributions from (distributions to) Parent		(53,032	)		39,420			(36,201	)
Net cash provided by financing activities		345,265			578,848			44,273
Net increase (decrease) in cash and cash equivalents		199,485			(42,910	)		33,910
Cash and cash equivalents at beginning of period		27,074			69,984			36,074
Cash and cash equivalents at end of period	$	226,559		$	27,074		$	69,984
Supplemental disclosures
Elimination of net deferred tax liabilities	$	22,072		$	214,464		$	—
Contribution of assets (to) from Parent	$	(29	)	$	7,827		$	—
Increase (decrease) in accrued capital expenditures	$	5,402		$	5,218		$	13,390
Interest paid	$	25,828		$	16,497		$	9,372
Interest received	$	16,900		$	16,900		$	16,900
Taxes paid	$	190		$	507		$	—

⁽¹⁾  Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

See accompanying Notes to Consolidated Financial Statements.

6

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General. Western Gas Partners, LP (the “Partnership”), a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to own, operate, acquire and develop midstream energy assets, closed its initial public offering to become publicly traded in 2008. Including the effect of the acquisition of Mountain Gas Resources, LLC (“MGR”), the Partnership’s assets include thirteen gathering systems, seven natural gas treating facilities, ten natural gas processing facilities, two NGL pipelines, one interstate gas pipeline, one intrastate gas pipeline, and interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”), which are accounted for under the equity method. The Partnership’s assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming), and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko Petroleum Corporation and its consolidated subsidiaries, as well as third-party producers and customers.

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

Basis of presentation. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”), and certain amounts in prior periods have been reclassified to conform to the current presentation. The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest, and all significant intercompany transactions have been eliminated. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system in the accompanying consolidated financial statements.

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement, as amended and restated (the “Chipeta LLC agreement”) (see Notes 2 and 3). As of December 31, 2011, 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 Partnership’s consolidated financial statements for all periods presented.

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of December 31, 2011. Because of Anadarko’s control of the Partnership through its ownership of the general partner, each acquisition of Partnership assets, except for the acquisitions of the Platte Valley assets and the 9.6% interest in White Cliffs from third parties, was considered a transfer of net assets between entities under common control (see Note 2). As a result, after each acquisition of assets from Anadarko, the Partnership is required to recast its financial statements to include the activities of the Partnership assets as of the date of common control.

The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. Net income attributable to the Partnership assets for periods prior to the Partnership’s acquisition of such assets is not allocated to the limited partners for purposes of calculating net income per common or subordinated unit.

Use of estimates. In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the amounts reported in the consolidated financial statements and the notes thereto. Management evaluates its estimates and related assumptions regularly, utilizing historical experience and other methods considered reasonable under the circumstances. Changes in facts and circumstances or additional information, may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

7

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership 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, the Partnership utilizes the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions.

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 for identical instruments, if available, or average valuations of similar debt instruments at the balance sheet date. See Note 10.

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items.

Cash equivalents. The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Bad-debt reserve. The Partnership’s 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. At December 31, 2011 and 2010, third-party accounts receivable are shown net of the associated bad-debt reserve of $17,000.

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 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, 2011, natural gas imbalance receivables and payables were approximately $2.3 million and $3.1 million, respectively. As of December 31, 2010, natural gas imbalance receivables and payables were approximately $0.4 million and $2.6 million, respectively. Changes in natural gas imbalances are reported in equity income and other, net or cost of product in the consolidated statements of income.

Inventory. The cost of NGLs inventories is determined by the weighted average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets.

8

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Property, plant and equipment. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the Partnership assets acquired by the Partnership from Anadarko are initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to Partners’ capital.

Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. 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 that 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, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, 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 reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

The Partnership evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.

During the year ended December 31, 2011, an impairment of $7.3 million was recognized for certain equipment and materials. The costs of the equipment and materials, previously capitalized as assets under construction and related to a Red Desert complex (see Note 2) expansion project, were deemed no longer recoverable as the expansion project was indefinitely postponed by Anadarko management. Subsequent to the project evaluation and impairment, the remaining fair value of the equipment and materials, approximately $10.6 million, was reclassified from within property, plant and equipment to other assets on the consolidated balance sheet as of December 31, 2011. Also during 2011, following an evaluation of future cash flows, an impairment of $3.0 million was recognized for a transportation pipeline. This asset was impaired to fair value, estimated using Level 3 fair-value inputs.

During the year ended December 31, 2010, the Partnership recognized $0.6 million of impairment related to a compressor sold during the year to a third party, and $0.3 million of impairment due to cancelled capital projects and additional costs recorded on a project previously impaired to salvage value. During the year ended December 31, 2009, an impairment of $6.1 million was recognized for an idle pipeline for which no future cash flows were expected.

Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset.

Goodwill and other intangible assets. Goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the assets the Partnership has acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s goodwill balance does not reflect, and in some cases is significantly different than, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of the net assets on the acquisition date. The Partnership’s consolidated balance sheets as of December 31, 2011 and 2010, include goodwill of $82.1 million, none of which is deductible for tax purposes.

9

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The Partnership evaluates goodwill for impairment annually, as of October 1, or more often as facts and circumstances warrant. The first step in the goodwill impairment test is to compare the fair value of each reporting unit to which goodwill has been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. If the carrying amount of the reporting unit exceeds its fair value, step two in the goodwill impairment test requires goodwill to be written down to its implied fair value through a charge to operating expense based on a hypothetical purchase price allocation. No goodwill impairment has been recognized in these consolidated financial statements. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement.

The Partnership assesses intangible assets, as described in Note 8, for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense. No intangible asset impairment has been recognized in connection with these assets.

Equity-method investments. The following table presents the activity in the Partnership’s investments in equity of Fort Union, White Cliffs and Rendezvous:

	Equity Investments
thousands	Fort Union (1)			White Cliffs (2)			Rendezvous (3)
Balance at December 31, 2009	$	20,060		$	1,284		$	78,216
Investment earnings, net of amortization		5,723			917			988
Contributions		310			—			—
Distributions		(4,665	)		(1,270	)		(5,038	)
Acquisition of additional 9.6% interest from third party		—			18,047			—
Other		—			—			(110	)
Balance at December 31, 2010	$	21,428		$	18,978		$	74,056
Investment earnings, net of amortization		6,067			4,023			1,171
Contributions		—			93			—
Distributions		(5,227	)		(5,384	)		(5,388	)
Balance at December 31, 2011	$	22,268		$	17,710		$	69,839

⁽¹⁾  The Partnership has a 14.81% interest in Fort Union, a joint venture which 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. 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. Each of the joint venture members has pledged its respective equity interest to the administrative agent of Fort Union’s credit agreement.

⁽²⁾  The Partnership has a 10% interest in White Cliffs, a limited liability company which owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma and became operational in June 2009. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.

⁽³⁾  The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in southwestern Wyoming. 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 members’ gas servicing agreements, require unanimous approval of the members.

10

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The investment balance at December 31, 2011, includes $2.7 million and $47.9 million for the purchase price allocated to the investment in Fort Union and Rendezvous, respectively, in excess of the historic cost basis of Western Gas Resources, Inc. (entity that owned the interests in Fort Union and Rendezvous, which Anadarko acquired in August 2006). This excess balance is attributable to the difference between the fair value and book value of their gathering and treating facilities (at the time Western Gas Resources, Inc. was acquired by Anadarko) and is being amortized over the remaining estimated useful life of those facilities.

The White Cliffs investment balance at December 31, 2011, is $10.4 million less than the Partnership’s underlying equity in White Cliffs’ net assets as of December 31, 2011, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference is being amortized to equity income over the remaining estimated useful life of the White Cliffs pipeline.

Management evaluates its equity-method investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments 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.

Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for 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. Over time, the discounted liability is accreted through accretion expense to its expected settlement value. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 9.

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 or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 11.

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

Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are 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 and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered and delivered to pipelines for market delivery. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate are sold and the related purchases are recorded as a percentage of the product sale.

11

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue gas to either sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue gas. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower as liquids than as a component of the natural gas stream. Revenue is recognized from the sale of condensate and NGLs upon transfer of title and related purchases are recorded as cost of product.

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. Transportation 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 and NGLs 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 (the “FERC”) and reserves are established where appropriate. See Note 11 for discussion of the Partnership’s pending rate case with the FERC.

Proceeds from the sale of residue gas, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate 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 as revenues from gathering, processing and transportation of natural gas and natural gas liquids in the consolidated statements of income.

Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “LTIP”). The LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,160,848 units remain available for future issuance as of December 31, 2011. 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. Equity-based compensation expense attributable to grants made under the LTIP impact the Partnership’s cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. 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: (i) Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) and (ii) 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 in 2011 and 2010 were collectively valued at $634.00 per unit and $215.00 per unit as of December 31, 2011 and 2010, respectively. The UVRs and UARs 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 (net of 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. Upon the occurrence of a UAR vesting event, each participant will receive a lump-sum cash payment (net of any applicable withholding taxes) for each UAR that is exercised prior to (i) the 90^th day after a participant’s voluntary termination, or (ii) the 10^th anniversary of the grant date, whichever occurs first. 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.

12

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. For equity-based awards issued under the Incentive Plan and ultimately settled in cash, the fair value of the relevant equity grant is revised periodically based on the estimated fair value of the Partnership’s general partner using a discounted cash flow estimate and multiples-valuation terminal value. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact the Partnership’s cash flows 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. Equity-based compensation granted under the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities. See Note 5.

Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Federal and state income tax expense was recorded prior to the Partnership’s acquisition of the Partnership assets. In addition, deferred federal and state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases with respect to the Partnership assets prior to the Partnership’s acquisition; and deferred state income taxes are recorded with respect to the Partnership assets including and subsequent to acquisition. The recognition of deferred federal and state tax assets prior to the Partnership’s acquisition of the Partnership assets was based on management’s belief that it was more likely than not that the results of future operations would generate sufficient taxable income to realize the deferred tax assets. For periods including or subsequent to the Partnership’s acquisition of the Partnership assets, the Partnership is only subject to Texas margin tax; therefore, deferred federal income tax assets and liabilities with respect to the Partnership assets for periods including and subsequent to the Partnership’s acquisitions are no longer recognized by the Partnership.

For periods including and subsequent to the Partnership’s acquisition 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 estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, 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 accounting standard for uncertain tax positions 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, 2011 or 2010.

13

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Net income per common unit. The Partnership applies the two-class method in determining net income per unit applicable to master limited partnerships having multiple classes of securities including common units, general partnership units and incentive distribution rights (“IDRs”) of the general partner. Under the two-class method, net income per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. 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.

The Partnership’s net income for periods including and subsequent to the Partnership’s acquisitions of the Partnership assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. The Partnership’s net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner, common unitholders and subordinated unitholders consistent with actual cash distributions, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and subordinated unitholders in accordance with their respective ownership percentages during each period. See Note 4.

Other assets. For all periods presented, other assets on the Partnership’s consolidated balance sheets include a $0.7 million receivable recognized in conjunction with the capital lease component of a processing agreement assumed in connection with the MGR acquisition. The agreement, in which the Partnership is the lessor, extends through November 2014. Other assets also includes $4.6 million related to the unguaranteed residual value of the processing plant included in the processing agreement, based on a measurement of fair value estimated when the plant was acquired by Anadarko in 2006. Interest income related to the capital lease is recorded to other income (expense), net on the accompanying consolidated statements of income.

Recently issued accounting standard not yet adopted. In September 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that permits an initial assessment of qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount for goodwill impairment testing purposes. Thus, determining a reporting unit’s fair value is not required unless, as a result of the qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount. This ASU is effective prospectively beginning January 1, 2012. Adoption of this ASU will have no impact on the Partnership’s consolidated financial statements.

14

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.  ACQUISITIONS

The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2011, 2010 and 2009, and details the funding for those acquisitions through borrowings, cash on hand and/or the issuance of Partnership equity:

thousands except unit and     percent amounts	Acquisition Date		Percentage Acquired		Borrowings		Cash On Hand		Common Units Issued		GP Units Issued
Chipeta (1)		07/01/09		51%	$	101,451	$	4,638		351,424		7,172
Granger (2)		01/29/10		100%		210,000		31,680		620,689		12,667
Wattenberg (3)		08/02/10		100%		450,000		23,100		1,048,196		21,392
White Cliffs (4)		09/28/10		10%		—		38,047		—		—
Platte Valley (5)		02/28/11		100%		303,000		602		—		—
Bison (6)		07/08/11		100%		—		25,000		2,950,284		60,210

⁽¹⁾  The assets acquired from Anadarko include a 51% membership interest in Chipeta, together with an associated NGL pipeline. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. Chipeta owns a natural gas processing plant with two processing trains: a refrigeration unit and a cryogenic unit. In addition, in November 2009, Chipeta acquired the Natural Buttes plant including a compressor station and processing plant from a third party for $9.1 million, of which $4.5 million was contributed by the noncontrolling interest owners to fund their proportionate share. 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.”

⁽²⁾  The assets acquired from Anadarko include (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of cryogenic trains, a refrigeration train, an NGLs fractionation facility and ancillary equipment. These assets, located in southwestern Wyoming, are referred to collectively as the “Granger assets” and the acquisition as the “Granger acquisition.”

⁽³⁾  The assets acquired from Anadarko include the Wattenberg gathering system and related facilities, including the Fort Lupton processing plant. These assets, located in the Denver-Julesburg Basin, north and east of Denver, Colorado, are referred to collectively as the “Wattenberg assets” and the acquisition as the “Wattenberg acquisition.”

⁽⁴⁾  White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma, which became operational in June 2009. The Partnership’s acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko combined with the acquisition of an additional 9.6% interest in White Cliffs from a third party, are referred to collectively as the “White Cliffs acquisition.” The Partnership’s interest in White Cliffs is referred to as the “White Cliffs investment.”

⁽⁵⁾  The assets acquired from a third party include (i) a natural gas gathering system and related compression and other ancillary equipment, and (ii) cryogenic gas processing facilities. These assets, located in the Denver-Julesburg Basin, are referred to collectively as the “Platte Valley assets” and the acquisition as the “Platte Valley acquisition.” See further information below, including the final allocation of the purchase price in August 2011.

⁽⁶⁾  The Bison gas treating facility acquired from Anadarko is located in the Powder River Basin in northeastern Wyoming, and includes (i) three amine treating units, (ii) compressor units, and (iii) generators. These assets are referred to collectively as the “Bison assets” and the acquisition as the “Bison acquisition.” The Bison assets are the only treating and delivery point into the third-party-owned Bison pipeline. Anadarko began construction of the Bison assets in 2009 and placed them in service in June 2010. See further information below.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.  ACQUISITIONS (CONTINUED)

Platte Valley acquisition. The Platte Valley acquisition has been accounted for under the acquisition method of accounting. The Platte Valley assets and liabilities were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Platte Valley assets were included in the Partnership’s consolidated statements of income beginning on the acquisition date in the first quarter of 2011.

The table below reflects the final allocation of the purchase price, including a $1.6 million adjustment to intangible assets recorded in August 2011, to the assets acquired and liabilities assumed in the Platte Valley acquisition:

thousands
Property, plant and equipment	$	264,521
Intangible assets		53,754
Asset retirement obligations and other liabilities		(16,318	)
Total purchase price	$	301,957

The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the Platte Valley acquisition, after consideration of post-closing purchase price adjustments. The fair values of the plant and processing facilities, related equipment, and intangible assets acquired were based on the market, cost and income approaches. The liabilities assumed include certain amounts associated with environmental contingencies estimated by management. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. For more information regarding the intangible assets presented in the table above, see Note 8.

The following table presents the pro forma condensed financial information of the Partnership as if the Platte Valley acquisition had occurred on January 1, 2011:

thousands except per-unit amount	Year Ended December 31, 2011
Revenues	$	839,304
Net income		191,072
Net income attributable to Western Gas Partners, LP		176,969
Net income per common unit – basic and diluted	$	1.67

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s pro forma information in the table above includes $83.4 million of revenues and $59.1 million of operating expenses, excluding depreciation, amortization and impairments, attributable to the Platte Valley assets that are included in the Partnership’s consolidated statement of income for the year ended December 31, 2011. The pro forma adjustments reflect pre-acquisition results of the Platte Valley assets for January and February 2011, including (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the purchase price allocated to property, plant and equipment and other intangible assets and estimated useful lives; (c) elimination of $0.7 million of acquisition-related costs; and (d) interest on the Partnership’s borrowings under its revolving credit facility to finance the Platte Valley acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transactions are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the acquisition, nor any future acquisition related expenses. Pro forma information is not presented for periods ended on or before December 31, 2010, as it is not practical to determine revenues and cost of product for periods prior to January 1, 2011, the effective date of the gathering and processing agreement with the seller.

16

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.  ACQUISITIONS (CONTINUED)

Bison and MGR acquisitions. On January 13, 2012, the Partnership completed the acquisition of Anadarko’s 100% ownership interest in MGR which owns the Red Desert complex, a 22% interest in Rendezvous and related facilities, effective January 1, 2012. The Red Desert complex includes the Patrick Draw processing plant, the Red Desert processing plant, 1,295 miles of gathering lines and related facilities. Rendezvous owns a 338-mile mainline gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, which delivers gas to the Granger complex and other locations. These assets are referred to collectively as the “MGR assets” and the acquisition as the “MGR acquisition.” Consideration paid includes: (i) $159.6 million of cash on hand, (ii) $299.0 million borrowings on the Partnership’s senior unsecured revolving credit facility, and (iii) the issuance of 632,783 common units and 12,914 general partner units.

As transfers of net assets between entities under common control, the Partnership’s historical financial statements previously filed with the U.S. Securities and Exchange Commission (“SEC”) have been recast in this Current Report on Form 8-K to include the results attributable to the Bison and MGR assets as if the Partnership owned such assets for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

The following tables present the impact to the historical consolidated statements of income attributable to the Bison and MGR assets, including the elimination of intercompany activity between such assets:

	Year Ended December 31, 2010
thousands	Partnership Historical		Bison Assets			MGR Assets		Eliminations			Combined
Revenues	$	503,322	$	1,879		$	158,135	$	(62	)	$	663,274
Net income (loss)		137,073		(3,194	)		23,318		—			157,197
	Year Ended December 31, 2009
thousands	Partnership Historical		Bison Assets			MGR Assets		Eliminations			Combined
Revenues	$	490,546	$	—		$	129,218	$	—		$	619,764
Net income (loss)		118,166		(657	)		8,986		—			126,495

17

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.  PARTNERSHIP DISTRIBUTIONS

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

	Total Quarterly
thousands except per-unit amounts	Distribution	Total Cash	Date of
Quarters Ended	per Unit	Distribution	Distribution
2009
March 31	$    0.300	$    17,030	May 2009
June 30	$    0.310	$    17,718	August 2009
September 30	$    0.320	$    18,289	November 2009
December 31	$    0.330	$    21,393	February 2010
2010
March 31	$    0.340	$    22,042	May 2010
June 30	$    0.350	$    24,378	August 2010
September 30	$    0.370	$    26,381	November 2010
December 31	$    0.380	$    30,564	February 2011
2011
March 31	$    0.390	$    33,168	May 2011
June 30	$    0.405	$    36,063	August 2011
September 30	$    0.420	$    40,323	November 2011
December 31 (1)	$    0.440	$    43,027	February 2012

⁽¹⁾  On January 18, 2012, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

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, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such 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 (such as the Chipeta LLC agreement), 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.

18

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.  PARTNERSHIP DISTRIBUTIONS (CONTINUED)

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. 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:

	Total Quarterly Distribution Target Amount		Marginal Percentage Interest in Distributions
			Unitholders	General Partner
Minimum quarterly distribution		$    0.300	98.0%	2.0%
First target distribution		up to $    0.345	98.0%	2.0%
Second target distribution		above $    0.345 up to $    0.375	85.0%	15.0%
Third target distribution		above $    0.375 up to $    0.450	75.0%	25.0%
Thereafter		above $    0.450	50.0%	50.0%

The table above assumes that the Partnership’s general partner maintains its 2.0% 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 common units that it owns or may acquire.

4.  EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public equity offerings during 2009, 2010 and 2011:

thousands except unit     and per-unit amounts	Common Units Issued (2)		GP Units Issued (3)		Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
December 2009 equity offering		6,900,000		140,817	$	18.20	$	5,500	$	122,539
May 2010 equity offering (1)		4,558,700		93,035		22.25		4,427		99,074
November 2010 equity offering		8,415,000		171,734		29.92		10,325		246,729
March 2011 equity offering		3,852,813		78,629		35.15		5,621		132,569
September 2011 equity offering		5,750,000		117,347		35.86		7,655		202,748

⁽¹⁾  Refers collectively to the May 2010 equity offering issuance, and the June 2010 exercise of the underwriters’ over-allotment option.

⁽²⁾  Includes the issuance of 900,000 common units, 558,700 common units, 915,000 common units, 302,813 common units and 750,000 common units pursuant to the exercise, in full or in part, of the underwriters’ over-allotment options granted in connection with the December 2009, May 2010, November 2010, March 2011 and September 2011 equity offerings, respectively.

⁽³⁾  Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% interest.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Common and general partner units. The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.”

Conversion of subordinated units. From its inception through June 30, 2011, the Partnership paid equal distributions per unit on common, subordinated and general partner units. Upon payment of the cash distribution for the second quarter of 2011, the financial requirements for the conversion of all subordinated units were satisfied. As a result, the 26,536,306 subordinated units were converted on August 15, 2011, on a one-for-one basis, into common units. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. The Partnership’s net income was allocated to the general partner and the limited partners, including the holders of the subordinated units, through June 30, 2011, in accordance with their respective ownership percentages. The conversion does not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Anadarko holdings of Partnership equity. As of December 31, 2011, Anadarko held 1,839,613 general partner units representing a 2.0% general partner interest in the Partnership, 39,789,221 common units representing a 43.3% limited partner interest, and 100% of the Partnership’s IDRs. The public held 50,351,778 common units, representing a 54.7% interest in the Partnership. Refer to Note 2 for information related to the common and general partner units issued in conjunction with the MGR acquisition.

The Partnership’s net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 2), is allocated to the general partner and the limited partners in accordance with their respective ownership percentages (see Note 1).

Basic and diluted net income per common unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding.

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated units:

	Year Ended December 31,
thousands except per-unit amounts	2011			2010			2009
Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235
Pre-acquisition net (income) loss allocated to Parent		(34,084	)		(32,061	)		(44,827	)
General partner interest in net (income) loss		(8,599	)		(3,067	)		(1,428	)
Limited partners’ interest in net income	$	131,560		$	111,064		$	69,980
Net income allocable to common units	$	110,542		$	68,410		$	37,035
Net income allocable to subordinated units		21,018			42,654			32,945
Limited partners’ interest in net income	$	131,560		$	111,064		$	69,980
Net income per unit – basic and diluted
Common units	$	1.64		$	1.66		$	1.25
Subordinated units	$	1.28		$	1.61		$	1.24
Weighted average units outstanding – basic and diluted
Common units		67,333			41,287			29,684
Subordinated units		16,431			26,536			26,536

20

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES

Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue gas, condensate and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operating and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. A portion of the Partnership’s general and administrative expenses is paid by Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the omnibus agreement. Affiliate expenses do not inherently bear a direct relationship to affiliate revenues, and third-party expenses do not necessarily bear a direct relationship to third-party revenues. See Note 2 for further information related to contributions of assets to the Partnership by Anadarko.

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

Note receivable from and note payable to Anadarko. Concurrent with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was approximately $303.7 million and $258.9 million at December 31, 2011 and 2010, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments.

In December 2008, the Partnership entered into a term loan agreement with Anadarko, discussed further in Note 10.

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold at the Hilight, Hugoton, Newcastle, Granger and Wattenberg assets, with various expiration dates through September 2015. In December 2011, the Partnership extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2013. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. See Note 12 for commodity price swap agreements entered into in December 2011, related to the MGR acquisition, with forward-starting effective dates beginning January 2012.

21

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

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

	Year Ended December 31,
per barrel except natural gas	2012		2013		2014		2015
Ethane	$	18.21 – 29.78	$	18.32 – 30.10	$	18.36 – 30.53	$	18.41
Propane	$	45.23 – 53.28	$	45.90 – 55.84	$	46.47 – 52.37	$	47.08
Isobutane	$	57.50 – 67.22	$	60.44 – 68.11	$	61.24 – 69.23	$	62.09
Normal butane	$	52.40 – 62.92	$	53.20 – 66.37	$	53.89 – 64.78	$	54.62
Natural gasoline	$	69.77 – 85.15	$	70.89 – 92.23	$	71.85 – 79.74	$	72.88
Condensate	$	72.73 – 78.52	$	74.04 – 83.93	$	75.22 – 79.56	$	76.47 – 78.61
Natural gas (per MMbtu)	$	4.15 –   5.97	$	3.75 –   6.09	$	5.32 –   6.20	$	5.50 –   5.96

The following table summarizes realized gains and losses on commodity price swap agreements:

	Year Ended December 31,
thousands	2011			2010			2009
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	33,845		$	20,200		$	18,446
Natural gas liquids sales		(36,802	)		2,953			2,196
Total		(2,957	)		23,153			20,642
Losses on commodity price swap agreements related to purchases (2)		(27,234	)		(23,344	)		(16,538	)
Net gains (losses) on commodity price swap agreements	$	(30,191	)	$	(191	)	$	4,104

⁽¹⁾  Reported in natural gas, NGLs and condensate sales in the Partnership’s consolidated statements of income in the period in which the related sale is recorded.

⁽²⁾  Reported in cost of product in the Partnership’s consolidated statements of income in the period in which the related purchase is recorded.

Gas gathering and processing agreements. The Partnership has significant gas gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. Approximately 75%, 73% and 76% of the Partnership’s gathering, transportation and treating throughput for the years ended December 31, 2011, 2010 and 2009, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 64%, 66% and 58% of the Partnership’s processing throughput for the years ended December 31, 2011, 2010 and 2009, respectively, was attributable to natural gas production owned or controlled by Anadarko.

In connection with the MGR acquisition, the Partnership entered into 10-year, fee-based gathering and processing agreements with Anadarko effective December 1, 2011, for all affiliate throughput on the MGR assets.

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

22

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Omnibus agreement. Pursuant to the omnibus agreement, Anadarko and the general partner perform centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing; and midstream administration. The Partnership’s reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership was capped at $9.0 million and $6.9 million for the years ended December 31, 2010 and 2009, respectively. The cap under the omnibus agreement expired on December 31, 2010. Expenses in excess of the cap for the years ended December 31, 2010 and 2009, were recorded as capital contributions from Anadarko and did not impact the Partnership’s cash flows. For the year ended December 31, 2011, and thereafter, Anadarko, in accordance with the partnership and omnibus agreements, determined, in its reasonable discretion, amounts to be allocated to the Partnership in exchange for services provided under the omnibus agreement. Such amount was $19.5 million for the year ended December 31, 2011, comprised of $11.8 million of allocated general and administrative expenses and $7.7 million of public company expenses. The Partnership also incurred $8.0 million and $7.5 million in public company expenses not subject to the cap previously contained in the omnibus agreement, excluding equity-based compensation, during the years ended December 31, 2010 and 2009, respectively. See Summary of affiliate transactions below.

Services and secondment agreement. Pursuant to the services and secondment agreement, specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement extends through May 2018 and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination before the applicable twelve-month period expires. The consolidated financial statements of the Partnership include costs allocated by Anadarko pursuant to the services and secondment agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership assets.

Tax sharing agreement. Pursuant to a tax sharing agreement, the Partnership reimburses Anadarko for the Partnership’s estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, borne by Anadarko on behalf of the Partnership as a result of the Partnership’s results being included in a combined or consolidated tax return filed by Anadarko with respect to periods including and subsequent to the Partnership’s acquisition of the Partnership assets. Anadarko may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. Nevertheless, the Partnership is required to reimburse Anadarko for its estimated share of taxes 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 incurred by Anadarko 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 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.

23

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Long-term incentive plan. The general partner awarded phantom units under the LTIP primarily to (i) the general partner’s Chief Executive Officer and (ii) independent directors in 2011, and primarily to independent directors in 2010 and 2009. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense attributable to the phantom units granted under the LTIP is recognized entirely by the Partnership over the vesting period and was approximately $0.3 million, $0.3 million and $0.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. As of December 31, 2011, there was $0.6 million of unrecognized compensation expense attributable to the LTIP, of which $0.5 million will be allocated to the Partnership, and is expected to be recognized over a weighted-average period of 2.3 years.

The following table summarizes LTIP award activity for the years ended December 31, 2011, 2010 and 2009:

	2011					2010					2009
	Weighted-					Weighted-					Weighted-
	Average					Average					Average
	Grant-Date					Grant-Date					Grant-Date
	Fair Value		Units			Fair Value		Units			Fair Value		Units
Phantom units outstanding at beginning of year	$	20.19		17,503		$	15.02		21,970		$	16.50		30,304
Vested	$	20.51		(15,119	)	$	15.02		(19,751	)	$	16.50		(30,304	)
Granted	$	35.66		21,594		$	20.94		15,284		$	15.02		21,970
Phantom units outstanding at end of year	$	33.92		23,978		$	20.19		17,503		$	15.02		21,970

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, 2011, 2010 and 2009 included approximately $13.9 million, $5.4 million and $4.1 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.

As of December 31, 2011, the Partnership estimates that $5.5 million of unrecognized compensation expense attributable to the Incentive Plan will be allocated to the Partnership over a weighted-average period of 1.4 years. In addition, the Partnership estimates that $3.7 million of unrecognized compensation expense attributable to the Anadarko Incentive Plans, excluding performance-based awards, will be allocated to the Partnership over a weighted-average period of 2.0 years. As of December 31, 2011, the compensation cost related to performance-based awards under the Anadarko Incentive Plans that could be allocated to the Partnership during the next three years is approximately $0.1 million.

Equipment purchase and sale. In September 2010, the Partnership sold idle compressors with a net carrying value of $2.6 million to Anadarko for $2.8 million in cash. The gain on the sale was recorded as an adjustment to Partners’ capital. In November 2010, the Partnership purchased compressors with a net carrying value of $0.4 million from Anadarko for $0.4 million in cash.

In November 2011, the Partnership purchased equipment with a net carrying value of $2.0 million from Anadarko for $3.8 million in cash, with the difference recorded as an adjustment to Partners’ capital.

24

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. Affiliate transactions include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas. The following table summarizes affiliate transactions, including transactions with Anadarko, its affiliates and the general partner:

	Year Ended December 31,
thousands	2011		2010		2009
Revenues (1)	$	648,997	$	571,628	$	521,850
Cost of product (1)		83,722		95,667		94,999
Operation and maintenance (2)		51,339		46,379		41,444
General and administrative (3)		31,855		23,807		27,408
Operating expenses		166,916		165,853		163,851
Interest income, net (4)		28,560		20,243		20,717
Interest expense (5)		4,935		6,924		9,096
Distributions to unitholders (6)		68,039		52,337		44,450
Contributions from noncontrolling interest owners		16,476		2,019		34,011
Distributions to noncontrolling interest owners		9,437		6,476		5,410

⁽¹⁾  Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

⁽²⁾  Represents expenses incurred under the services and secondment agreement, as applicable.

⁽³⁾  Represents general and administrative expense incurred under the omnibus agreement, as applicable.

⁽⁴⁾  Represents interest income recognized on the note receivable from Anadarko. This line item also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

⁽⁵⁾  Represents interest expense recognized on the note payable to Anadarko.

⁽⁶⁾  Represents distributions paid under the partnership agreement.

Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented on the Partnership’s consolidated statements of income.

6.  INCOME TAXES

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

	Year Ended December 31,
thousands	2011		2010			2009
Current income tax expense (benefit)
Federal income tax expense (benefit)	$	15,890	$	10,580		$	20,253
State income tax expense		524		1,534			1,856
Total current income tax expense (benefit)		16,414		12,114			22,109
Deferred income tax expense (benefit)
Federal income tax expense (benefit)		2,464		9,709			696
State income tax expense (benefit)		140		(121	)		(646	)
Total deferred income tax expense (benefit)		2,604		9,588			50
Total income tax expense	$	19,018	$	21,702		$	22,159

25

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6.  INCOME TAXES (CONTINUED)

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,
thousands except percentages	2011		2010		2009
Income before income taxes	$	207,364	$	178,899	$	148,654
Statutory tax rate		0%		0%		0%
Tax computed at statutory rate	$	—	$	—	$	—
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition		18,354		20,678		21,407
State taxes on income attributable to Partnership assets pre-acquisition
(net of federal benefit)		—		724		852
Texas margin tax expense (benefit)		664		300		(100	)
Income tax expense	$	19,018	$	21,702	$	22,159
Effective tax rate		9%		12%		15%

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

	December 31,
thousands	2011			2010
Credit carryforwards	$	14		$	14
Other		—			2
Net current deferred income tax assets		14			16
Depreciable property		(83,566	)		(100,889	)
Partnership basis		(24,481	)		(26,320	)
Credit carryforwards		556			570
Other		114			(207	)
Net long-term deferred income tax liabilities		(107,377	)		(126,846	)
Total net deferred income tax liabilities	$	(107,363	)	$	(126,830	)

Credit carryforwards, which are available for utilization on future income tax returns, consist of $0.6 million of state income tax credits that expire in 2026.

26

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7.  PROPERTY, PLANT AND EQUIPMENT

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

	Estimated		December 31,
thousands	Useful Life		2011		2010
Land		n/a	$	364	$	364
Gathering systems		5 to 47 years		2,437,152		2,102,219
Pipelines and equipment		15 to 45 years		90,883		89,778
Assets under construction		n/a		104,687		44,388
Other		3 to 25 years		4,927		3,059
Total property, plant and equipment				2,638,013		2,239,808
Accumulated depreciation				585,789		486,046
Net property, plant and equipment			$	2,052,224	$	1,753,762

The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet suitable to be placed into productive service as of the respective balance sheet date. In addition, property, plant and equipment cost, as well as third-party accrued liability balances in the Partnership’s consolidated balance sheets include $15.0 million and $9.6 million of accrued capital as of December 31, 2011 and 2010, respectively, representing estimated capital expenditures for which invoices had not yet been processed.

8.  OTHER INTANGIBLE ASSETS

The intangible asset balance in the Partnership’s consolidated balance sheets represents the fair value, net of amortization, related to the contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which dedicate certain customers’ field production to the acquired gathering and processing system. These long-term contracts provide an extended commercial relationship with the existing customers whereby the Partnership will have the opportunity to gather and process future production from the customers’ acreage. These contracts are generally limited, however, by the quantity and production life of the underlying natural gas resource base.

At December 31, 2011, the carrying value of the Partnership’s customer relationship intangible assets was $52.9 million, net of $0.9 million of accumulated amortization, and was included in goodwill and other intangible assets in the Partnership’s consolidated balance sheets. Customer relationships are amortized on a straight-line basis over 50 years, which is the estimated productive life of the reserves covered by the underlying acreage ultimately expected to be produced and gathered or processed through the Partnership’s assets subject to current contractual arrangements. No intangible asset impairment has been recognized in connection with these assets (see Note 1).

Estimated future amortization for these intangible assets over the next five years is as follows:

thousands	Future Amortization
2012	$	1,075
2013		1,075
2014		1,075
2015		1,075
2016		1,075

27

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9.  ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations:

	Year Ended December 31,
thousands	2011			2010
Carrying amount of asset retirement obligations at beginning of year	$	44,777		$	55,862
Liabilities incurred		15,390			800
Liabilities settled		—			(104	)
Accretion expense		3,781			3,740
Revisions in estimated liabilities		(679	)		(15,521	)
Carrying amount of asset retirement obligations at end of year	$	63,269		$	44,777

The increase in asset retirement obligations for the year ended December 31, 2011, is primarily a result of the liabilities incurred in connection with the acquisition of the Platte Valley assets (see Note 2). Revisions in estimates for the year ended December 31, 2010, related primarily to a decrease in the inflation rate.

10.  DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt as of December 31, 2011 and 2010:

	December 31, 2011						December 31, 2010
thousands	Principal		Carrying Value		Fair Value		Principal		Carrying Value		Fair Value
Revolving credit facility	$	—	$	—	$	—	$	49,000	$	49,000	$	49,000
5.375% Senior Notes due 2021		500,000		494,178		499,950		—		—		—
Wattenberg term loan		—		—		—		250,000		250,000		250,000
Note payable to Anadarko		175,000		175,000		174,528		175,000		175,000		168,116
Total debt outstanding (1)	$	675,000	$	669,178	$	674,478	$	474,000	$	474,000	$	467,116

⁽¹⁾  The Partnership’s consolidated balance sheets include accrued interest expense of $2.7 million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

28

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2011 and 2010:

thousands	Carrying Value
Balance as of December 31, 2009	$	175,000
Revolving credit facility borrowings		410,000
Repayment of revolving credit facility		(361,000	)
Revolving credit facility borrowings – Swingline		10,000
Repayment of revolving credit facility – Swingline		(10,000	)
Issuance of Wattenberg term loan		250,000
Balance as of December 31, 2010	$	474,000
Revolving credit facility borrowings		570,000
Repayment of revolving credit facility		(619,000	)
Repayment of Wattenberg term loan		(250,000	)
Revolving credit facility borrowings – Swingline		30,000
Repayment of revolving credit facility – Swingline		(30,000	)
Issuance of 5.375% Senior Notes due 2021		500,000
Other and changes in debt discount		(5,822	)
Balance as of December 31, 2011	$	669,178

5.375% Senior Notes due 2021. In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “Notes”) at a price to the public of 98.778% of the face amount of the Notes. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the Notes is paid semi-annually on June 1 and December 1 of each year, with payments commencing on December 1, 2011. Proceeds from the offering of the Notes (net of the underwriting discount of $3.3 million and debt issuance costs) were used to repay the then-outstanding balance on the Partnership’s revolving credit facility, with the remainder used for general partnership purposes.

The Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the Notes in whole or in part, at any time before March 1, 2021, at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such Notes (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined in the indenture governing the Notes) plus 40 basis points, plus, in either case, accrued and unpaid interest, if any, on the principal amount being redeemed to such redemption date. On or after March 1, 2021, the Notes will be redeemable and repayable, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the Notes to be redeemed, plus accrued interest on the Notes to be redeemed to the date of redemption.

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Partnership’s wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees will be released if the Subsidiary Guarantors are released from their obligations under the Partnership’s revolving credit facility. See Note 13 for the condensed financial statements of the Subsidiary Guarantors.

The Notes indenture contains customary events of default including, among others, (i) default in any payment of interest on any debt securities when due that continues for 30 days; (ii) default in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii) certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing the Notes also contains covenants that limit, among other things, the ability of the Partnership and the Subsidiary Guarantors to (i) create liens on their principal properties; (ii) engage in sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease or transfer substantially all of their properties or assets to another entity. At December 31, 2011, the Partnership was in compliance with all covenants under the Notes.

29

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

Note payable to Anadarko. In December 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 4.00% until November 2010. The term loan agreement was amended in December 2010 to fix the interest rate at 2.82% through maturity in 2013. The Partnership has the option, at any time, to repay the outstanding principal amount in whole or in part.

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

Revolving credit facility. In March 2011, the Partnership entered into an amended and restated $800.0 million senior unsecured revolving credit facility (the “RCF”) and borrowed $250.0 million under the RCF to repay the Wattenberg term loan (described below). The RCF amended and restated the Partnership’s $450.0 million credit facility, which was originally entered into in October 2009. The RCF matures in March 2016 and bears interest at London Interbank Offered Rate (“LIBOR”) plus applicable margins currently ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.80% and 3.26% at December 31, 2011 and 2010, respectively. The Partnership is required to pay a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon the Partnership’s senior unsecured debt rating. The facility fee rate was 0.25% and 0.50% at December 31, 2011 and 2010, respectively.

The RCF contains covenants that limit, among other things, the ability of the Partnership and certain of its subsidiaries to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of the Partnership’s assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and certain financial tests as of the end of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization (“Consolidated EBITDA”) for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio (which is defined as the ratio of Consolidated EBITDA for the most recent four consecutive fiscal quarters to consolidated interest expense for such period) of 2.0 to 1.0.

All amounts due under the RCF are unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. The Partnership will no longer be required to comply with the minimum consolidated interest coverage ratio, as well as the subsidiary guarantees and certain of the aforementioned covenants, if the Partnership obtains two of the following three ratings: BBB- or better by Standard & Poor’s, Baa3 or better by Moody’s Investors Service, or BBB- or better by Fitch Ratings. At December 31, 2011, the Partnership was in compliance with all covenants under the RCF. As of December 31, 2011, no amounts were outstanding under the RCF, and $800.0 million was available for borrowing. See Note 2 for borrowing activity under the RCF in January 2012, related to the MGR acquisition.

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

Interest-rate swap agreement. The Partnership entered into a forward-starting interest-rate swap agreement in March 2011 to mitigate the risk of rising interest rates prior to the issuance of the Notes. In May 2011, the Partnership issued the Notes and terminated the swap agreement, realizing a loss of $1.9 million, which is included in other expense, net in the Partnership’s consolidated statements of income.

30

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

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

	Year Ended December 31,
thousands	2011			2010		2009
Third Parties
Interest expense on long-term debt	$	20,533		$	8,530	$	304
Amortization of debt issuance costs and commitment fees (1)		5,297			3,340		555
Capitalized interest		(420	)		—		—
Total interest expense – third parties		25,410			11,870		859
Affiliates
Interest expense on notes payable to Anadarko		4,935			6,828		8,953
Credit facility commitment fees		—			96		143
Total interest expense – affiliates		4,935			6,924		9,096
Interest expense	$	30,345		$	18,794	$	9,955

⁽¹⁾  For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees related to the Notes.

11.  COMMITMENTS AND CONTINGENCIES

Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As of December 31, 2011, the Partnership’s consolidated balance sheet included a $1.7 million current liability and a $1.6 million long-term liability for remediation and reclamation obligations, included in third-party accrued liabilities and asset retirement obligations and other, respectively. As of December 31, 2010, the Partnership’s consolidated balance sheet included a $0.6 million current liability and a $0.9 million long-term liability for remediation and reclamation obligations, included in third-party accrued liabilities and asset retirement obligations and other, respectively. The recorded obligations do not include any anticipated insurance recoveries. Substantially all of the payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes the Partnership’s environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership’s overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.  COMMITMENTS AND CONTINGENCIES (CONTINUED)

Litigation and legal proceedings. In March 2011, DCP Midstream LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering LLC, in Weld County District Court (the “Court”) in Colorado, alleging that Anadarko and its affiliates diverted gas from DCP’s gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering LLC, the entity which holds the Wattenberg assets. Anadarko countersued DCP asserting that DCP has not properly allocated values and charges to Anadarko for the gas that DCP gathers and/or processes, and seeks a judgment that DCP has no valid gathering or processing rights to much of the gas production it is claiming, in addition to other claims. In July 2011, the Court denied the defendants’ motion to dismiss without ruling on the merits and the case is proceeding to the discovery phase. Management does not believe the outcome of this proceeding will have a material effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership intends to vigorously defend this litigation. Furthermore, without regard to the merit of DCP’s claims, management believes that the Partnership has adequate contractual indemnities covering the claims against it in this lawsuit.

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

Other commitments. The Partnership has short-term payment obligations, or commitments, related to capital spending programs of the Partnership, as well as its unconsolidated affiliates. As of December 31, 2011, the Partnership had unconditional payment obligations for services to be rendered, or products to be delivered in connection with its capital projects of approximately $30.2 million, primarily related to the construction of a second cryogenic train at the Chipeta plant, all of which will be spent in 2012.

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations. The leases for the shared field offices extend through 2018, and the lease for the warehouse extends through March 2012 and includes an early termination clause. The lease for the Partnership’s corporate offices expires in January 2012, and during 2011, Anadarko entered into a new agreement for the Partnership’s corporate offices that extends through March 2017. Anadarko, on behalf of the Partnership, continues to lease certain other compression equipment under leases expiring through January 2015.

In addition, during 2010, Anadarko and Kerr-McGee Gathering LLC purchased an aggregate $44.5 million of previously leased compression equipment used at the Granger and Wattenberg assets, which terminated the leases and associated lease expense. The purchased compression equipment was contributed to the Partnership pursuant to provisions of the contribution agreements for the Granger and the Wattenberg acquisitions. Rent expense associated with the office, warehouse and equipment leases was approximately $4.1 million, $7.7 million and $10.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2011, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:

thousands	Operating Leases
2012	$	261
2013		228
2014		168
2015		168
2016		168
Thereafter		103
Total	$	1,096

32

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12.  SUBSEQUENT EVENT

Refer to Note 2 for a description of the MGR acquisition in January 2012. In conjunction with the MGR acquisition, the Partnership entered into commodity price swap agreements with Anadarko that do not contain fixed notional volumes, each effective for one year beginning January 1, 2012, and extending through December 31, 2016. Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements for the system:

	Year Ended December 31,
per barrel except natural gas	2012		2013		2014		2015		2016
Ethane	$	26.87	$	25.34	$	24.10	$	23.41	$	23.11
Propane	$	57.97	$	55.59	$	53.78	$	52.99	$	52.90
Isobutane	$	80.98	$	77.66	$	75.13	$	74.02	$	73.89
Normal butane	$	71.15	$	68.24	$	66.01	$	65.04	$	64.93
Natural gasoline	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Condensate	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Natural gas (per MMbtu)	$	3.62	$	4.17	$	4.45	$	4.66	$	4.87

13.  CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

The Partnership may issue an indeterminate amount of common units and various debt securities under its effective shelf registration statement on file with the SEC. The Notes are, and any future debt securities issued under such registration statement may be, guaranteed by the Subsidiary Guarantors. The guarantees are full, unconditional, joint and several. The following condensed consolidating financial information reflects the Partnership’s stand-alone accounts, the combined accounts of the Subsidiary Guarantors, the accounts of the Non-Guarantor Subsidiary, consolidating adjustments, and eliminations and the Partnership’s consolidated financial information. 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 Subsidiary Guarantors’ investment in and equity income from their subsidiaries are presented in accordance with the equity method of accounting in which the equity income from subsidiaries includes the results of operations of the Partnership assets for periods including and subsequent to the Partnership’s acquisition of the Partnership assets.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

	Statement of Income Year Ended December 31, 2011
thousands	Western Gas Partners, LP			Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations			Consolidated
Revenues	$	(2,957	)	$	756,764	$	69,458	$	—		$	823,265
Operating expenses		61,009			512,374		40,689		—			614,072
Operating income (loss)		(63,966	)		244,390		28,769		—			209,193
Interest income, net – affiliates		16,900			11,693		—		(33	)		28,560
Interest expense		(30,378	)		—		—		33			(30,345	)
Other income (expense), net		(1,745	)		1,689		12		—			(44	)
Equity income		219,349			14,678		—		(234,027	)		—
Income before income taxes		140,160			272,450		28,781		(234,027	)		207,364
Income tax expense		—			19,018		—		—			19,018
Net income		140,160			253,432		28,781		(234,027	)		188,346
Net income attributable to noncontrolling interests		—			14,103		—		—			14,103
Net income attributable to Western Gas Partners, LP	$	140,160		$	239,329	$	28,781	$	(234,027	)	$	174,243

	Statement of Income Year Ended December 31, 2010
thousands	Western Gas Partners, LP			Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations			Consolidated
Revenues	$	23,153		$	596,033	$	44,088	$	—		$	663,274
Operating expenses		44,593			419,058		21,635		—			485,286
Operating income (loss)		(21,440	)		176,975		22,453		—			177,988
Interest income, net – affiliates		16,900			3,374		—		(31	)		20,243
Interest expense		(18,825	)		—		—		31			(18,794	)
Other income (expense), net		(2,331	)		1,787		6		—			(538	)
Equity income		139,613			11,454		—		(151,067	)		—
Income before income taxes		113,917			193,590		22,459		(151,067	)		178,899
Income tax expense		—			21,702		—		—			21,702
Net income		113,917			171,888		22,459		(151,067	)		157,197
Net income attributable to noncontrolling interests		—			11,005		—		—			11,005
Net income attributable to Western Gas Partners, LP	$	113,917		$	160,883	$	22,459	$	(151,067	)	$	146,192

34

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

	Statement of Income Year Ended December 31, 2009
thousands	Western Gas Partners, LP			Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations			Consolidated
Revenues	$	20,642		$	557,115	$	42,007	$	—		$	619,764
Operating expenses		34,602			427,820		21,078		—			483,500
Operating income (loss)		(13,960	)		129,295		20,929		—			136,264
Interest income, net – affiliates		16,900			3,834		—		(17	)		20,717
Interest expense		(9,972	)		—		—		17			(9,955	)
Other income (expense), net		32			1,586		10		—			1,628
Equity income		78,408			5,138		—		(83,546	)		—
Income before income taxes		71,408			139,853		20,939		(83,546	)		148,654
Income tax expense		—			22,159		—		—			22,159
Net income		71,408			117,694		20,939		(83,546	)		126,495
Net income attributable to noncontrolling interests		—			10,260		—		—			10,260
Net income attributable to Western Gas Partners, LP	$	71,408		$	107,434	$	20,939	$	(83,546	)	$	116,235

35

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

	Balance Sheet December 31, 2011
thousands	Western Gas Partners, LP		Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations			Consolidated
Current assets	$	207,913	$	110,619	$	25,977	$	(88,061	)	$	256,448
Note receivable – Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		1,232,245		130,396		—		(1,362,641	)		—
Net property, plant and equipment		735		1,812,275		239,214		—			2,052,224
Other long-term assets		8,164		260,790		—		—			268,954
Total assets	$	1,709,057	$	2,314,080	$	265,191	$	(1,450,702	)	$	2,837,626
Current liabilities	$	95,817	$	56,762	$	12,078	$	(88,061	)	$	76,596
Long-term debt		669,178		—		—		—			669,178
Deferred income taxes		—		107,377		—		—			107,377
Asset retirement obligations and other		104		64,980		2,085		—			67,169
Total liabilities		765,099		229,119		14,163		(88,061	)		920,320
Partners’ capital		943,958		1,964,237		251,028		(1,362,641	)		1,796,582
Noncontrolling interests		—		120,724		—		—			120,724
Total liabilities, equity and partners’ capital	$	1,709,057	$	2,314,080	$	265,191	$	(1,450,702	)	$	2,837,626
	Balance Sheet December 31, 2010
thousands	Western Gas Partners, LP		Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations			Consolidated
Current assets	$	24,972	$	209,649	$	10,346	$	(200,342	)	$	44,625
Note receivable – Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		1,052,073		97,018		—		(1,149,091	)		—
Net property, plant and equipment		165		1,572,383		181,214		—			1,753,762
Other long-term assets		2,361		202,346		—		—			204,707
Total assets	$	1,339,571	$	2,081,396	$	191,560	$	(1,349,433	)	$	2,263,094
Current liabilities	$	201,989	$	47,946	$	2,127	$	(200,342	)	$	51,720
Long-term debt		474,000		—		—		—			474,000
Deferred income taxes		—		126,846		—		—			126,846
Asset retirement obligations and other		38		46,507		1,954		—			48,499
Total liabilities		676,027		221,299		4,081		(200,342	)		701,065
Partners’ capital		663,544		1,769,635		187,479		(1,149,091	)		1,471,567
Noncontrolling interests		—		90,462		—		—			90,462
Total liabilities, equity and partners’ capital	$	1,339,571	$	2,081,396	$	191,560	$	(1,349,433	)	$	2,263,094

36

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

	Statement of Cash Flows Year Ended December 31, 2011
thousands	Western Gas Partners, LP			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations			Consolidated
Net income	$	140,160		$	253,432		$	28,781		$	(234,027	)	$	188,346
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income		(219,349	)		(14,678	)		—			234,027			—
Depreciation, amortization and impairments		55			106,230			5,619			—			111,904
Change in other items, net		(93,715	)		118,719			1,917			—			26,921
Net cash provided by
(used in) operating activities		(172,849	)		463,703			36,317			—			327,171
Net cash used in investing activities		(25,416	)		(409,715	)		(55,384	)		17,564			(472,951	)
Net cash provided by
(used in) financing activities		382,049			(53,988	)		34,768			(17,564	)		345,265
Net increase (decrease) in cash and cash equivalents		183,784			—			15,701			—			199,485
Cash and cash equivalents at beginning of period		21,479			—			5,595			—			27,074
Cash and cash equivalents at end of period	$	205,263		$	—		$	21,296		$	—		$	226,559
	Statement of Cash Flows Year Ended December 31, 2010
thousands	Western Gas Partners, LP			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations			Consolidated
Net income	$	113,917		$	171,888		$	22,459		$	(151,067	)	$	157,197
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income		(139,613	)		(11,454	)		—			151,067			—
Depreciation, amortization and impairments		54			85,199			5,757			—			91,010
Change in other items, net		149,408			(130,554	)		(3,312	)		—			15,542
Net cash provided by operating activities		123,766			115,079			24,904			—			263,749
Net cash used in investing activities		(734,780	)		(147,924	)		(2,803	)		—			(885,507	)
Net cash provided by
(used in) financing activities		570,863			32,845			(24,860	)		—			578,848
Net increase (decrease) in cash and cash equivalents		(40,151	)		—			(2,759	)		—			(42,910	)
Cash and cash equivalents at beginning of period		61,630			—			8,354			—			69,984
Cash and cash equivalents at end of period	$	21,479		$	—		$	5,595		$	—		$	27,074

37

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

	Statement of Cash Flows Year Ended December 31, 2009
thousands	Western Gas Partners, LP			Subsidiary Guarantors			Non- Guarantor Subsidiary			Eliminations			Consolidated
Net income	$	71,408		$	117,694		$	20,939		$	(83,546	)	$	126,495
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income		(78,408	)		(5,138	)		—			83,546			—
Depreciation, amortization and impairments		54			86,134			4,504			—			90,692
Change in other items, net		2,112			(3,946	)		(15,081	)		12,493			(4,422	)
Net cash provided by
(used in) operating activities		(4,834	)		194,744			10,362			12,493			212,765
Net cash used in investing activities		—			(183,750	)		(39,378	)		—			(223,128	)
Net cash provided by
(used in) financing activities		33,157			(10,994	)		34,603			(12,493	)		44,273
Net increase (decrease) 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

38

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, 2011 and 2010. The Partnership’s operating results reflect the operations of the Partnership assets from the dates of common control, unless otherwise noted, and have been recast to include results attributable to the Bison and MGR assets, as applicable. See Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

thousands except per-unit amounts	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2011
Revenues	$	180,842	$	209,680	$	217,546	$	215,197
Operating income	$	50,972	$	58,181	$	53,946	$	46,094
Net income attributable to Western Gas Partners, LP	$	43,897	$	45,026	$	45,306	$	40,014
Net income per common unit – basic and diluted (1)	$	0.43	$	0.40	$	0.41	$	0.35
Net income per subordinated unit – basic and diluted (1)	$	0.41	$	0.38	$	—	$	—
2010
Revenues	$	171,195	$	165,915	$	163,139	$	163,025
Operating income	$	42,729	$	44,394	$	41,335	$	49,530
Net income attributable to Western Gas Partners, LP	$	34,447	$	33,890	$	36,189	$	41,666
Net income per common unit – basic and diluted (1)	$	0.37	$	0.35	$	0.44	$	0.48
Net income per subordinated unit – basic and diluted (1)	$	0.37	$	0.35	$	0.44	$	0.44

⁽¹⁾  Represents net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). In addition, all subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4. Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

39

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Acquisitions - Acquisitions Table (details) (USD $)	12 Months Ended																1 Months Ended								1 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009		Dec. 31, 2011 Affiliated Entity Member		Dec. 31, 2010 Affiliated Entity Member		Dec. 31, 2009 Affiliated Entity Member		Dec. 31, 2011 Third Parties [Member]		Dec. 31, 2010 Third Parties [Member]		Jul. 31, 2009 Chipeta [Member]		Jul. 31, 2009 Chipeta [Member] Third Parties [Member]		Jul. 31, 2009 Chipeta [Member] Noncontrolling Interests		Jul. 31, 2009 Chipeta [Member] Processing Trains [Member]		Jan. 31, 2010 Granger [Member]		Aug. 31, 2010 Wattenberg [Member]		Sep. 30, 2010 White Cliffs [Member]		Sep. 30, 2010 White Cliffs [Member] Affiliated Entity Member		Sep. 30, 2010 White Cliffs [Member] Third Parties [Member]		Feb. 28, 2011 Platte Valley [Member]		Jul. 31, 2011 Bison [Member]		Jul. 31, 2011 Bison [Member] Amine Treating Unit [Member]
Business Acquisition Line Items
Acquisition date																	07/01/09	[1]							01/29/10	[2]	08/02/10	[3]	09/28/10	[4]					02/28/11	[5]	07/08/11	[6]
Percentage acquired																	51.00%	[1]							100.00%	[2]	100.00%	[3]	10.00%	[4]	0.40%	[4]	9.60%	[4]	100.00%	[5]	100.00%	[6]
Borrowings	$ 1,055,939,000	[7]	$ 660,000,000	[7]	$ 101,451,000	[7]											$ 101,451,000	[1]							$ 210,000,000	[2]	$ 450,000,000	[3]							$ 303,000,000	[5]
Cash on hand							28,837,000	[7]	734,780,000	[7]	101,451,000	[7]	301,957,000	[7]	18,047,000	[7]	4,638,000	[1]							31,680,000	[2]	23,100,000	[3]	38,047,000	[4]					602,000	[5]	25,000,000	[6]
Common units issued																	351,424	[1]							620,689	[2]	1,048,196	[3]									2,950,284	[6]
GP units issued																	7,172	[1]							12,667	[2]	21,392	[3]									60,210	[6]
Table Text Block Supplement Abstract
Assets, number of units																							2	[1]															3	[6]
Cash paid for compressor station and processing plant																			9,100,000	[1]
Contribution from noncontrolling interest owners																					$ 4,500,000	[1]

[1] The assets acquired from Anadarko include a 51% membership interest in Chipeta, together with an associated NGL pipeline. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. Chipeta owns a natural gas processing plant with two processing trains: a refrigeration unit and a cryogenic unit. In addition, in November 2009, Chipeta acquired the Natural Buttes plant including a compressor station and processing plant from a third party for $9.1 million, of which $4.5 million was contributed by the noncontrolling interest owners to fund their proportionate share. 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.”

[2] The assets acquired from Anadarko include (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of cryogenic trains, a refrigeration train, an NGLs fractionation facility and ancillary equipment. These assets, located in southwestern Wyoming, are referred to collectively as the “Granger assets” and the acquisition as the “Granger acquisition.”

[3] The assets acquired from Anadarko include the Wattenberg gathering system and related facilities, including the Fort Lupton processing plant. These assets, located in the Denver-Julesburg Basin, north and east of Denver, Colorado, are referred to collectively as the “Wattenberg assets” and the acquisition as the “Wattenberg acquisition.”

[4] White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma, which became operational in June 2009. The Partnership’s acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko combined with the acquisition of an additional 9.6% interest in White Cliffs from a third party, are referred to collectively as the “White Cliffs acquisition.” The Partnership’s interest in White Cliffs is referred to as the “White Cliffs investment.”

[5] The assets acquired from a third party include (i) a natural gas gathering system and related compression and other ancillary equipment, and (ii) cryogenic gas processing facilities. These assets, located in the Denver-Julesburg Basin, are referred to collectively as the “Platte Valley assets” and the acquisition as the “Platte Valley acquisition.” See further information below, including the final allocation of the purchase price in August 2011.

[6] The Bison gas treating facility acquired from Anadarko is located in the Powder River Basin in northeastern Wyoming, and includes (i) three amine treating units, (ii) compressor units, and (iii) generators. These assets are referred to collectively as the “Bison assets” and the acquisition as the “Bison acquisition.” The Bison assets are the only treating and delivery point into the third-party-owned Bison pipeline. Anadarko began construction of the Bison assets in 2009 and placed them in service in June 2010. See further information below.

[7] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

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Transactions With Affiliates - Additional Information (details) (USD $)					12 Months Ended						1 Months Ended			12 Months Ended																1 Months Ended				12 Months Ended	1 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2011 Gathering Transportation And Treating [Member]	Dec. 31, 2010 Gathering Transportation And Treating [Member]	Dec. 31, 2009 Gathering Transportation And Treating [Member]	Dec. 31, 2011 Processing [Member]	Dec. 31, 2010 Processing [Member]	Dec. 31, 2009 Processing [Member]	May 31, 2008 Note Receivable From Anadarko [Member]	Dec. 31, 2011 Note Receivable From Anadarko [Member]	Dec. 31, 2010 Note Receivable From Anadarko [Member]	Dec. 31, 2011 Omnibus Agreement [Member]	Dec. 31, 2011 Omnibus Agreement [Member] Public Company Expenses [Member]	Dec. 31, 2010 Omnibus Agreement [Member] Public Company Expenses [Member]	Dec. 31, 2009 Omnibus Agreement [Member] Public Company Expenses [Member]	Dec. 31, 2010 Omnibus Agreement [Member] Cap	Dec. 31, 2009 Omnibus Agreement [Member] Cap	Dec. 31, 2011 Omnibus Agreement [Member] No Cap	Dec. 31, 2011 Long Term Incentive Plan [Member] Years	Dec. 31, 2010 Long Term Incentive Plan [Member]	Dec. 31, 2009 Long Term Incentive Plan [Member]	Dec. 31, 2011 Incentive Plan And Or Anadarko Incentive Plans [Member]	Dec. 31, 2010 Incentive Plan And Or Anadarko Incentive Plans [Member]	Dec. 31, 2009 Incentive Plan And Or Anadarko Incentive Plans [Member]	Dec. 31, 2011 Incentive Plan [Member] Years	Dec. 31, 2011 Anadarko Incentive Plan [Member] Years	Dec. 31, 2011 Anadarko Incentive Plan [Member] Performance Based Awards [Member] Years	Nov. 30, 2011 Purchased Equipment Including Compressors [Member]	Nov. 30, 2010 Purchased Equipment Including Compressors [Member]	Sep. 30, 2010 Sold Compressors [Member]	Dec. 31, 2011 Anadarko [Member] Long Term Incentive Plan [Member]	Dec. 31, 2011 Director [Member] Long Term Incentive Plan [Member]	Dec. 31, 2011 Mountain Gas Resources [Member] Gathering And Processing [Member]
Related Party Transaction Line Items
Note receivable - Anadarko	$ 260,000,000	[1]	$ 260,000,000	[1]							$ 260,000,000
Term of instrument in years											30 years																								10 years
Fixed annual rate for note receivable bearing interest											6.50%
The fair value of the note receivable												303,700,000	258,900,000
Affiliate throughput percent					75.00%	73.00%	76.00%	64.00%	66.00%	58.00%
Allocated costs from Parent														19,500,000	7,700,000	8,000,000	7,500,000	9,000,000	6,900,000	11,800,000
Phantom units vesting term, minimum																																		1
Phantom units vesting term, maximum																					3
Equity based compensation expense																					300,000	300,000	400,000	13,900,000	5,400,000	4,100,000
Unvested equity based compensation																					500,000						5,500,000	3,700,000	100,000				600,000
Weighted average term of unvested awards																					2.3						1.4	2	3
Carrying value of equipment	2,052,224,000	[1]	1,753,762,000	[1]																										2,000,000	400,000	2,600,000
Cash received for idle compressors																																2,800,000
Cash paid for equipment																														$ 3,800,000	$ 400,000

[1] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

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Equity and Partners' Capital - Calculation of Net Income Per Unit Table (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Earnings Per Unit [Line Items]
Net income attributable to Western Gas Partners, LP	$ 174,243	[1]	$ 146,192	[1]	$ 116,235	[1]
Pre-acquisition net (income) loss allocated to Parent	(34,084)	[1]	(32,061)	[1]	(44,827)	[1]
General partner interest in net (income) loss	(8,599)	[1],[2]	(3,067)	[1],[2]	(1,428)	[1],[2]
Limited partners' interest in net income	131,560	[1],[2]	111,064	[1],[2]	69,980	[1],[2]
Common Units
Earnings Per Unit [Line Items]
Limited partners' interest in net income	110,542		68,410		37,035
Common Units | Limited Partners Member
Net income per unit - basic and diluted
Net income per unit - basic and diluted	$ 1.64	[1]	$ 1.66	[1]	$ 1.25	[1]
Weighted average units outstanding - basic and diluted
Weighted average units outstanding - basic and diluted	67,333		41,287		29,684
Subordinated Units
Earnings Per Unit [Line Items]
Limited partners' interest in net income	$ 21,018		$ 42,654		$ 32,945
Subordinated Units | Limited Partners Member
Net income per unit - basic and diluted
Net income per unit - basic and diluted	$ 1.28	[1],[3]	$ 1.61	[1],[3]	$ 1.24	[1],[3]
Weighted average units outstanding - basic and diluted
Weighted average units outstanding - basic and diluted	16,431		26,536		26,536

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Represents net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 1). See also Note 4.

[3] All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4.

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Subsequent Event - Commodity Price Per Unit Table (details) (Mountain Gas Resources [Member])	Dec. 31, 2011
Ethane [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	26.87
Ethane [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	25.34
Ethane [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	24.10
Ethane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	23.41
Ethane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	23.11
Propane [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	57.97
Propane [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	55.59
Propane [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.78
Propane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.99
Propane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.90
Isobutane [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	80.98
Isobutane [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	77.66
Isobutane [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	75.13
Isobutane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	74.02
Isobutane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	73.89
Normal Butane [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	71.15
Normal Butane [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	68.24
Normal Butane [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	66.01
Normal Butane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	65.04
Normal Butane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	64.93
Natural Gasoline [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	89.51
Natural Gasoline [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	85.84
Natural Gasoline [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	83.04
Natural Gasoline [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.82
Natural Gasoline [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.68
Natural gas (per MMbtu) [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	3.62
Natural gas (per MMbtu) [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.17
Natural gas (per MMbtu) [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.45
Natural gas (per MMbtu) [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.66
Natural gas (per MMbtu) [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.87
Condensate [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	89.51
Condensate [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	85.84
Condensate [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	83.04
Condensate [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.82
Condensate [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.68

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Income Taxes - Components of Income Tax Expense Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Current Income Tax Expense (Benefit) [Abstract]
Federal income tax expense (benefit)	$ 15,890		$ 10,580		$ 20,253
State income tax expense	524		1,534		1,856
Total current income tax expense (benefit)	16,414		12,114		22,109
Deferred Income Tax Expense (Benefit) [Abstract]
Federal income tax expense (benefit)	2,464		9,709		696
State income tax expense (benefit)	140		(121)		(646)
Total deferred income tax expense (benefit)	2,604	[1]	9,588	[1]	50	[1]
Total income tax expense	$ 19,018	[1]	$ 21,702	[1]	$ 22,159	[1]

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

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Partnership Distributions - Additional Information (details)	0 Months Ended	12 Months Ended
	May 14, 2008	Dec. 31, 2011
Distributions Made to Members or Limited Partners [Abstract]
Partnership agreement day requirement of distribution of available cash	45 days
General partner's interest		2.00%

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Debt and Interest Expense (tables)

12 Months Ended

Dec. 31, 2011

Debt Instruments Abstract

Debt Outstanding Table

	December 31, 2011						December 31, 2010
			Carrying		Fair				Carrying		Fair
thousands	Principal		Value		Value		Principal		Value		Value
Revolving credit facility	$	—	$	—	$	—	$	49,000	$	49,000	$	49,000
5.375% Senior Notes due 2021		500,000		494,178		499,950		—		—		—
Wattenberg term loan		—		—		—		250,000		250,000		250,000
Note payable to Anadarko		175,000		175,000		174,528		175,000		175,000		168,116
Total debt outstanding (1)	$	675,000	$	669,178	$	674,478	$	474,000	$	474,000	$	467,116

_________________________________________________

(1)The Partnership's consolidated balance sheets include accrued interest expense of $2.7million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

Debt Activity Table

thousands		Carrying Value
Balance as of December 31, 2009		$	175,000
	Revolving credit facility borrowings		410,000
	Repayment of revolving credit facility		(361,000)
	Revolving credit facility borrowings – Swingline		10,000
	Repayment of revolving credit facility – Swingline		(10,000)
	Issuance of Wattenberg term loan		250,000
Balance as of December 31, 2010		$	474,000
	Revolving credit facility borrowings		570,000
	Repayment of revolving credit facility		(619,000)
	Repayment of Wattenberg term loan		(250,000)
	Revolving credit facility borrowings – Swingline		30,000
	Repayment of revolving credit facility – Swingline		(30,000)
	Issuance of 5.375% Senior Notes due 2021		500,000
	Other and changes in debt discount		(5,822)
Balance as of December 31, 2011		$	669,178

Interest Expense Table

			Year Ended December 31,
thousands			2011		2010		2009
Third Parties
	Interest expense on long-term debt		$	20,533	$	8,530	$	304
	Amortization of debt issuance costs and commitment fees (1)			5,297		3,340		555
	Capitalized interest			(420)		—		—
		Total interest expense – third parties		25,410		11,870		859
Affiliates
	Interest expense on notes payable to Anadarko			4,935		6,828		8,953
	Credit facility commitment fees			—		96		143
		Total interest expense – affiliates		4,935		6,924		9,096
Interest expense			$	30,345	$	18,794	$	9,955

_____________________________________________________________

(1)For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters' fees related to the Notes.

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Condensed Consolidating Financial Statements - Statement of Cash Flows (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Cash flows from operating activities
Net income	$ 188,346	[1]	$ 157,197	[1]	$ 126,495	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	111,904	[1]	91,010	[1]	90,692	[1]
Change in other items, net	26,921		15,542		(4,422)
Net cash provided by (used in) operating activities	327,171	[1]	263,749	[1]	212,765	[1]
Net cash used in investing activities	(472,951)	[1]	(885,507)	[1]	(223,128)	[1]
Net cash provided by (used in) financing activities	345,265	[1]	578,848	[1]	44,273	[1]
Net increase (decrease) in cash and cash equivalents	199,485	[1]	(42,910)	[1]	33,910	[1]
Cash and cash equivalents at beginning of period	27,074	[1],[2]	69,984	[1]	36,074	[1]
Cash and cash equivalents at end of period	226,559	[1],[2]	27,074	[1],[2]	69,984	[1]
Western Gas Partners, LP
Cash flows from operating activities
Net income	140,160		113,917		71,408
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income	(219,349)		(139,613)		(78,408)
Depreciation, amortization and impairments	55		54		54
Change in other items, net	(93,715)		149,408		2,112
Net cash provided by (used in) operating activities	(172,849)		123,766		(4,834)
Net cash used in investing activities	(25,416)		(734,780)
Net cash provided by (used in) financing activities	382,049		570,863		33,157
Net increase (decrease) in cash and cash equivalents	183,784		(40,151)		28,323
Cash and cash equivalents at beginning of period	21,479		61,630		33,307
Cash and cash equivalents at end of period	205,263		21,479		61,630
Subsidiary Guarantors
Cash flows from operating activities
Net income	253,432		171,888		117,694
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income	(14,678)		(11,454)		(5,138)
Depreciation, amortization and impairments	106,230		85,199		86,134
Change in other items, net	118,719		(130,554)		(3,946)
Net cash provided by (used in) operating activities	463,703		115,079		194,744
Net cash used in investing activities	(409,715)		(147,924)		(183,750)
Net cash provided by (used in) financing activities	(53,988)		32,845		(10,994)
Non-Guarantor Subsidiary
Cash flows from operating activities
Net income	28,781		22,459		20,939
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	5,619		5,757		4,504
Change in other items, net	1,917		(3,312)		(15,081)
Net cash provided by (used in) operating activities	36,317		24,904		10,362
Net cash used in investing activities	(55,384)		(2,803)		(39,378)
Net cash provided by (used in) financing activities	34,768		(24,860)		34,603
Net increase (decrease) in cash and cash equivalents	15,701		(2,759)		5,587
Cash and cash equivalents at beginning of period	5,595		8,354		2,767
Cash and cash equivalents at end of period	21,296		5,595		8,354
Eliminations
Cash flows from operating activities
Net income	(234,027)		(151,067)		(83,546)
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income	234,027		151,067		83,546
Change in other items, net					12,493
Net cash provided by (used in) operating activities					12,493
Net cash used in investing activities	17,564
Net cash provided by (used in) financing activities	$ (17,564)				$ (12,493)

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

XML

Income Taxes - Deferred Tax Assets and Liabilities Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Income Tax Expense (Benefit) [Abstract]
Credit carryforwards	$ 14		$ 14
Other			2
Net current deferred income tax assets	14		16
Depreciable property	(83,566)		(100,889)
Partnership basis	(24,481)		(26,320)
Credit carryforwards	556		570
Other	114		(207)
Net long-term deferred income tax liabilities	(107,377)	[1]	(126,846)	[1]
Total net deferred income tax liabilities	$ (107,363)		$ (126,830)

[1] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

XML

Condensed Consolidating Financial Statements - Statement of Income (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Condensed Financial Statements Captions Line Items
Revenues	$ 823,265	[1]	$ 663,274	[1]	$ 619,764	[1]
Operating expenses	614,072	[1]	485,286	[1]	483,500	[1]
Operating income (loss)	209,193	[1]	177,988	[1]	136,264	[1]
Interest income - affiliates	28,560	[1],[2]	20,243	[1],[2]	20,717	[1],[2]
Interest expense	(30,345)	[1],[3]	(18,794)	[1],[3]	(9,955)	[1],[3]
Other income (expense), net	(44)	[1]	(538)	[1]	1,628	[1]
Income before income taxes	207,364	[1]	178,899	[1]	148,654	[1]
Income tax expense	19,018	[1]	21,702	[1]	22,159	[1]
Net income	188,346	[1]	157,197	[1]	126,495	[1]
Net income attributable to noncontrolling interests	14,103	[1]	11,005	[1]	10,260	[1]
Net income attributable to Western Gas Partners, LP	174,243	[1]	146,192	[1]	116,235	[1]
Western Gas Partners, LP
Condensed Financial Statements Captions Line Items
Revenues	(2,957)		23,153		20,642
Operating expenses	61,009		44,593		34,602
Operating income (loss)	(63,966)		(21,440)		(13,960)
Interest income - affiliates	16,900		16,900		16,900
Interest expense	(30,378)		(18,825)		(9,972)
Other income (expense), net	(1,745)		(2,331)		32
Equity income	219,349		139,613		78,408
Income before income taxes	140,160		113,917		71,408
Net income	140,160		113,917		71,408
Net income attributable to Western Gas Partners, LP	140,160		113,917		71,408
Subsidiary Guarantors
Condensed Financial Statements Captions Line Items
Revenues	756,764		596,033		557,115
Operating expenses	512,374		419,058		427,820
Operating income (loss)	244,390		176,975		129,295
Interest income - affiliates	11,693		3,374		3,834
Interest expense	0
Other income (expense), net	1,689		1,787		1,586
Equity income	14,678		11,454		5,138
Income before income taxes	272,450		193,590		139,853
Income tax expense	19,018		21,702		22,159
Net income	253,432		171,888		117,694
Net income attributable to noncontrolling interests	14,103		11,005		10,260
Net income attributable to Western Gas Partners, LP	239,329		160,883		107,434
Non-Guarantor Subsidiary
Condensed Financial Statements Captions Line Items
Revenues	69,458		44,088		42,007
Operating expenses	40,689		21,635		21,078
Operating income (loss)	28,769		22,453		20,929
Other income (expense), net	12		6		10
Income before income taxes	28,781		22,459		20,939
Net income	28,781		22,459		20,939
Net income attributable to Western Gas Partners, LP	28,781		22,459		20,939
Eliminations
Condensed Financial Statements Captions Line Items
Interest income - affiliates	(33)		(31)		(17)
Interest expense	33		31		17
Equity income	(234,027)		(151,067)		(83,546)
Income before income taxes	(234,027)		(151,067)		(83,546)
Net income	(234,027)		(151,067)		(83,546)
Net income attributable to Western Gas Partners, LP	$ (234,027)		$ (151,067)		$ (83,546)

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Represents interest income recognized on the note receivable from Anadarko. This line item also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

[3] Includes affiliate (as defined in Note 1) interest expense of $4.9 million, $6.9 million and $9.1 million for years ended December 31, 2011, 2010 and 2009, respectively. See Note 10.

XML

Acquisitions (tables)

12 Months Ended

Dec. 31, 2011

Business Combinations [Abstract]

Acquisitions Table

thousands except unit and		Acquisition	Percentage			Cash		Common	GP Units
	percent amounts	Date	Acquired	Borrowings		On Hand		Units Issued	Issued
Chipeta (1)		07/01/09	51%	$	101,451	$	4,638	351,424	7,172
Granger (2)		01/29/10	100%		210,000		31,680	620,689	12,667
Wattenberg (3)		08/02/10	100%		450,000		23,100	1,048,196	21,392
White Cliffs (4)		09/28/10	10%		—		38,047	—	—
Platte Valley (5)		02/28/11	100%		303,000		602	—	—
Bison (6)		07/08/11	100%		—		25,000	2,950,284	60,210

_______________________________________________________

(1)The assets acquired from Anadarko include a 51% membership interest in Chipeta, together with an associated NGL pipeline. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. Chipeta owns a natural gas processing plant with two processing trains: a refrigeration unit and a cryogenic unit. In addition, in November 2009, Chipeta acquired the Natural Buttes plant including a compressor station and processing plant from a third party for $9.1 million, of which $4.5 million was contributed by the noncontrolling interest owners to fund their proportionate share. 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.”

(2)The assets acquired from Anadarkoinclude (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of cryogenic trains, a refrigeration train, an NGLs fractionation facility and ancillary equipment. These assets, located in southwestern Wyoming, are referred to collectively as the “Granger assets”and the acquisition as the “Granger acquisition.”

(3)The assets acquired from Anadarko include the Wattenberg gathering system and related facilities, including the Fort Lupton processing plant. These assets, located in the Denver-JulesburgBasin, north and east of Denver, Colorado, are referred to collectively as the “Wattenberg assets”and the acquisition as the “Wattenberg acquisition.”

(4)White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma, whichbecame operational in June 2009. The Partnership's acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko combined with the acquisition of an additional 9.6% interest in White Cliffs from a third party, are referred to collectively as the “White Cliffs acquisition.” The Partnership's interest in White Cliffs is referred to as the “White Cliffs investment.”

(5)The assets acquired from a third partyinclude (i) a natural gas gathering system and related compression and other ancillary equipment, and (ii) cryogenic gas processing facilities. These assets, located in the Denver-Julesburg Basin, are referred to collectively as the “Platte Valley assets”and the acquisition as the “Platte Valley acquisition.” See further information below, including the final allocation of the purchase price in August 2011.

(6)The Bison gas treating facility acquired from Anadarko is located in the Powder River Basin in northeastern Wyoming, and includes (i) three amine treating units, (ii) compressor units, and (iii) generators.These assets are referred to collectively as the “Bison assets” and the acquisition as the “Bison acquisition.”The Bison assets are the only treating and delivery point into the third-party-owned Bison pipeline. Anadarko began construction of the Bison assets in 2009 and placed them in service in June 2010. See further information below.

Purchase Price Allocation Table

thousands
Property, plant and equipment	$	264,521
Intangible assets		53,754
Asset retirement obligations and other liabilities		(16,318)
Total purchase price	$	301,957

Pro Forma Condensed Financial Information Table

	Year Ended
thousands except per-unit amount	December 31, 2011
Revenues	$	839,304
Net income		191,072
Net income attributable to Western Gas Partners, LP		176,969
Net income per common unit – basic and diluted	$	1.67

Adjustment to Prior Year Income Table

	Year Ended December 31, 2010
	Partnership		Bison		MGR
thousands	Historical		Assets		Assets		Eliminations		Combined
Revenues	$	503,322	$	1,879	$	158,135	$	(62)	$	663,274
Net income (loss)		137,073		(3,194)		23,318		—		157,197
	Year Ended December 31, 2009
	Partnership		Bison		MGR
thousands	Historical		Assets		Assets		Eliminations		Combined
Revenues	$	490,546	$	—	$	129,218	$	—	$	619,764
Net income (loss)		118,166		(657)		8,986		—		126,495

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Transactions With Affiliates - Commodity Price Per Unit Table (details)	Dec. 31, 2011
Ethane [Member] | Minimum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	18.21
Ethane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	18.32
Ethane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	18.36
Ethane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	18.41
Ethane [Member] | Maximum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	29.78
Ethane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	30.10
Ethane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	30.53
Propane [Member] | Minimum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	45.23
Propane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	45.90
Propane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	46.47
Propane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	47.08
Propane [Member] | Maximum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.28
Propane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	55.84
Propane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.37
Isobutane [Member] | Minimum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	57.50
Isobutane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	60.44
Isobutane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	61.24
Isobutane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	62.09
Isobutane [Member] | Maximum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	67.22
Isobutane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	68.11
Isobutane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	69.23
Normal Butane [Member] | Minimum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.40
Normal Butane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.20
Normal Butane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.89
Normal Butane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	54.62
Normal Butane [Member] | Maximum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	62.92
Normal Butane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	66.37
Normal Butane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	64.78
Natural Gasoline [Member] | Minimum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	69.77
Natural Gasoline [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	70.89
Natural Gasoline [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	71.85
Natural Gasoline [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	72.88
Natural Gasoline [Member] | Maximum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	85.15
Natural Gasoline [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	92.23
Natural Gasoline [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	79.74
Natural gas (per MMbtu) [Member] | Minimum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.15
Natural gas (per MMbtu) [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	3.75
Natural gas (per MMbtu) [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	5.32
Natural gas (per MMbtu) [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	5.50
Natural gas (per MMbtu) [Member] | Maximum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	5.97
Natural gas (per MMbtu) [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	6.09
Natural gas (per MMbtu) [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	6.20
Natural gas (per MMbtu) [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	5.96
Condensate [Member] | Minimum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	72.73
Condensate [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	74.04
Condensate [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	75.22
Condensate [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	76.47
Condensate [Member] | Maximum [Member] | Year 2012 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	78.52
Condensate [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	83.93
Condensate [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	79.56
Condensate [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	78.61

XML

Acquisitions - Impact to Historical Consolidated Statements of Income (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Prior Period Adjustments [Line Items]
Revenues	$ 823,265	[1]	$ 663,274	[1]	$ 619,764	[1]
Net income	188,346	[1]	157,197	[1]	126,495	[1]
Partnership Historical
Prior Period Adjustments [Line Items]
Revenues			503,322		490,546
Net income			137,073		118,166
Bison Assets
Prior Period Adjustments [Line Items]
Revenues			1,879
Net income			(3,194)		(657)
MGR Assets
Prior Period Adjustments [Line Items]
Revenues			158,135		129,218
Net income			23,318		8,986
Eliminations
Prior Period Adjustments [Line Items]
Revenues			$ (62)

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

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Summary of Significant Accounting Policies - Equity Method Investments Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Equity-method investments
Balance	$ 114,462	[1]
Contributions	93	[2]	310	[2]	382	[2]
Balance	109,817	[1]	114,462	[1]
Third Parties [Member]
Equity-method investments
Acquisition of additional 9.6% interest from third party	301,957	[2]	18,047	[2]
Fort Union [Member]
Equity-method investments
Balance	21,428	[3]	20,060	[3]
Investment earnings, net of amortization	6,067	[3]	5,723	[3]
Contributions			310	[3]
Distributions	(5,227)	[3]	(4,665)	[3]
Balance	22,268	[3]	21,428	[3]
Table Text Block Supplement Abstract
Ownership interest	14.81%	[3]
Approval Percentage	65.00%	[3]
White Cliffs [Member]
Equity-method investments
Balance	18,978	[4]	1,284	[4]
Investment earnings, net of amortization	4,023	[4]	917	[4]
Contributions	93	[4]
Distributions	(5,384)	[4]	(1,270)	[4]
Balance	17,710	[4]	18,978	[4]
Table Text Block Supplement Abstract
Ownership interest	10.00%	[4]
Approval Percentage	75.00%	[4]
White Cliffs [Member] | Third Parties [Member]
Equity-method investments
Acquisition of additional 9.6% interest from third party			18,047	[4]
Table Text Block Supplement Abstract
Ownership interest	9.60%	[4]
Rendezvous [Member]
Equity-method investments
Balance	74,056	[5]	78,216	[5]
Investment earnings, net of amortization	1,171	[5]	988	[5]
Distributions	(5,388)	[5]	(5,038)	[5]
Other			(110)	[5]
Balance	$ 69,839	[5]	$ 74,056	[5]
Table Text Block Supplement Abstract
Ownership interest	22.00%	[5]

[1] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[3] The Partnership has a 14.81% interest in Fort Union, a joint venture which 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. 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. Each of the joint venture members has pledged its respective equity interest to the administrative agent of Fort Union’s credit agreement.

[4] The Partnership has a 10% interest in White Cliffs, a limited liability company which owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma and became operational in June 2009. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.

[5] The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in southwestern Wyoming. 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 members’ gas servicing agreements, require unanimous approval of the members.

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Transactions With Affiliates - LTIP Award Activity Table (details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Phantom units outstanding at beginning of year	17,503	21,970	30,304
Vested	(15,119)	(19,751)	(30,304)
Granted	21,594	15,284	21,970
Phantom units outstanding at end of year	23,978	17,503	21,970
Value per Unit of Phantom Units Outstanding	$ 33.92	$ 20.19	$ 15.02	$ 16.50
Value per Unit of Phantom Units Vested during the Period	$ 20.51	$ 15.02	$ 16.50
Value per Unit of Phantom Units Granted during the Period	$ 35.66	$ 20.94	$ 15.02

XML

Debt and Interest Expense - Additional Information (details) (USD $)					1 Months Ended		12 Months Ended			1 Months Ended	12 Months Ended				1 Months Ended		1 Months Ended			1 Months Ended					1 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		May 31, 2011 5.375% Senior Notes due 2021	Dec. 31, 2011 5.375% Senior Notes due 2021	Dec. 31, 2008 Note Payable To Anadarko [Member]	Dec. 31, 2011 Note Payable To Anadarko [Member]	Dec. 31, 2010 Note Payable To Anadarko [Member]	Mar. 31, 2011 Revolving Credit Facility [Member]	Dec. 31, 2011 Revolving Credit Facility [Member]	Dec. 31, 2010 Revolving Credit Facility [Member]	Oct. 31, 2009 Revolving Credit Facility [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Alternate Base Rate [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Maximum [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Maximum [Member] Alternate Base Rate [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Minimum [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Minimum [Member] Alternate Base Rate [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Percentage Above Federal Funds Effective Rate [Member] Alternate Base Rate [Member]	Mar. 31, 2011 Three Year Wattenberg Term Loan	Aug. 31, 2010 Three Year Wattenberg Term Loan	Dec. 31, 2010 Three Year Wattenberg Term Loan	Aug. 31, 2010 Three Year Wattenberg Term Loan Maximum [Member]	Aug. 31, 2010 Three Year Wattenberg Term Loan Minimum [Member]	May 31, 2011 Interest Rate Swap [Member]
Debt Instrument Line Items
Fixed interest rate					5.375%		4.00%		2.82%
Principal	$ 675,000,000	[1]	$ 474,000,000	[1]	$ 500,000,000	$ 500,000,000	$ 175,000,000	$ 175,000,000	$ 175,000,000			$ 49,000,000									$ 250,000,000	$ 250,000,000
Offering Percent					98.778%
Effective interest rate					5.648%
Underwriting discount					3,300,000
Description of debt instrument					In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “Notes”) at a price to the public of 98.778% of the face amount of the Notes. Including the effects of the underwriting discount and debt issuance costs, the effective interest rate is 5.648%. Interest on the Notes is paid semi-annually on June 1 and December 1 of each year, with payments commencing on December 1, 2011. Proceeds from the offering of the Notes (net of the underwriting discount of $3.3 million and debt issuance costs) were used to repay the then-outstanding balance on the Partnership’s revolving credit facility, with the remainder used for general partnership purposes. The Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the Notes in whole or in part, at any time before March 1, 2021, at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such Notes (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined in the indenture governing the Notes) plus 40 basis points, plus, in either case, accrued and unpaid interest, if any, on the principal amount being redeemed to such redemption date. On or after March 1, 2021, the Notes will be redeemable and repayable, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the Notes to be redeemed, plus accrued interest on the Notes to be redeemed to the date of redemption.
Covenants					The Notes indenture contains customary events of default including, among others, (i) default in any payment of interest on any debt securities when due that continues for 30 days; (ii) default in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii) certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing the Notes also contains covenants that limit, among other things, the ability of the Partnership and the Subsidiary Guarantors to (i) create liens on their principal properties; (ii) engage in sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease or transfer substantially all of their properties or assets to another entity.
Term of instrument in years					10 years		5 years			5 years											3 years
The provisions of the agreement							The provisions of the five-year term loan agreement contain customary events of default, including (i) non-payment of principal when due or non-payment of interest or other amounts within three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to the Partnership and (iii) a change of control.
Revolving Credit Facility, current maximum borrowing capacity										800,000,000			450,000,000
Revolving Credit Facility, additional borrowings										250,000,000
Revolving Credit Facility, remaining borrowing capacity											800,000,000
Interest rate percent above LIBOR														1.00%	1.90%	0.90%	1.30%	0.30%	0.50%				3.50%	2.50%
Revolving Credit Facility, interest rate at period end											1.80%	3.26%
Facility fee											0.25%	0.50%			0.35%		0.20%
Revolving Credit Facility, outstanding borrowings											0
Revolving Credit Facility covenants										The RCF also contains various customary covenants, customary events of default and certain financial tests as of the end of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization (“Consolidated EBITDA”) for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio (which is defined as the ratio of Consolidated EBITDA for the most recent four consecutive fiscal quarters to consolidated interest expense for such period) of 2.0 to 1.0. All amounts due under the RCF are unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. The Partnership will no longer be required to comply with the minimum consolidated interest coverage ratio, as well as the subsidiary guarantees and certain of the aforementioned covenants, if the Partnership obtains two of the following three ratings: BBB- or better by Standard & Poor’s, Baa3 or better by Moody’s Investors Service, or BBB- or better by Fitch Ratings.
Accelerated amortization expense																				1,300,000
Realized loss on terminated swap agreement																									$ 1,900,000

[1] The Partnership’s consolidated balance sheets include accrued interest expense of $2.7 million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

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Other Intangible Assets - Amortization Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Acquired Finite Lived Intangible Assets Line Items
2012	$ 1,075
2013	1,075
2014	1,075
2015	1,075
2016	$ 1,075

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Equity and Partners' Capital - Equity Offerings Table (details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended	1 Months Ended
	Dec. 31, 2011	Sep. 30, 2011 Equity offering		Mar. 31, 2011 Equity offering		Nov. 30, 2010 Equity offering		May 31, 2010 Equity offering		Dec. 31, 2009 Equity offering		Sep. 30, 2011 Equity offering Underwriter Over-Allotment Option	Mar. 31, 2011 Equity offering Underwriter Over-Allotment Option	Nov. 30, 2010 Equity offering Underwriter Over-Allotment Option	May 31, 2010 Equity offering Underwriter Over-Allotment Option	Dec. 31, 2009 Equity offering Underwriter Over-Allotment Option
Equity Issuance Since Inception [Line Items]
Common units issued		5,750,000	[1]	3,852,813	[1]	8,415,000	[1]	4,558,700	[1],[2]	6,900,000	[1]	750,000	302,813	915,000	558,700	900,000
GP units issued		117,347	[3]	78,629	[3]	171,734	[3]	93,035	[2],[3]	140,817	[3]
Price per unit		$ 35.86		$ 35.15		$ 29.92		$ 22.25	[2]	$ 18.20
Underwriting discount and other offering expenses		$ 7,655		$ 5,621		$ 10,325		$ 4,427	[2]	$ 5,500
Net proceeds		$ 202,748		$ 132,569		$ 246,729		$ 99,074	[2]	$ 122,539
Table Text Block Supplement Abstract
General partner's interest	2.00%

[1] Includes the issuance of 900,000 common units, 558,700 common units, 915,000 common units, 302,813 common units and 750,000 common units pursuant to the exercise, in full or in part, of the underwriters’ over-allotment options granted in connection with the December 2009, May 2010, November 2010, March 2011 and September 2011 equity offerings, respectively.

[2] Refers collectively to the May 2010 equity offering issuance, and the June 2010 exercise of the underwriters’ over-allotment option.

[3] Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% interest.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

General. Western Gas Partners, LP (the “Partnership”), a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to own, operate, acquire and develop midstream energy assets, closed its initial public offering to become publicly traded in 2008. Including the effect of the acquisition of Mountain Gas Resources, LLC (“MGR”), the Partnership's assets includethirteengathering systems, seven natural gas treating facilities, tennatural gas processing facilities, two NGL pipelines, one interstate gas pipeline, one intrastate gas pipeline, and interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”), which are accounted for under the equity method.The Partnership's assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming), and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko Petroleum Corporation and its consolidated subsidiaries, as well as third-party producers and customers.

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

Basis of presentation. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”), and certain amounts in prior periods have been reclassified to conform to the current presentation. The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest, and all significant intercompany transactions have been eliminated. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system in the accompanying consolidated financial statements.

       In July 2009, the Partnership acquired a 51% interest in Chipeta ProcessingLLC (“Chipeta”) and became party to Chipeta's limited liability company agreement, as amended and restated (the “Chipeta LLC agreement”) (see Notes 2 and 3). As of December 31, 2011, 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 Partnership's consolidated financial statements for all periods presented.       

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of December 31, 2011. Because of Anadarko's control of the Partnership through its ownership of the general partner, each acquisition of Partnership assets, except for the acquisitions of the Platte Valley assets and the 9.6% interest in White Cliffs from third parties, was considered a transfer of net assets between entities under common control (see Note 2). As a result, after each acquisition of assets from Anadarko, the Partnership is required to recast its financial statements to include the activities of the Partnership assets as of the date of common control.

       The consolidated financial statements for periods prior to the Partnership's acquisition of the Partnership assets have been prepared from Anadarko's historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. Net income attributable to the Partnership assets for periods prior to the Partnership's acquisition of such assets is not allocated to the limited partners for purposes of calculating net income per common or subordinated unit.

Use of estimates.In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the amounts reported in the consolidated financial statements and the notes thereto. Management evaluates its estimates and related assumptions regularly, utilizing historical experience and other methods considered reasonable under the circumstances. Changes in facts and circumstancesor additional information, may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership's business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

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 certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations,and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership 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, the Partnership utilizes the cost, income, or market valuation approach depending on the quality of information available to support management's assumptions.

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 for identical instruments, if available, or average valuations of similar debt instruments at the balance sheet date. See Note 10.

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items.

Cash equivalents. The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Bad-debt reserve. The Partnership's 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. At December 31, 2011 and 2010, third-party accounts receivable are shown net of the associated bad-debt reserve of $17,000.

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 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, 2011, natural gas imbalance receivables and payables were approximately $2.3 million and $3.1 million, respectively. As of December 31, 2010, natural gas imbalance receivables and payables were approximately $0.4 million and $2.6 million, respectively. Changes in natural gas imbalances are reported in equity income and other, net or cost of product in the consolidated statements of income.

Inventory. The cost of NGLs inventories is determined by the weighted average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets.

Property, plant and equipment.Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the Partnership assets acquired by the Partnership from Anadarko are initially recorded at Anadarko's historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to Partners' capital.

Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. 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 that 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, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, 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 reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

The Partnership evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset's carrying amount over its estimated fair value, such that the asset's carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.

During the year ended December 31, 2011, an impairment of $7.3 million was recognized for certain equipment and materials. The costs of the equipment and materials, previously capitalized as assets under construction and related to a Red Desert complex (see Note 2) expansion project, were deemed no longer recoverable as the expansion project was indefinitely postponed by Anadarko management. Subsequent to the project evaluation and impairment, the remaining fair value of the equipment and materials, approximately $10.6 million, was reclassified from within property, plant and equipment to other assets on the consolidated balance sheet as of December 31, 2011. Also during 2011, following an evaluation of future cash flows, an impairment of $3.0 million was recognized for a transportation pipeline. This asset was impaired to fair value, estimated using Level 3 fair-value inputs.

During the year ended December 31, 2010, the Partnership recognized $0.6 million of impairment related to a compressor sold during the year to a third party, and $0.3 million of impairment due to cancelled capital projects and additional costs recorded on a project previously impaired to salvage value. During the year ended December 31, 2009, an impairment of $6.1 million was recognized for an idle pipeline for which no future cash flows were expected.

Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset.

Goodwill and other intangible assets.Goodwill represents the allocated portion of Anadarko's midstream goodwill attributed to the assets the Partnership has acquired from Anadarko. The carrying value of Anadarko's midstream goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership's goodwill balance does not reflect, and in some cases is significantly different than, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of the net assets on the acquisition date. The Partnership's consolidated balance sheets as of December 31, 2011 and 2010, include goodwill of$82.1 million, none of which is deductible for tax purposes.

The Partnership evaluates goodwill for impairment annually, as of October 1, or more often as facts and circumstances warrant. The first step in the goodwill impairment test is to compare the fair value of each reporting unit to which goodwill has been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. If the carrying amount of the reporting unit exceeds its fair value, step two in the goodwill impairment test requires goodwill to be written down to its implied fair value through a charge to operating expense based on a hypothetical purchase price allocation. No goodwill impairment has been recognized in these consolidated financial statements. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement.

The Partnership assesses intangible assets, as described inNote 8, for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset's carrying amount over its estimated fair value such that the asset's carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense. No intangible asset impairment has been recognized in connection with these assets.

Equity-method investments. The following table presents the activity in the Partnership's investments in equity of Fort Union, White Cliffs and Rendezvous:

		Equity Investments
thousands		Fort Union (1)		White Cliffs (2)		Rendezvous (3)
Balance at December 31, 2009		$	20,060	$	1,284	$	78,216
	Investment earnings, net of amortization		5,723		917		988
	Contributions		310		—		—
	Distributions		(4,665)		(1,270)		(5,038)
	Acquisition of additional 9.6% interest from third party		—		18,047		—
	Other		—		—		(110)
Balance at December 31, 2010		$	21,428	$	18,978	$	74,056
	Investment earnings, net of amortization		6,067		4,023		1,171
	Contributions		—		93		—
	Distributions		(5,227)		(5,384)		(5,388)
Balance at December 31, 2011		$	22,268	$	17,710	$	69,839

____________________________________________________________

(1)The Partnership has a 14.81% interest in Fort Union, a joint venture which 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. 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. Each of the joint venture members has pledged its respective equity interest to the administrative agent of Fort Union's credit agreement.

(2)The Partnership has a 10% interest in White Cliffs,a limited liability company which owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma and became operational in June 2009. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.

(3)       The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in southwestern Wyoming. 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 members' gas servicing agreements, require unanimous approval of the members.

The investment balance at December 31, 2011, includes $2.7 million and $47.9 million for the purchase price allocated to the investment in Fort Union and Rendezvous, respectively, in excess of the historic cost basis of Western Gas Resources, Inc. (entity that owned the interests in Fort Union and Rendezvous, which Anadarko acquired in August 2006). This excess balance is attributable to the difference between the fair value and book value of their gathering and treating facilities (at the time Western Gas Resources, Inc. was acquired by Anadarko) and is being amortized over the remaining estimated useful life of those facilities.

The White Cliffs investment balance at December 31, 2011, is $10.4 million less than the Partnership's underlying equity in White Cliffs' net assets as of December 31, 2011, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko's historic carrying value. This difference is being amortized to equity income over the remaining estimated useful life of the White Cliffs pipeline.

Management evaluates its equity-method investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments 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.

Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for 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. Over time, the discounted liability is accreted through accretion expense to its expected settlement value. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 9.

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 or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 11.

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

Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are 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 and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers' gas is gathered and delivered to pipelines for market delivery. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate are sold and the related purchases are recorded as a percentage of the product sale.

The Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue gas to either sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue gas. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower as liquids than as a component of the natural gas stream. Revenue is recognized from the sale of condensate and NGLs upon transfer of title and related purchases are recorded as cost of product.

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. Transportation 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 and NGLs 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 (the “FERC”) and reserves are established where appropriate. See Note 11for discussion of the Partnership's pending rate case with the FERC.

Proceeds from the sale of residue gas, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate 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 as revenues from gathering, processing and transportation of natural gas and natural gas liquids in the consolidated statements of income.

Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “LTIP”). The LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,160,848 units remain available for future issuance as of December 31, 2011. 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. Equity-based compensation expense attributable to grants made under the LTIP impact the Partnership's cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. 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: (i) Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) and (ii) 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 in 2011 and 2010 were collectively valued at $634.00 per unit and $215.00 per unit as of December 31, 2011 and 2010, respectively. The UVRs and UARs 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 (net of 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. Upon the occurrence of a UAR vesting event, each participant will receive a lump-sum cash payment (net of any applicable withholding taxes) for each UAR that is exercised prior to (i) the 90thday after a participant's voluntary termination, or (ii) the 10th anniversary of the grant date, whichever occurs first. 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.

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. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. For equity-based awards issued under the Incentive Plan and ultimately settled in cash, the fair value of the relevant equity grant is revised periodically based on the estimated fair value of the Partnership's general partner using a discounted cash flow estimate and multiples-valuation terminal value. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact the Partnership's cash flows 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. Equity-based compensation granted under the Anadarko Incentive Plans does not impact the Partnership's cash flows from operating activities. See Note 5.

Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Federal and state income tax expense was recorded prior to the Partnership's acquisition of the Partnership assets. In addition, deferred federal and state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases with respect to the Partnership assets prior to the Partnership's acquisition; and deferred state income taxes are recorded with respect to the Partnership assets including and subsequent to acquisition. The recognition of deferred federal and state tax assets prior to the Partnership's acquisition of the Partnership assets was based on management's belief that it was more likely than not that the results of future operations would generate sufficient taxable income to realize the deferred tax assets. For periods including or subsequent to the Partnership's acquisition of the Partnership assets, the Partnership is only subject to Texas margin tax; therefore, deferred federal income tax assets and liabilities with respect to the Partnership assets for periods including and subsequent to the Partnership's acquisitions are no longer recognized by the Partnership.

For periods including and subsequent to the Partnership's acquisition 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 estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, 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 accounting standard for uncertain tax positions 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, 2011 or 2010.

Net income per common unit. The Partnership applies the two-class method in determining net income per unit applicable to master limited partnerships having multiple classes of securities including common units, general partnership units and incentive distribution rights (“IDRs”) of the general partner. Under the two-class method, net income per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. 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.

The Partnership's net income for periods including and subsequent to the Partnership's acquisitions of the Partnership assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. The Partnership's net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner, common unitholders and subordinated unitholders consistent with actual cash distributions, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and subordinated unitholders in accordance with their respective ownership percentages during each period. See Note 4.

Other assets. For all periods presented, other assets on the Partnership's consolidated balance sheets include a $0.7 million receivable recognized in conjunction with the capital lease component of a processing agreement assumed in connection with the MGR acquisition. The agreement, in which the Partnership is the lessor, extends through November 2014. Other assets also includes $4.6 million related to the unguaranteed residual value of the processing plant included in the processing agreement, based on a measurement of fair value estimated when the plant was acquired by Anadarko in 2006. Interest income related to the capital lease is recorded to other income (expense), net on the accompanying consolidated statements of income.

Recently issued accounting standard not yet adopted. In September 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that permits an initial assessment of qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount for goodwill impairment testing purposes. Thus, determining a reporting unit's fair value is not required unless, as a result of the qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount. This ASU is effective prospectively beginning January 1, 2012. Adoption of this ASU will have no impact on the Partnership's consolidated financial statements.

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Other Intangible Assets - Additional Information (details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Goodwill and Intangible Assets Disclosure [Abstract]
Customer relationship intangible assets	$ 52.9
Accumulated amortization of customer relationship intangible assets	$ 0.9
Straight-line basis of amortization	50

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Acquisitions - Additional Information (details) (USD $)	12 Months Ended						1 Months Ended		12 Months Ended	1 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009		Feb. 28, 2011 Platte Valley [Member]		Dec. 31, 2011 Platte Valley [Member]	Jan. 31, 2012 Mountain Gas Resources [Member]	Jan. 31, 2012 Mountain Gas Resources [Member] Rendezvous [Member]
Business Acquisition Line Items
Adjustment to intangible assets									$ 1,600,000
Revenues	823,265,000	[1]	663,274,000	[1]	619,764,000	[1]			83,400,000
Operating expenses	614,072,000	[1]	485,286,000	[1]	483,500,000	[1]			59,100,000
Acquisition-related costs									700,000
Acquisition date							02/28/11	[2]		1/13/2012
Percentage acquired							100.00%	[2]		100.00%
Equity Method Investment, Ownership Percentage											22.00%
Miles Of Gathering Lines										1,295	338
Borrowings	1,055,939,000	[1]	660,000,000	[1]	101,451,000	[1]	303,000,000	[2]		299,000,000
Cash on hand							$ 602,000	[2]		$ 159,600,000
Common units issued										632,783
GP units issued										12,914

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] The assets acquired from a third party include (i) a natural gas gathering system and related compression and other ancillary equipment, and (ii) cryogenic gas processing facilities. These assets, located in the Denver-Julesburg Basin, are referred to collectively as the “Platte Valley assets” and the acquisition as the “Platte Valley acquisition.” See further information below, including the final allocation of the purchase price in August 2011.

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Income Taxes (tables)

12 Months Ended

Dec. 31, 2011

Income Tax Expense (Benefit) [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

		Year Ended December 31,
thousands		2011		2010		2009
Current income tax expense (benefit)
	Federal income tax expense (benefit)	$	15,890	$	10,580	$	20,253
	State income tax expense		524		1,534		1,856
	Total current income tax expense (benefit)		16,414		12,114		22,109
Deferred income tax expense (benefit)
	Federal income tax expense (benefit)		2,464		9,709		696
	State income tax expense (benefit)		140		(121)		(646)
	Total deferred income tax expense (benefit)		2,604		9,588		50
Total income tax expense		$	19,018	$	21,702	$	22,159

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

		Year Ended December 31,
thousands except percentages		2011		2010		2009
Income before income taxes		$	207,364	$	178,899	$	148,654
Statutory tax rate			0%		0%		0%
Tax computed at statutory rate		$	—	$	—	$	—
Adjustments resulting from:
	Federal taxes on income attributable to Partnership assets pre-acquisition		18,354		20,678		21,407
	State taxes on income attributable to Partnership assets pre-acquisition
	(net of federal benefit)		—		724		852
	Texas margin tax expense (benefit)		664		300		(100)
Income tax expense		$	19,018	$	21,702	$	22,159
Effective tax rate			9%		12%		15%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	December 31,
thousands	2011		2010
Credit carryforwards	$	14	$	14
Other		—		2
Net current deferred income tax assets		14		16
Depreciable property		(83,566)		(100,889)
Partnership basis		(24,481)		(26,320)
Credit carryforwards		556		570
Other		114		(207)
Net long-term deferred income tax liabilities		(107,377)		(126,846)
Total net deferred income tax liabilities	$	(107,363)	$	(126,830)

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Transactions With Affiliates (tables)

1 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2011

Transactions With Affiliates [Abstract]

Commodity Price Swap Agreements Table

In conjunction with the MGR acquisition, the Partnership entered into commodity price swap agreements with Anadarko that do not contain fixed notional volumes, each effective for one year beginning January 1, 2012, and extending through December 31, 2016. Below is a summary of the fixed prices on the Partnership's commodity price swap agreements for the system:

	Year Ended December 31,
per barrel except natural gas	2012		2013		2014		2015		2016
Ethane	$	26.87	$	25.34	$	24.10	$	23.41	$	23.11
Propane	$	57.97	$	55.59	$	53.78	$	52.99	$	52.90
Isobutane	$	80.98	$	77.66	$	75.13	$	74.02	$	73.89
Normal butane	$	71.15	$	68.24	$	66.01	$	65.04	$	64.93
Natural gasoline	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Condensate	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Natural gas (per MMbtu)	$	3.62	$	4.17	$	4.45	$	4.66	$	4.87

Below is a summary of the fixed price ranges on the Partnership's commodity price swap agreements outstanding as of December 31, 2011:

	Year Ended December 31,
per barrel except natural gas	2012				2013				2014				2015
Ethane	$	18.21	−	29.78	$	18.32	−	30.10	$	18.36	−	30.53	$	18.41
Propane	$	45.23	−	53.28	$	45.90	−	55.84	$	46.47	−	52.37	$	47.08
Isobutane	$	57.50	−	67.22	$	60.44	−	68.11	$	61.24	−	69.23	$	62.09
Normal butane	$	52.40	−	62.92	$	53.20	−	66.37	$	53.89	−	64.78	$	54.62
Natural gasoline	$	69.77	−	85.15	$	70.89	−	92.23	$	71.85	−	79.74	$	72.88
Condensate	$	72.73	−	78.52	$	74.04	−	83.93	$	75.22	−	79.56	$	76.47	−	78.61
Natural gas (per MMbtu)	$	4.15	−	5.97	$	3.75	−	6.09	$	5.32	−	6.20	$	5.50	−	5.96

Gains (Losses) on Commodity Price Swap Agreements Table

			Year Ended December 31,
thousands			2011		2010		2009
Gains (losses) on commodity price swap agreements related to sales: (1)
	Natural gas sales		$	33,845	$	20,200	$	18,446
	Natural gas liquids sales			(36,802)		2,953		2,196
		Total		(2,957)		23,153		20,642
Losses on commodity price swap agreements related to purchases (2)				(27,234)		(23,344)		(16,538)
Net gains (losses) on commodity price swap agreements			$	(30,191)	$	(191)	$	4,104

____________________________________________________________

(1)Reported in natural gas, NGLs and condensate sales in the Partnership's consolidated statements of income in the period in which the related sale is recorded.

(2)Reported in cost of product in the Partnership's consolidated statements of income in the period in which the related purchase is recorded.

LTIP Award Activity Table

		2011			2010			2009
		Weighted-			Weighted-			Weighted-
		Average			Average			Average
		Grant-Date			Grant-Date			Grant-Date
		Fair Value		Units	Fair Value		Units	Fair Value		Units
Phantom units outstanding
	at beginning of year	$	20.19	17,503	$	15.02	21,970	$	16.50	30,304
Vested		$	20.51	(15,119)	$	15.02	(19,751)	$	16.50	(30,304)
Granted		$	35.66	21,594	$	20.94	15,284	$	15.02	21,970
Phantom units outstanding
	at end of year	$	33.92	23,978	$	20.19	17,503	$	15.02	21,970

Summary of Affiliate Transactions Table

		Year Ended December 31,
thousands		2011		2010		2009
Revenues (1)		$	648,997	$	571,628	$	521,850
Cost of product (1)			83,722		95,667		94,999
Operation and maintenance (2)			51,339		46,379		41,444
General and administrative (3)			31,855		23,807		27,408
	Operating expenses		166,916		165,853		163,851
Interest income, net (4)			28,560		20,243		20,717
Interest expense (5)			4,935		6,924		9,096
Distributions to unitholders (6)			68,039		52,337		44,450
Contributions from noncontrolling interest owners			16,476		2,019		34,011
Distributions to noncontrolling interest owners			9,437		6,476		5,410

_______________________________________________________

(1)Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

(2)Represents expenses incurred under the services and secondment agreement, as applicable.

(3)Represents general and administrative expense incurred under the omnibus agreement, as applicable.

(4)Represents interest income recognized on the note receivable from Anadarko. This line item also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

(5)Represents interest expense recognized on the note payable to Anadarko.

(6)Represents distributions paid under the partnership agreement.

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Income Taxes - Tax Rate Reconciliation Table (details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Related Party Transaction Line Items
Income before income taxes	$ 207,364,000	[1]	$ 178,899,000	[1]	$ 148,654,000	[1]
Statutory tax rate	0.00%		0.00%		0.00%
Tax computed at statutory rate	0		0		0
Adjustments resulting from:
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) Texas margin tax expense (benefit)	664,000		300,000		(100,000)
Total income tax expense	19,018,000	[1]	21,702,000	[1]	22,159,000	[1]
Effective tax rate	9.00%		12.00%		15.00%
Pre Acquisition From Parent [Member]
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition	18,354,000		20,678,000		21,407,000
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) Texas margin tax expense (benefit)			$ 724,000		$ 852,000

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

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Partnership Distributions - Cash Distributions Table (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	0 Months Ended	3 Months Ended
	May 14, 2008	Dec. 31, 2011		Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009
Distributions Made to Members or Limited Partners [Abstract]
Total Quarterly Distribution per Unit	$ 0.300	$ 0.440	[1]	$ 0.420	$ 0.405	$ 0.390	$ 0.380	$ 0.370	$ 0.350	$ 0.340	$ 0.330	$ 0.320	$ 0.310	$ 0.300
Total Cash Distribution		$ 43,027	[1]	$ 40,323	$ 36,063	$ 33,168	$ 30,564	$ 26,381	$ 24,378	$ 22,042	$ 21,393	$ 18,289	$ 17,718	$ 17,030
Date of Distribution		February 2012	[1]	November 2011	August 2011	May 2011	February 2011	November 2010	August 2010	May 2010	February 2010	November 2009	August 2009	May 2009
Date of record for distribution		2/1/2012
Date of declaration for distribution		1/18/2012

[1] On January 18, 2012, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

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Property, Plant and Equipment (table)

12 Months Ended

Dec. 31, 2011

Property Plant And Equipment Abstract

Property, Plant and Equipment Table

		Estimated	December 31,
thousands		Useful Life	2011		2010
Land		n/a	$	364	$	364
Gathering systems		5 to 47 years		2,437,152		2,102,219
Pipelines and equipment		15 to 45 years		90,883		89,778
Assets under construction		n/a		104,687		44,388
Other		3 to 25 years		4,927		3,059
	Total property, plant and equipment			2,638,013		2,239,808
Accumulated depreciation				585,789		486,046
	Net property, plant and equipment		$	2,052,224	$	1,753,762

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Other Intangible Assets (table)

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule Of Expected Amortization Expense [Table Text Block]

	Future
thousands	Amortization
2012	$	1,075
2013		1,075
2014		1,075
2015		1,075
2016		1,075

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Cash flows from operating activities
Net income	$ 188,346	[1]	$ 157,197	[1]	$ 126,495	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	111,904	[1]	91,010	[1]	90,692	[1]
Deferred income taxes	2,604	[1]	9,588	[1]	50	[1]
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(881)	[1]	424	[1]	2,669	[1]
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	23,092	[1]	2,734	[1]	(14,267)	[1]
Change in other items, net	2,106	[1]	2,796	[1]	7,126	[1]
Change in other items, net	26,921		15,542		(4,422)
Net cash provided by operating activities	327,171	[1]	263,749	[1]	212,765	[1]
Cash flows from investing activities
Capital expenditures	(142,946)	[1]	(138,000)	[1]	(121,295)	[1]
Investments in equity affiliates	(93)	[1]	(310)	[1]	(382)	[1]
Net cash used in investing activities	(472,951)	[1]	(885,507)	[1]	(223,128)	[1]
Cash flows from financing activities
Borrowings, net of debt issuance costs	1,055,939	[1]	660,000	[1]	101,451	[1]
Repayments of debt	(869,000)	[1]	(361,000)	[1]	(101,451)	[1]
Revolving credit facility issuance costs			(12)	[1]	(4,263)	[1]
Proceeds from issuance of common and general partner units, net of offering expenses	335,317	[1]	345,803	[1]	122,539	[1]
Distributions to unitholders	(140,118)	[1]	(94,194)	[1]	(70,066)	[1]
Contributions from noncontrolling interest owners	33,637	[1]	2,053	[1]	40,262	[1]
Distributions to noncontrolling interest owners	(17,478)	[1]	(13,222)	[1]	(7,998)	[1]
Net contributions from Parent			39,420	[1]
Net (distributions to) Parent	(53,032)	[1]			(36,201)	[1]
Net cash provided by financing activities	345,265	[1]	578,848	[1]	44,273	[1]
Net increase (decrease) in cash and cash equivalents	199,485	[1]	(42,910)	[1]	33,910	[1]
Cash and cash equivalents at beginning of period	27,074	[1],[2]	69,984	[1]	36,074	[1]
Cash and cash equivalents at end of period	226,559	[1],[2]	27,074	[1],[2]	69,984	[1]
Supplemental disclosures
Elimination of net deferred tax liabilities	22,072	[1]	214,464	[1]
Contribution of assets from Parent			7,827	[1]
Contribution of assets (to) Parent	(29)	[1]
Increase (decrease) in accrued capital expenditures	5,402	[1]	5,218	[1]	13,390	[1]
Interest paid	25,828	[1]	16,497	[1]	9,372	[1]
Interest received	16,900	[1]	16,900	[1]	16,900	[1]
Taxes paid	190	[1]	507	[1]
Affiliated Entity Member
Cash flows from investing activities
Acquisitions from affiliates Acquisitions from third parties	(28,837)	[1]	(734,780)	[1]	(101,451)	[1]
Proceeds from sale of assets	382	[1]	2,805	[1]
Third Parties [Member]
Cash flows from investing activities
Acquisitions from affiliates Acquisitions from third parties	(301,957)	[1]	(18,047)	[1]
Proceeds from sale of assets	$ 500	[1]	$ 2,825	[1]

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

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Asset Retirement Obligations (table)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

		Year Ended December 31,
thousands		2011		2010
Carrying amount of asset retirement obligations at beginning of year		$	44,777	$	55,862
	Liabilities incurred		15,390		800
	Liabilities settled		—		(104)
	Accretion expense		3,781		3,740
	Revisions in estimated liabilities		(679)		(15,521)
Carrying amount of asset retirement obligations at end of year		$	63,269	$	44,777

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Acquisitions - Purchase Price Allocation Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Business Combinations [Abstract]
Property, plant and equipment	$ 264,521
Intangible assets	53,754
Asset retirement obligations and other liabilities	(16,318)
Total purchase price	$ 301,957

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Transactions With Affiliates - Summary Table (details) (USD $) In Thousands, unless otherwise specified	3 Months Ended													12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Related Party Transaction Line Items
Revenues														$ 823,265	[1]	$ 663,274	[1]	$ 619,764	[1]
Cost of product														327,371	[1],[2]	246,476	[1],[2]	238,874	[1],[2]
Operation and maintenance														119,104	[1],[2]	103,887	[1],[2]	106,590	[1],[2]
General and administrative														39,114	[1],[2]	29,640	[1],[2]	33,171	[1],[2]
Operating expenses														614,072	[1]	485,286	[1]	483,500	[1]
Interest income														28,560	[1],[3]	20,243	[1],[3]	20,717	[1],[3]
Interest expense														30,345	[1],[4]	18,794	[1],[4]	9,955	[1],[4]
Distributions to unitholders	43,027	[5]	40,323	36,063	33,168	30,564	26,381	24,378	22,042	21,393	18,289	17,718	17,030
Contributions from noncontrolling interest owners														33,637		2,053		40,262
Distributions to noncontrolling interest owners														17,478		13,222		7,998
Affiliates
Related Party Transaction Line Items
Revenues														648,997	[1],[6]	571,628	[1],[6]	521,850	[1],[6]
Cost of product														83,722	[6]	95,667	[6]	94,999	[6]
Operation and maintenance														51,339	[7]	46,379	[7]	41,444	[7]
General and administrative														31,855	[8]	23,807	[8]	27,408	[8]
Operating expenses														166,916		165,853		163,851
Interest expense														4,935	[9]	6,924	[9]	9,096	[9]
Distributions to unitholders														68,039	[10]	52,337	[10]	44,450	[10]
Contributions from noncontrolling interest owners														16,476		2,019		34,011
Distributions to noncontrolling interest owners														$ 9,437		$ 6,476		$ 5,410

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $83.7 million, $95.7 million and $95.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. Operation and maintenance includes charges from Anadarko of $51.3 million, $46.4 million and $41.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. General and administrative includes charges from Anadarko of $31.9 million, $23.8 million and $27.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. See Note 5.

[3] Represents interest income recognized on the note receivable from Anadarko. This line item also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

[4] Includes affiliate (as defined in Note 1) interest expense of $4.9 million, $6.9 million and $9.1 million for years ended December 31, 2011, 2010 and 2009, respectively. See Note 10.

[5] On January 18, 2012, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

[6] Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[7] Represents expenses incurred under the services and secondment agreement, as applicable.

[8] Represents general and administrative expense incurred under the omnibus agreement, as applicable.

[9] Represents interest expense recognized on the note payable to Anadarko.

[10] Represents distributions paid under the partnership agreement.

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Condensed Consolidating Financial Statements - Balance Sheet (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Condensed Financial Statements Captions Line Items
Current assets	$ 256,448	[1]	$ 44,625	[1]
Note receivable - Anadarko	260,000	[1]	260,000	[1]
Net property, plant and equipment	2,052,224	[1]	1,753,762	[1]
Other long-term assets	268,954		204,707
Total assets	2,837,626	[1]	2,263,094	[1]
Current liabilities	76,596	[1]	51,720	[1]
Long-term debt	669,178	[2]	474,000	[2]	175,000
Deferred income taxes	107,377	[1]	126,846	[1]
Asset retirement obligations and other	67,169	[1]	48,499	[1]
Total liabilities	920,320	[1]	701,065	[1]
Partners' capital	1,796,582	[1]	1,471,567	[1]
Noncontrolling interests	120,724	[1]	90,462	[1]
Total liabilities, equity and partners' capital	2,837,626	[1]	2,263,094	[1]
Western Gas Partners, LP
Condensed Financial Statements Captions Line Items
Current assets	207,913		24,972
Note receivable - Anadarko	260,000		260,000
Investment in consolidated subsidiaries	1,232,245		1,052,073
Net property, plant and equipment	735		165
Other long-term assets	8,164		2,361
Total assets	1,709,057		1,339,571
Current liabilities	95,817		201,989
Long-term debt	669,178		474,000
Asset retirement obligations and other	104		38
Total liabilities	765,099		676,027
Partners' capital	943,958		663,544
Total liabilities, equity and partners' capital	1,709,057		1,339,571
Subsidiary Guarantors
Condensed Financial Statements Captions Line Items
Current assets	110,619		209,649
Investment in consolidated subsidiaries	130,396		97,018
Net property, plant and equipment	1,812,275		1,572,383
Other long-term assets	260,790		202,346
Total assets	2,314,080		2,081,396
Current liabilities	56,762		47,946
Deferred income taxes	107,377		126,846
Asset retirement obligations and other	64,980		46,507
Total liabilities	229,119		221,299
Partners' capital	1,964,237		1,769,635
Noncontrolling interests	120,724		90,462
Total liabilities, equity and partners' capital	2,314,080		2,081,396
Non-Guarantor Subsidiary
Condensed Financial Statements Captions Line Items
Current assets	25,977		10,346
Net property, plant and equipment	239,214		181,214
Total assets	265,191		191,560
Current liabilities	12,078		2,127
Asset retirement obligations and other	2,085		1,954
Total liabilities	14,163		4,081
Partners' capital	251,028		187,479
Total liabilities, equity and partners' capital	265,191		191,560
Eliminations
Condensed Financial Statements Captions Line Items
Current assets	(88,061)		(200,342)
Investment in consolidated subsidiaries	(1,362,641)		(1,149,091)
Total assets	(1,450,702)		(1,349,433)
Current liabilities	(88,061)		(200,342)
Total liabilities	(88,061)		(200,342)
Partners' capital	(1,362,641)		(1,149,091)
Total liabilities, equity and partners' capital	$ (1,450,702)		$ (1,349,433)

[1] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] The Partnership’s consolidated balance sheets include accrued interest expense of $2.7 million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Revenues
Total revenues	$ 823,265	[1]	$ 663,274	[1]	$ 619,764	[1]
Operating expenses
Cost of product	327,371	[1],[2]	246,476	[1],[2]	238,874	[1],[2]
Operation and maintenance	119,104	[1],[2]	103,887	[1],[2]	106,590	[1],[2]
General and administrative	39,114	[1],[2]	29,640	[1],[2]	33,171	[1],[2]
Property and other taxes	16,579	[1]	14,273	[1]	14,173	[1]
Depreciation, amortization and impairments	111,904	[1]	91,010	[1]	90,692	[1]
Total operating expenses	614,072	[1]	485,286	[1]	483,500	[1]
Operating income	209,193	[1]	177,988	[1]	136,264	[1]
Interest income - affiliates	28,560	[1],[3]	20,243	[1],[3]	20,717	[1],[3]
Interest expense	(30,345)	[1],[4]	(18,794)	[1],[4]	(9,955)	[1],[4]
Other income (expense), net	(44)	[1]	(538)	[1]	1,628	[1]
Income before income taxes	207,364	[1]	178,899	[1]	148,654	[1]
Income tax expense	19,018	[1]	21,702	[1]	22,159	[1]
Net income (loss)	188,346	[1]	157,197	[1]	126,495	[1]
Net income attributable to noncontrolling interests	14,103	[1]	11,005	[1]	10,260	[1]
Net income attributable to Western Gas Partners, LP	174,243	[1]	146,192	[1]	116,235	[1]
Limited partners' interest in net income:
Pre-acquisition net (income) loss allocated to Parent	(34,084)	[1]	(32,061)	[1]	(44,827)	[1]
General partner interest in net (income) loss	(8,599)	[1],[5]	(3,067)	[1],[5]	(1,428)	[1],[5]
Limited partners' interest in net income	131,560	[1],[5]	111,064	[1],[5]	69,980	[1],[5]
Common [Member]
Limited partners' interest in net income:
Limited partners' interest in net income	110,542		68,410		37,035
Subordinated [Member]
Limited partners' interest in net income:
Limited partners' interest in net income	21,018		42,654		32,945
Affiliates
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	217,852	[1]	192,286	[1]	181,477	[1]
Natural gas, natural gas liquids and condensate sales	417,547	[1]	369,903	[1]	330,855	[1]
Equity income and Other, net	13,598	[1]	9,439	[1]	9,518	[1]
Total revenues	648,997	[1],[6]	571,628	[1],[6]	521,850	[1],[6]
Operating expenses
Cost of product	83,722	[6]	95,667	[6]	94,999	[6]
Operation and maintenance	51,339	[7]	46,379	[7]	41,444	[7]
General and administrative	31,855	[8]	23,807	[8]	27,408	[8]
Total operating expenses	166,916		165,853		163,851
Interest expense	(4,935)	[9]	(6,924)	[9]	(9,096)	[9]
Third Parties
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	83,477	[1]	60,987	[1]	64,989	[1]
Natural gas, natural gas liquids and condensate sales	84,836	[1]	26,134	[1]	30,790	[1]
Equity income and Other, net	5,955	[1]	4,525	[1]	2,135	[1]
Total revenues	174,268	[1]	91,646	[1]	97,914	[1]
Operating expenses
Interest expense	$ (25,410)		$ (11,870)		$ (859)
Limited Partners Member | Common [Member]
Limited partners' interest in net income:
Net income per unit - basic and diluted	$ 1.64	[1]	$ 1.66	[1]	$ 1.25	[1]
Limited Partners Member | Subordinated [Member]
Limited partners' interest in net income:
Net income per unit - basic and diluted	$ 1.28	[1],[10]	$ 1.61	[1],[10]	$ 1.24	[1],[10]

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $83.7 million, $95.7 million and $95.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. Operation and maintenance includes charges from Anadarko of $51.3 million, $46.4 million and $41.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. General and administrative includes charges from Anadarko of $31.9 million, $23.8 million and $27.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. See Note 5.

[3] Represents interest income recognized on the note receivable from Anadarko. This line item also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

[4] Includes affiliate (as defined in Note 1) interest expense of $4.9 million, $6.9 million and $9.1 million for years ended December 31, 2011, 2010 and 2009, respectively. See Note 10.

[5] Represents net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 1). See also Note 4.

[6] Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[7] Represents expenses incurred under the services and secondment agreement, as applicable.

[8] Represents general and administrative expense incurred under the omnibus agreement, as applicable.

[9] Represents interest expense recognized on the note payable to Anadarko.

[10] All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4.

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Partnership Distributions - Incentive Distribution Rights Table (details) (USD $)	0 Months Ended	3 Months Ended
	May 14, 2008	Dec. 31, 2011		Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.300	$ 0.440	[1]	$ 0.420	$ 0.405	$ 0.390	$ 0.380	$ 0.370	$ 0.350	$ 0.340	$ 0.330	$ 0.320	$ 0.310	$ 0.300
General Partner
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	2.00%
General Partner | First Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	2.00%
General Partner | Second Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	15.00%
General Partner | Third Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	25.00%
General Partner | Thereafter [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	50.00%
Unitholders
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	98.00%
Unitholders | First Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	98.00%
Unitholders | Second Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	85.00%
Unitholders | Third Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	75.00%
Unitholders | Thereafter [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Marginal Percentage Interest In Distributions	50.00%
Minimum [Member] | First Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.300
Minimum [Member] | Second Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.345
Minimum [Member] | Third Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.375
Maximum [Member] | First Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.345
Maximum [Member] | Second Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.375
Maximum [Member] | Third Target [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.450
Maximum [Member] | Thereafter [Member]
IncentiveDistributionMadeToManagingMemberOrGeneralPartnerLineItems
Total Quarterly Distribution Target Amount	$ 0.450

[1] On January 18, 2012, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

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Consolidated Statement of Equity and Partners' Capital (USD $) In Thousands		Total		Parent Net Investment	Common Units	Subordinated Units	General Partner Units	Noncontrolling Interests
Balance at Dec. 31, 2008	[1]	$ 1,554,790		$ 833,819	$ 368,050	$ 275,917	$ 10,988	$ 66,016
Net income		126,495	[2]	44,827	37,035	32,945	1,428	10,260
Issuance of common and general partner units, net of offering expenses		122,539			120,080		2,459
Contributions from noncontrolling interest owners		40,262		20,544				19,718
Distributions to noncontrolling interest owners		(7,998)		(2,926)				(5,072)
Distributions to unitholders		(70,066)			(36,025)	(32,640)	(1,401)
Acquisition from affiliates		(101,451)		(112,744)	11,068		225
Net pre-acquisition contributions from (distributions to) Parent		(36,505)		(36,505)
Non-cash equity-based compensation and other		(248)		2,354	(2,978)	349	27
Balance at Dec. 31, 2009	[1]	1,627,818		749,369	497,230	276,571	13,726	90,922
Net income		157,197	[2]	32,061	68,410	42,654	3,067	11,005
Issuance of common and general partner units, net of offering expenses		345,803			338,483		7,320
Contributions from noncontrolling interest owners		2,053						2,053
Distributions to noncontrolling interest owners		(13,222)						(13,222)
Distributions to unitholders		(94,194)			(55,108)	(36,885)	(2,201)
Acquisition from affiliates		(734,780)		(684,487)	(49,662)		(631)
Net pre-acquisition contributions from (distributions to) Parent		44,335		44,335
Contribution of other assets from Parent		10,715			10,500		215
Elimination of net deferred tax liabilities		214,464	[2]	214,464
Non-cash equity-based compensation and other		1,840		1,219	864	44	9	(296)
Balance at Dec. 31, 2010	[1]	1,562,029	[3]	356,961	810,717	282,384	21,505	90,462
Net income		188,346	[2]	34,084	110,542	21,018	8,599	14,103
Conversion of subordinated units to common units	[4]				272,222	(272,222)
Issuance of common and general partner units, net of offering expenses		335,317			328,345		6,972
Contributions from noncontrolling interest owners		33,637						33,637
Distributions to noncontrolling interest owners		(17,478)						(17,478)
Distributions to unitholders		(140,118)			(102,091)	(31,180)	(6,847)
Acquisition from affiliates		(25,000)		(92,666)	66,313		1,353
Contributions of Equity Based Compensation From Parent		9,666			9,472		194
Net pre-acquisition contributions from (distributions to) Parent		(50,851)		(50,851)
Elimination of net deferred tax liabilities		22,072	[2]	22,072
Non-cash equity-based compensation and other		(314)			(267)		(47)
Balance at Dec. 31, 2011	[1]	$ 1,917,306	[3]	$ 269,600	$ 1,495,253		$ 31,729	$ 120,724

[1] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, 2009, and 2008, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[3] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[4] All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

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Property, Plant and Equipment Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Years		Dec. 31, 2010
Property Plant And Equipment Line Items
Property, plant and equipment	$ 2,638,013	[1]	$ 2,239,808	[1]
Accumulated depreciation	585,789	[1]	486,046	[1]
Net property, plant and equipment	2,052,224	[1]	1,753,762	[1]
Land Member
Property Plant And Equipment Line Items
Property, plant and equipment	364		364
Gathering systems
Property Plant And Equipment Line Items
Property, plant and equipment	2,437,152		2,102,219
Estimated useful life, range start	5
Estimated useful life, range end	47
Pipelines And Equipment [Member]
Property Plant And Equipment Line Items
Property, plant and equipment	90,883		89,778
Estimated useful life, range start	15
Estimated useful life, range end	45
Asset Under Construction Member
Property Plant And Equipment Line Items
Property, plant and equipment	104,687		44,388
Other
Property Plant And Equipment Line Items
Property, plant and equipment	$ 4,927		$ 3,059
Estimated useful life, range start	3
Estimated useful life, range end	25

[1] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

XML

Subsequent Event (table)

1 Months Ended

12 Months Ended

Dec. 31, 2011

Dec. 31, 2011

Subsequent Events [Abstract]

Commodity Price Swap Agreements Table

In conjunction with the MGR acquisition, the Partnership entered into commodity price swap agreements with Anadarko that do not contain fixed notional volumes, each effective for one year beginning January 1, 2012, and extending through December 31, 2016. Below is a summary of the fixed prices on the Partnership's commodity price swap agreements for the system:

	Year Ended December 31,
per barrel except natural gas	2012		2013		2014		2015		2016
Ethane	$	26.87	$	25.34	$	24.10	$	23.41	$	23.11
Propane	$	57.97	$	55.59	$	53.78	$	52.99	$	52.90
Isobutane	$	80.98	$	77.66	$	75.13	$	74.02	$	73.89
Normal butane	$	71.15	$	68.24	$	66.01	$	65.04	$	64.93
Natural gasoline	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Condensate	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Natural gas (per MMbtu)	$	3.62	$	4.17	$	4.45	$	4.66	$	4.87

Below is a summary of the fixed price ranges on the Partnership's commodity price swap agreements outstanding as of December 31, 2011:

	Year Ended December 31,
per barrel except natural gas	2012				2013				2014				2015
Ethane	$	18.21	−	29.78	$	18.32	−	30.10	$	18.36	−	30.53	$	18.41
Propane	$	45.23	−	53.28	$	45.90	−	55.84	$	46.47	−	52.37	$	47.08
Isobutane	$	57.50	−	67.22	$	60.44	−	68.11	$	61.24	−	69.23	$	62.09
Normal butane	$	52.40	−	62.92	$	53.20	−	66.37	$	53.89	−	64.78	$	54.62
Natural gasoline	$	69.77	−	85.15	$	70.89	−	92.23	$	71.85	−	79.74	$	72.88
Condensate	$	72.73	−	78.52	$	74.04	−	83.93	$	75.22	−	79.56	$	76.47	−	78.61
Natural gas (per MMbtu)	$	4.15	−	5.97	$	3.75	−	6.09	$	5.32	−	6.20	$	5.50	−	5.96

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Debt and Interest Expense - Debt Activity Table (details) (USD $) In Thousands, unless otherwise specified						12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009	Dec. 31, 2011 Revolving Credit Facility [Member]	Dec. 31, 2010 Revolving Credit Facility [Member]	Dec. 31, 2011 Revolving Credit Facility [Member] Swingline [Member]	Dec. 31, 2010 Revolving Credit Facility [Member] Swingline [Member]	Dec. 31, 2011 Wattenberg Term Loan [Member]	Dec. 31, 2010 Wattenberg Term Loan [Member]	Dec. 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member]
Debt Instrument Line Items
Balance	$ 669,178	[1]	$ 474,000	[1]	$ 175,000	$ 49,000				$ 250,000
Borrowings						570,000	410,000	30,000	10,000		250,000	500,000
Repayments						(619,000)	(361,000)	(30,000)	(10,000)	(250,000)
Other and changes in debt discount	(5,822)
Balance	$ 669,178	[1]	$ 474,000	[1]	$ 175,000		$ 49,000				$ 250,000	$ 494,178

[1] The Partnership’s consolidated balance sheets include accrued interest expense of $2.7 million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

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Supplemental Quarterly Information

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Information [Abstract]

Supplemental Quarterly Information

The following table presents a summary of the Partnership's operating results by quarter for the years ended December 31, 2011 and 2010. The Partnership's operating results reflect the operations of the Partnership assets from the dates of common control, unless otherwise noted, and have been recast to include results attributable to the Bison and MGR assets, as applicable. See Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 ofExhibit 99.3 to this Current Report on Form 8-K.

	First		Second		Third		Fourth
thousands except per-unit amounts	Quarter		Quarter		Quarter		Quarter
2011
Revenues	$	180,842	$	209,680	$	217,546	$	215,197
Operating income	$	50,972	$	58,181	$	53,946	$	46,094
Net income attributable to Western Gas Partners, LP	$	43,897	$	45,026	$	45,306	$	40,014
Net income per common unit – basic and diluted (1)	$	0.43	$	0.40	$	0.41	$	0.35
Net income per subordinated unit – basic and diluted (1)	$	0.41	$	0.38	$	—	$	—
2010
Revenues	$	171,195	$	165,915	$	163,139	$	163,025
Operating income	$	42,729	$	44,394	$	41,335	$	49,530
Net income attributable to Western Gas Partners, LP	$	34,447	$	33,890	$	36,189	$	41,666
Net income per common unit – basic and diluted (1)	$	0.37	$	0.35	$	0.44	$	0.48
Net income per subordinated unit – basic and diluted (1)	$	0.37	$	0.35	$	0.44	$	0.44

____________________________________________________________

(1)Represents net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 1. Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to thisCurrent Report on Form 8-K). In addition, all subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4. Equity and Partners' Capitalin the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report onForm 8-K.

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Supplemental Quarterly Information (table)

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Information [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

	First		Second		Third		Fourth
thousands except per-unit amounts	Quarter		Quarter		Quarter		Quarter
2011
Revenues	$	180,842	$	209,680	$	217,546	$	215,197
Operating income	$	50,972	$	58,181	$	53,946	$	46,094
Net income attributable to Western Gas Partners, LP	$	43,897	$	45,026	$	45,306	$	40,014
Net income per common unit – basic and diluted (1)	$	0.43	$	0.40	$	0.41	$	0.35
Net income per subordinated unit – basic and diluted (1)	$	0.41	$	0.38	$	—	$	—
2010
Revenues	$	171,195	$	165,915	$	163,139	$	163,025
Operating income	$	42,729	$	44,394	$	41,335	$	49,530
Net income attributable to Western Gas Partners, LP	$	34,447	$	33,890	$	36,189	$	41,666
Net income per common unit – basic and diluted (1)	$	0.37	$	0.35	$	0.44	$	0.48
Net income per subordinated unit – basic and diluted (1)	$	0.37	$	0.35	$	0.44	$	0.44

________________________________________________________

(1)Represents net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 1. Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to thisCurrent Report on Form 8-K). In addition, all subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4. Equity and Partners' Capitalin the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report onForm 8-K.

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Summary of Significant Accounting Policies (table)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Equity-Method Investments

		Equity Investments
thousands		Fort Union (1)		White Cliffs (2)		Rendezvous (3)
Balance at December 31, 2009		$	20,060	$	1,284	$	78,216
	Investment earnings, net of amortization		5,723		917		988
	Contributions		310		—		—
	Distributions		(4,665)		(1,270)		(5,038)
	Acquisition of additional 9.6% interest from third party		—		18,047		—
	Other		—		—		(110)
Balance at December 31, 2010		$	21,428	$	18,978	$	74,056
	Investment earnings, net of amortization		6,067		4,023		1,171
	Contributions		—		93		—
	Distributions		(5,227)		(5,384)		(5,388)
Balance at December 31, 2011		$	22,268	$	17,710	$	69,839

_______________________________________________________

(1)The Partnership has a 14.81% interest in Fort Union, a joint venture which 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. 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. Each of the joint venture members has pledged its respective equity interest to the administrative agent of Fort Union's credit agreement.

(2)The Partnership has a 10% interest in White Cliffs,a limited liability company which owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma and became operational in June 2009. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.

(3)       The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in southwestern Wyoming. 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 members' gas servicing agreements, require unanimous approval of the members.

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Commitments and Contingencies - Operating lease Obligations Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Commitments And Contingencies [Abstract]
2012	$ 261
2013	228
2014	168
2015	168
2016	168
Thereafter	103
Total	$ 1,096

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Consolidated Statement of Equity and Partners' Capital (Parenthetical)	Dec. 31, 2011
Statement Of Partners Capital Abstract
Subordinated Units End Date	8/15/2011

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Consolidated Statements of Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Cost of product	$ 327,371	[1],[2]	$ 246,476	[1],[2]	$ 238,874	[1],[2]
Operation and maintenance	119,104	[1],[2]	103,887	[1],[2]	106,590	[1],[2]
General and administrative	39,114	[1],[2]	29,640	[1],[2]	33,171	[1],[2]
Interest expense	30,345	[1],[3]	18,794	[1],[3]	9,955	[1],[3]
Subordinated Units End Date	8/15/2011
Affiliates Anadarko
Cost of product	83,722	[4]	95,667	[4]	94,999	[4]
Operation and maintenance	51,339	[5]	46,379	[5]	41,444	[5]
General and administrative	31,855	[6]	23,807	[6]	27,408	[6]
Interest expense	$ 4,935	[7]	$ 6,924	[7]	$ 9,096	[7]

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $83.7 million, $95.7 million and $95.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. Operation and maintenance includes charges from Anadarko of $51.3 million, $46.4 million and $41.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. General and administrative includes charges from Anadarko of $31.9 million, $23.8 million and $27.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. See Note 5.

[3] Includes affiliate (as defined in Note 1) interest expense of $4.9 million, $6.9 million and $9.1 million for years ended December 31, 2011, 2010 and 2009, respectively. See Note 10.

[4] Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[5] Represents expenses incurred under the services and secondment agreement, as applicable.

[6] Represents general and administrative expense incurred under the omnibus agreement, as applicable.

[7] Represents interest expense recognized on the note payable to Anadarko.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

The following table provides a summary of changes in asset retirement obligations:

		Year Ended December 31,
thousands		2011		2010
Carrying amount of asset retirement obligations at beginning of year		$	44,777	$	55,862
	Liabilities incurred		15,390		800
	Liabilities settled		—		(104)
	Accretion expense		3,781		3,740
	Revisions in estimated liabilities		(679)		(15,521)
Carrying amount of asset retirement obligations at end of year		$	63,269	$	44,777

The increase in asset retirement obligations for the year ended December 31, 2011, is primarily a result of the liabilities incurred in connection with the acquisition of the Platte Valley assets (see Note 2). Revisions in estimates for the year ended December 31, 2010, related primarily to a decrease in the inflation rate.

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Document and Entity Information	12 Months Ended
	Dec. 31, 2011
Document Information Line Items
Entity Registrant Name	WESTERN GAS PARTNERS LP
Entity Central Index Key	0001414475
Document Type	8-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false

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Debt and Interest Expense

12 Months Ended

Dec. 31, 2011

Debt Instruments Abstract

Debt and Interest Expense

The following table presents the Partnership's outstanding debt as of December 31, 2011 and 2010:

	December 31, 2011						December 31, 2010
			Carrying		Fair				Carrying		Fair
thousands	Principal		Value		Value		Principal		Value		Value
Revolving credit facility	$	—	$	—	$	—	$	49,000	$	49,000	$	49,000
5.375% Senior Notes due 2021		500,000		494,178		499,950		—		—		—
Wattenberg term loan		—		—		—		250,000		250,000		250,000
Note payable to Anadarko		175,000		175,000		174,528		175,000		175,000		168,116
Total debt outstanding (1)	$	675,000	$	669,178	$	674,478	$	474,000	$	474,000	$	467,116

_______________________________________________________

(1)The Partnership's consolidated balance sheets include accrued interest expense of $2.7million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

Debt activity.The following table presents the debt activity of the Partnership for the years ended December 31, 2011 and 2010:

thousands		Carrying Value
Balance as of December 31, 2009		$	175,000
	Revolving credit facility borrowings		410,000
	Repayment of revolving credit facility		(361,000)
	Revolving credit facility borrowings – Swingline		10,000
	Repayment of revolving credit facility – Swingline		(10,000)
	Issuance of Wattenberg term loan		250,000
Balance as of December 31, 2010		$	474,000
	Revolving credit facility borrowings		570,000
	Repayment of revolving credit facility		(619,000)
	Repayment of Wattenberg term loan		(250,000)
	Revolving credit facility borrowings – Swingline		30,000
	Repayment of revolving credit facility – Swingline		(30,000)
	Issuance of 5.375% Senior Notes due 2021		500,000
	Other and changes in debt discount		(5,822)
Balance as of December 31, 2011		$	669,178

5.375% Senior Notes due 2021. In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notesdue 2021 (the “Notes”) at a price to the public of 98.778% of the face amount of the Notes. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the Notes is paid semi-annually on June 1 and December 1 of each year, with payments commencing on December 1, 2011. Proceeds from the offering of the Notes (net of the underwriting discount of $3.3million and debt issuance costs) were used to repay the then-outstanding balance on the Partnership's revolving credit facility, with the remainder used for general partnership purposes.

The Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the Notesin whole or in part,at any time before March 1, 2021, at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such Notes (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined in the indenture governing the Notes)plus 40 basis points, plus, in either case, accrued and unpaid interest, if any, on the principal amount being redeemed to such redemption date. On or after March 1, 2021, the Notes will be redeemable and repayable, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the Notes to be redeemed, plus accrued interest on the Notes to be redeemed to the date of redemption.

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Partnership's wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors' guarantees will be released if the Subsidiary Guarantors are released from their obligations under the Partnership's revolving credit facility. See Note 13 for the condensed financial statements of the Subsidiary Guarantors.

The Notes indenture contains customary events of default including, among others, (i) default in any payment of interest on any debt securities when due that continues for 30 days; (ii) default in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii) certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing the Notes also contains covenants that limit, among other things, the ability of the Partnership and the Subsidiary Guarantors to (i) create liens on their principal properties;(ii) engage in sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease or transfer substantially all of their properties or assets to another entity. At December 31, 2011, the Partnership was in compliance with all covenants under the Notes.

Note payable to Anadarko.In December 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 4.00% until November 2010. The term loan agreement was amended in December 2010 to fix the interest rate at 2.82% through maturity in 2013. The Partnership has the option, at any time, to repay the outstanding principal amount in whole or in part.

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

Revolving credit facility. In March 2011, the Partnership entered into an amended and restated $800.0 million senior unsecured revolving credit facility (the “RCF”) and borrowed $250.0 million under the RCF to repay the Wattenberg term loan (described below). The RCF amended and restated the Partnership's $450.0 million credit facility, which was originally entered into in October 2009. The RCF matures in March 2016 and bears interest at London Interbank Offered Rate (“LIBOR”) plus applicable margins currently ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.80% and 3.26% at December 31, 2011 and 2010, respectively. The Partnership is required to pay a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon the Partnership's senior unsecured debt rating. The facility fee rate was 0.25% and 0.50% at December 31, 2011 and 2010, respectively.

The RCF contains covenants that limit, among other things, the ability of the Partnership and certain of its subsidiaries to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of the Partnership's assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and certain financial tests as of the end of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization (“Consolidated EBITDA”) for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio (which is defined as the ratio of Consolidated EBITDA for the most recent four consecutive fiscal quarters to consolidated interest expense for such period) of 2.0 to 1.0.

All amounts due under the RCF are unconditionally guaranteed by the Partnership's wholly owned subsidiaries. The Partnership will no longer be required to comply with the minimum consolidated interest coverage ratio, as well as the subsidiary guarantees and certain of the aforementioned covenants, if the Partnership obtains two of the following three ratings: BBB- or better by Standard & Poor's, Baa3 or better by Moody's Investors Service, or BBB- or better by Fitch Ratings. At December 31, 2011, the Partnership was in compliance with all covenants under the RCF. As of December 31, 2011, no amounts were outstanding under the RCF, and $800.0 million was available for borrowing. See Note 2for borrowing activity under the RCF in January 2012, related to the MGR acquisition.

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

Interest-rate swap agreement. The Partnership entered into a forward-starting interest-rate swap agreement in March 2011 to mitigate the risk of rising interest rates prior to the issuance of the Notes. In May 2011, the Partnership issued the Notes and terminated the swap agreement, realizing a loss of $1.9 million, which is included in other expense, net in the Partnership's consolidated statements of income.

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

			Year Ended December 31,
thousands			2011		2010		2009
Third Parties
	Interest expense on long-term debt		$	20,533	$	8,530	$	304
	Amortization of debt issuance costs and commitment fees (1)			5,297		3,340		555
	Capitalized interest			(420)		—		—
		Total interest expense – third parties		25,410		11,870		859
Affiliates
	Interest expense on notes payable to Anadarko			4,935		6,828		8,953
	Credit facility commitment fees			—		96		143
		Total interest expense – affiliates		4,935		6,924		9,096
Interest expense			$	30,345	$	18,794	$	9,955

___________________________________________________________________

(1)For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters' fees related to the Notes.

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Consolidated Balance Sheet (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 226,559	[1],[2]	$ 27,074	[1],[2]
Accounts receivable, net	22,703	[2],[3]	11,607	[2],[3]
Other current assets	7,186	[2],[4]	5,944	[2],[4]
Total current assets	256,448	[2]	44,625	[2]
Note receivable - Anadarko	260,000	[2]	260,000	[2]
Plant, property and equipment
Cost	2,638,013	[2]	2,239,808	[2]
Less accumulated depreciation	585,789	[2]	486,046	[2]
Net property, plant and equipment	2,052,224	[2]	1,753,762	[2]
Goodwill and other intangible assets	134,994	[2]	82,136	[2]
Equity investments	109,817	[2]	114,462	[2]
Other assets	24,143	[2]	8,109	[2]
Other long-term assets	268,954		204,707
Total assets	2,837,626	[2]	2,263,094	[2]
Current liabilities
Accounts and natural gas imbalance payables	26,600	[2],[5]	17,058	[2],[5]
Accrued ad valorem taxes	8,186	[2]	6,262	[2]
Income taxes payable	495	[2]	160	[2]
Accrued liabilities	41,315	[2],[6]	28,240	[2],[6]
Total current liabilities	76,596	[2]	51,720	[2]
Long-term debt Note payable - Anadarko	669,178	[7]	474,000	[7]
Deferred income taxes	107,377	[2]	126,846	[2]
Asset retirement obligations and other	67,169	[2]	48,499	[2]
Total long-term liabilities	843,724	[2]	649,345	[2]
Total liabilities	920,320	[2]	701,065	[2]
Equity and partners' capital
General partner units (1,839,613 and 1,583,128 units issued and outstanding at December 31, 2011 and 2010, respectively)	31,729	[2]	21,505	[2]
Parent net investment	269,600	[2]	356,961	[2]
Total partners' capital	1,796,582	[2]	1,471,567	[2]
Noncontrolling interests	120,724	[2]	90,462	[2]
Total equity and partners' capital	1,917,306	[2],[8]	1,562,029	[2],[8]
Total liabilities, equity and partners' capital	2,837,626	[2]	2,263,094	[2]
Common [Member]
Equity and partners' capital
Common units (90,140,999 and 51,036,968 units issued and outstanding at December 31, 2011 and 2010, respectively) Subordinated units (zero and 26,536,306 units issued and outstanding at December 31, 2011 and 2010, respectively)	1,495,253	[2]	810,717	[2]
Subordinated [Member]
Equity and partners' capital
Common units (90,140,999 and 51,036,968 units issued and outstanding at December 31, 2011 and 2010, respectively) Subordinated units (zero and 26,536,306 units issued and outstanding at December 31, 2011 and 2010, respectively)			282,384	[2],[9]
Third Parties [Member]
Current liabilities
Long-term debt Note payable - Anadarko	494,178	[2]	299,000	[2]
Affiliates Anadarko
Current assets
Accounts receivable, net			1,800
Other current assets	500
Current liabilities
Accounts and natural gas imbalance payables	5,900		1,500
Accrued liabilities	300		600
Long-term debt Note payable - Anadarko	$ 175,000	[2]	$ 175,000	[2]

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[3] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of zero and $1.8 million as of December 31, 2011 and 2010, respectively.

[4] Other current assets includes natural gas imbalance receivables from affiliates of $0.5 million and zero as of December 31, 2011 and 2010, respectively.

[5] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $5.9 million and $1.5 million as of December 31, 2011 and 2010, respectively.

[6] Accrued liabilities include amounts payable to affiliates of $0.3 million and $0.6 million as of December 31, 2011 and 2010, respectively.

[7] The Partnership’s consolidated balance sheets include accrued interest expense of $2.7 million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

[8] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, 2009, and 2008, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[9] All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

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Equity and Partners' Capital

12 Months Ended

Dec. 31, 2011

Partners Capital Notes Abstract

Equity and Partners' Capital

Equity offerings.The Partnership completed the following public equity offerings during 2009, 2010 and 2011:

						Underwriting
						Discount and
thousands except unit		Common	GP Units	Price Per		Other Offering		Net
	and per-unit amounts	Units Issued (2)	Issued (3)	Unit		Expenses		Proceeds
December 2009 equity offering		6,900,000	140,817	$	18.20	$	5,500	$	122,539
May 2010 equity offering (1)		4,558,700	93,035		22.25		4,427		99,074
November 2010 equity offering		8,415,000	171,734		29.92		10,325		246,729
March 2011 equity offering		3,852,813	78,629		35.15		5,621		132,569
September 2011 equity offering		5,750,000	117,347		35.86		7,655		202,748

____________________________________________________________

(1)Refers collectively to the May 2010 equity offering issuance, and the June 2010 exercise of the underwriters' over-allotment option.

(2)Includes the issuance of 900,000 common units, 558,700 common units, 915,000 common units, 302,813 common units and 750,000 common units pursuant to the exercise, in full or in part, of the underwriters' over-allotment options granted in connection with the December 2009, May 2010, November 2010, March 2011 and September 2011 equity offerings, respectively.

(3)Represents general partner units issued to the general partner in exchange for the general partner's proportionate capital contribution to maintain its 2.0% interest.

Common and general partner units.The Partnership's common units are listed on the New York Stock Exchange under the symbol “WES.”

Conversion of subordinated units. From its inception through June 30, 2011, the Partnership paid equal distributions per unit on common, subordinated and general partner units. Upon payment of the cash distribution for the second quarter of 2011, the financial requirements for the conversion of all subordinated units were satisfied. As a result, the 26,536,306 subordinated units were converted on August 15, 2011, on a one-for-one basis, into common units. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. The Partnership's net income was allocated to the general partner and the limited partners, including the holders of the subordinated units, through June 30, 2011, in accordance with their respective ownership percentages. The conversion does not impact the amount of the cash distribution paid or the total number of the Partnership's outstanding units representing limited partner interests.

Anadarko holdings of Partnership equity. As of December 31, 2011, Anadarko held 1,839,613 general partner units representing a 2.0% general partner interest in the Partnership, 39,789,221 common units representing a 43.3% limited partner interest, and 100% of the Partnership's IDRs. The public held 50,351,778 common units, representing a 54.7% interest in the Partnership. Refer to Note 2 for information related to the common and general partner units issued in conjunction with the MGR acquisition.

The Partnership's net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 2), is allocated to the general partner and the limited partners in accordance with their respective ownership percentages (see Note 1).

Basic and diluted net income per common unit is calculated by dividing the limited partners' interest in net income by the weighted average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding.

The following table illustrates the Partnership's calculation of net income per unit for common and subordinated units:

	Year Ended December 31,
thousands except per-unit amounts	2011		2010		2009
Net income attributable to Western Gas Partners, LP	$	174,243	$	146,192	$	116,235
Pre-acquisition net (income) loss allocated to Parent		(34,084)		(32,061)		(44,827)
General partner interest in net (income) loss		(8,599)		(3,067)		(1,428)
Limited partners’ interest in net income	$	131,560	$	111,064	$	69,980
Net income allocable to common units	$	110,542	$	68,410	$	37,035
Net income allocable to subordinated units		21,018		42,654		32,945
Limited partners’ interest in net income	$	131,560	$	111,064	$	69,980
Net income per unit – basic and diluted
Common units	$	1.64	$	1.66	$	1.25
Subordinated units	$	1.28	$	1.61	$	1.24
Weighted average units outstanding – basic and diluted
Common units		67,333		41,287		29,684
Subordinated units		16,431		26,536		26,536

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Partnership Distributions

12 Months Ended

Dec. 31, 2011

Distributions Made to Members or Limited Partners [Abstract]

Partnership Distributions

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

	Total Quarterly
thousands except per-unit amounts	Distribution		Total Cash		Date of
Quarters Ended	per Unit		Distribution		Distribution
2009
March 31	$	0.300	$	17,030	May 2009
June 30	$	0.310	$	17,718	August 2009
September 30	$	0.320	$	18,289	November 2009
December 31	$	0.330	$	21,393	February 2010
2010
March 31	$	0.340	$	22,042	May 2010
June 30	$	0.350	$	24,378	August 2010
September 30	$	0.370	$	26,381	November 2010
December 31	$	0.380	$	30,564	February 2011
2011
March 31	$	0.390	$	33,168	May 2011
June 30	$	0.405	$	36,063	August 2011
September 30	$	0.420	$	40,323	November 2011
December 31 (1)	$	0.440	$	43,027	February 2012

___________________________________________________________________

(1)On January 18, 2012, the board of directors of the Partnership's general partner declared a cash distribution to the Partnership's unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

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, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such 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 (such as the Chipeta LLC agreement), 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.

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. 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	98.0%	2.0%
First target distribution	up to	$	0.345	98.0%	2.0%
Second target distribution	above $ 0.345 up to	$	0.375	85.0%	15.0%
Third target distribution	above $ 0.375 up to	$	0.450	75.0%	25.0%
Thereafter	above	$	0.450	50.0%	50.0%

The table above assumes that the Partnership's general partner maintains its 2.0% 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 common units that it owns or may acquire.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Presentation of partnership assets policy

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of December 31, 2011. Because of Anadarko's control of the Partnership through its ownership of the general partner, each acquisition of Partnership assets, except for the acquisitions of the Platte Valley assets and the 9.6% interest in White Cliffs from third parties, was considered a transfer of net assets between entities under common control (see Note 2). As a result, after each acquisition of assets from Anadarko, the Partnership is required to recast its financial statements to include the activities of the Partnership assets as of the date of common control.

       The consolidated financial statements for periods prior to the Partnership's acquisition of the Partnership assets have been prepared from Anadarko's historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. Net income attributable to the Partnership assets for periods prior to the Partnership's acquisition of such assets is not allocated to the limited partners for purposes of calculating net income per common or subordinated unit.

Use of estimates policy

Use of estimates.In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the amounts reported in the consolidated financial statements and the notes thereto. Management evaluates its estimates and related assumptions regularly, utilizing historical experience and other methods considered reasonable under the circumstances. Changes in facts and circumstancesor additional information, may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership's business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

Fair value policy

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 certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations,and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership 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, the Partnership utilizes the cost, income, or market valuation approach depending on the quality of information available to support management's assumptions.

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 for identical instruments, if available, or average valuations of similar debt instruments at the balance sheet date. See Note 10.

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items.

Cash equivalents policy

Cash equivalents. The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Bad-debt reserve policy

Bad-debt reserve. The Partnership's 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. At December 31, 2011 and 2010, third-party accounts receivable are shown net of the associated bad-debt reserve of $17,000.

Natural gas imbalances policy

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 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, 2011, natural gas imbalance receivables and payables were approximately $2.3 million and $3.1 million, respectively. As of December 31, 2010, natural gas imbalance receivables and payables were approximately $0.4 million and $2.6 million, respectively. Changes in natural gas imbalances are reported in equity income and other, net or cost of product in the consolidated statements of income.

Inventory policy

Inventory. The cost of NGLs inventories is determined by the weighted average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets.

Property, plant and equipment and capitalized interest policy

Property, plant and equipment.Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the Partnership assets acquired by the Partnership from Anadarko are initially recorded at Anadarko's historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to Partners' capital.

Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. 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 that 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, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, 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 reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

The Partnership evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset's carrying amount over its estimated fair value, such that the asset's carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.

During the year ended December 31, 2011, an impairment of $7.3 million was recognized for certain equipment and materials. The costs of the equipment and materials, previously capitalized as assets under construction and related to a Red Desert complex (see Note 2) expansion project, were deemed no longer recoverable as the expansion project was indefinitely postponed by Anadarko management. Subsequent to the project evaluation and impairment, the remaining fair value of the equipment and materials, approximately $10.6 million, was reclassified from within property, plant and equipment to other assets on the consolidated balance sheet as of December 31, 2011. Also during 2011, following an evaluation of future cash flows, an impairment of $3.0 million was recognized for a transportation pipeline. This asset was impaired to fair value, estimated using Level 3 fair-value inputs.

During the year ended December 31, 2010, the Partnership recognized $0.6 million of impairment related to a compressor sold during the year to a third party, and $0.3 million of impairment due to cancelled capital projects and additional costs recorded on a project previously impaired to salvage value. During the year ended December 31, 2009, an impairment of $6.1 million was recognized for an idle pipeline for which no future cash flows were expected.

Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset.

Goodwill policy

Goodwill and other intangible assets.Goodwill represents the allocated portion of Anadarko's midstream goodwill attributed to the assets the Partnership has acquired from Anadarko. The carrying value of Anadarko's midstream goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership's goodwill balance does not reflect, and in some cases is significantly different than, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of the net assets on the acquisition date. The Partnership's consolidated balance sheets as of December 31, 2011 and 2010, include goodwill of$82.1 million, none of which is deductible for tax purposes.

The Partnership evaluates goodwill for impairment annually, as of October 1, or more often as facts and circumstances warrant. The first step in the goodwill impairment test is to compare the fair value of each reporting unit to which goodwill has been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. If the carrying amount of the reporting unit exceeds its fair value, step two in the goodwill impairment test requires goodwill to be written down to its implied fair value through a charge to operating expense based on a hypothetical purchase price allocation. No goodwill impairment has been recognized in these consolidated financial statements. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement.

Equity-method investments policy

Management evaluates its equity-method investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments 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.

Asset retirement obligations and environmental expenditures policy

Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for 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. Over time, the discounted liability is accreted through accretion expense to its expected settlement value. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 9.

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 or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 11.

Segments policy

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

Revenues and cost of product policy

Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are 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 and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers' gas is gathered and delivered to pipelines for market delivery. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate are sold and the related purchases are recorded as a percentage of the product sale.

The Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue gas to either sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue gas. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower as liquids than as a component of the natural gas stream. Revenue is recognized from the sale of condensate and NGLs upon transfer of title and related purchases are recorded as cost of product.

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. Transportation 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 and NGLs 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 (the “FERC”) and reserves are established where appropriate. See Note 11for discussion of the Partnership's pending rate case with the FERC.

Proceeds from the sale of residue gas, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate 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 as revenues from gathering, processing and transportation of natural gas and natural gas liquids in the consolidated statements of income.

Equity-based compensation policy

Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “LTIP”). The LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,160,848 units remain available for future issuance as of December 31, 2011. 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. Equity-based compensation expense attributable to grants made under the LTIP impact the Partnership's cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. 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: (i) Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) and (ii) 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 in 2011 and 2010 were collectively valued at $634.00 per unit and $215.00 per unit as of December 31, 2011 and 2010, respectively. The UVRs and UARs 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 (net of 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. Upon the occurrence of a UAR vesting event, each participant will receive a lump-sum cash payment (net of any applicable withholding taxes) for each UAR that is exercised prior to (i) the 90thday after a participant's voluntary termination, or (ii) the 10th anniversary of the grant date, whichever occurs first. 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.

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. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. For equity-based awards issued under the Incentive Plan and ultimately settled in cash, the fair value of the relevant equity grant is revised periodically based on the estimated fair value of the Partnership's general partner using a discounted cash flow estimate and multiples-valuation terminal value. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact the Partnership's cash flows 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. Equity-based compensation granted under the Anadarko Incentive Plans does not impact the Partnership's cash flows from operating activities. See Note 5.

Income taxes policy

Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Federal and state income tax expense was recorded prior to the Partnership's acquisition of the Partnership assets. In addition, deferred federal and state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases with respect to the Partnership assets prior to the Partnership's acquisition; and deferred state income taxes are recorded with respect to the Partnership assets including and subsequent to acquisition. The recognition of deferred federal and state tax assets prior to the Partnership's acquisition of the Partnership assets was based on management's belief that it was more likely than not that the results of future operations would generate sufficient taxable income to realize the deferred tax assets. For periods including or subsequent to the Partnership's acquisition of the Partnership assets, the Partnership is only subject to Texas margin tax; therefore, deferred federal income tax assets and liabilities with respect to the Partnership assets for periods including and subsequent to the Partnership's acquisitions are no longer recognized by the Partnership.

For periods including and subsequent to the Partnership's acquisition 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 estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, 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 accounting standard for uncertain tax positions 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, 2011 or 2010.

Net income per common unit policy

Net income per common unit. The Partnership applies the two-class method in determining net income per unit applicable to master limited partnerships having multiple classes of securities including common units, general partnership units and incentive distribution rights (“IDRs”) of the general partner. Under the two-class method, net income per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. 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.

The Partnership's net income for periods including and subsequent to the Partnership's acquisitions of the Partnership assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. The Partnership's net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner, common unitholders and subordinated unitholders consistent with actual cash distributions, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and subordinated unitholders in accordance with their respective ownership percentages during each period. See Note 4.

Intangible assets policy

The Partnership assesses intangible assets, as described inNote 8, for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset's carrying amount over its estimated fair value such that the asset's carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense. No intangible asset impairment has been recognized in connection with these assets.

Capital lease, lessor income policy

Other assets. For all periods presented, other assets on the Partnership's consolidated balance sheets include a $0.7 million receivable recognized in conjunction with the capital lease component of a processing agreement assumed in connection with the MGR acquisition. The agreement, in which the Partnership is the lessor, extends through November 2014. Other assets also includes $4.6 million related to the unguaranteed residual value of the processing plant included in the processing agreement, based on a measurement of fair value estimated when the plant was acquired by Anadarko in 2006. Interest income related to the capital lease is recorded to other income (expense), net on the accompanying consolidated statements of income.

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Commitment and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Commitments and Contingencies

Environmental obligations.The Partnership is subject to various environmental-remediation obligations arisingfrom federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and otherenvironmental matters. As of December 31, 2011, the Partnership's consolidated balance sheet included a $1.7 millioncurrent liability and a $1.6 million long-term liability for remediation and reclamation obligations, included in third-party accruedliabilities and asset retirement obligations and other, respectively. As of December 31, 2010, thePartnership's consolidated balance sheet included a $0.6 million current liability and a $0.9 million long-term liability for remediation and reclamation obligations, included in third-party accrued liabilities and asset retirement obligations and other, respectively. The recorded obligations do not include any anticipated insurance recoveries. Substantially all of the payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes the Partnership's environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership's overall results of operations, cash flows or financial condition. There can be noassurance, however, that current regulatory requirements will not change, or past non-compliance with environmentalissues will not be discovered.

Litigation and legal proceedings.In March 2011, DCP Midstream LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering LLC, in Weld County District Court (the “Court”) in Colorado, alleging that Anadarko and its affiliates diverted gas from DCP's gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering LLC, the entity which holds the Wattenberg assets. Anadarko countersued DCP asserting that DCP has not properly allocated values and charges to Anadarko for the gas that DCP gathers and/or processes, and seeks a judgment that DCP has no valid gathering or processing rights to much of the gas production it is claiming, in addition to other claims. In July 2011, the Court denied the defendants' motion to dismiss without ruling on the merits and the case is proceeding to the discovery phase. Management does not believe the outcome of this proceeding will have a material effect on the Partnership's financial condition, results of operations or cash flows. The Partnership intends to vigorously defend this litigation. Furthermore, without regard to the merit of DCP's claims, management believes that the Partnership has adequate contractual indemnities covering the claims against it in this lawsuit.

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

Other commitments. The Partnership has short-term payment obligations, or commitments, related to capital spending programs of the Partnership, as well as its unconsolidated affiliates. As of December 31, 2011, the Partnership had unconditional payment obligations for services to be rendered, or products to be delivered in connection with its capital projects of approximately $30.2 million, primarily related to the construction of a second cryogenic train at the Chipeta plant, all of which will be spent in 2012.

Lease commitments.Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership's operations. The leases for the shared field offices extend through 2018, and the lease for the warehouse extends through March 2012 and includes an early termination clause. The lease for the Partnership's corporate offices expires in January 2012, and during 2011, Anadarko entered into a new agreement for the Partnership's corporate offices that extends through March 2017. Anadarko, on behalf of the Partnership, continues to lease certain other compression equipment under leases expiring through January 2015.

In addition, during 2010, Anadarko and Kerr-McGee Gathering LLC purchased an aggregate $44.5 million of previously leased compression equipment used at the Granger and Wattenberg assets, which terminated the leases and associated lease expense. The purchased compression equipment was contributed to the Partnership pursuant to provisions of the contribution agreements for the Granger and the Wattenberg acquisitions. Rent expense associated with the office, warehouse and equipment leases was approximately $4.1 million, $7.7 million and $10.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2011, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:

thousands	Operating Leases
2012	$	261
2013		228
2014		168
2015		168
2016		168
Thereafter		103
Total	$	1,096

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property Plant And Equipment Abstract

Property, Plant and Equipment

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

		Estimated	December 31,
thousands		Useful Life	2011		2010
Land		n/a	$	364	$	364
Gathering systems		5 to 47 years		2,437,152		2,102,219
Pipelines and equipment		15 to 45 years		90,883		89,778
Assets under construction		n/a		104,687		44,388
Other		3 to 25 years		4,927		3,059
	Total property, plant and equipment			2,638,013		2,239,808
Accumulated depreciation				585,789		486,046
	Net property, plant and equipment		$	2,052,224	$	1,753,762

The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet suitable to be placed into productive service as of the respective balance sheet date. In addition, property, plant and equipment cost, as well as third-party accrued liability balances in the Partnership's consolidated balance sheets include $15.0million and $9.6 million of accrued capital as of December 31, 2011 and 2010, respectively, representing estimated capital expenditures for which invoices had not yet been processed.

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Property, Plant and Equipment - Additional Information (details) (Estimated Capital Expenditures [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Estimated Capital Expenditures [Member]
Property Plant And Equipment Line Items
Accrued capital	$ 15.0	$ 9.6

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Transactions With Affiliates

12 Months Ended

Dec. 31, 2011

Transactions With Affiliates [Abstract]

Transactions with Affiliates

Affiliate transactions.Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue gas, condensate and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operating and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. A portion of the Partnership's general and administrative expenses is paid by Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the omnibus agreement. Affiliate expenses do not inherentlybear a direct relationship to affiliate revenues, and third-party expenses do not necessarily bear a direct relationship to third-party revenues. See Note 2for further information related to contributions of assets to the Partnership by Anadarko.

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

Note receivable from and note payable to Anadarko.Concurrent with the closing of the Partnership's May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was approximately $303.7 million and $258.9 million at December 31, 2011 and 2010, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments.

In December 2008, the Partnership entered into a term loan agreement with Anadarko, discussed further in Note 10.

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold at the Hilight, Hugoton, Newcastle, Granger and Wattenberg assets,with various expiration dates through September 2015.In December 2011, the Partnership extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2013. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. See Note 12 for commodity price swap agreements entered into in December 2011, related to the MGR acquisition, with forward-starting effective dates beginning January 2012.

Below is a summary of the fixed price ranges on the Partnership's commodity price swap agreements outstanding as of December 31, 2011:

	Year Ended December 31,
per barrel except natural gas	2012				2013				2014				2015
Ethane	$	18.21	−	29.78	$	18.32	−	30.10	$	18.36	−	30.53	$	18.41
Propane	$	45.23	−	53.28	$	45.90	−	55.84	$	46.47	−	52.37	$	47.08
Isobutane	$	57.50	−	67.22	$	60.44	−	68.11	$	61.24	−	69.23	$	62.09
Normal butane	$	52.40	−	62.92	$	53.20	−	66.37	$	53.89	−	64.78	$	54.62
Natural gasoline	$	69.77	−	85.15	$	70.89	−	92.23	$	71.85	−	79.74	$	72.88
Condensate	$	72.73	−	78.52	$	74.04	−	83.93	$	75.22	−	79.56	$	76.47	−	78.61
Natural gas (per MMbtu)	$	4.15	−	5.97	$	3.75	−	6.09	$	5.32	−	6.20	$	5.50	−	5.96

The following table summarizes realized gains and losses on commodity price swap agreements:

			Year Ended December 31,
thousands			2011		2010		2009
Gains (losses) on commodity price swap agreements related to sales: (1)
	Natural gas sales		$	33,845	$	20,200	$	18,446
	Natural gas liquids sales			(36,802)		2,953		2,196
		Total		(2,957)		23,153		20,642
Losses on commodity price swap agreements related to purchases (2)				(27,234)		(23,344)		(16,538)
Net gains (losses) on commodity price swap agreements			$	(30,191)	$	(191)	$	4,104

___________________________________________________________________

(1)Reported in natural gas, NGLs and condensate sales in the Partnership's consolidated statements of income in the period in which the related sale is recorded.

(2)Reported in cost of product in the Partnership's consolidated statements of income in the period in which the related purchase is recorded.

Gas gathering and processing agreements. The Partnership has significant gas gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. Approximately 75%, 73% and 76% of the Partnership's gathering, transportation and treating throughput for the years ended December 31, 2011, 2010 and 2009, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 64%, 66% and 58% of the Partnership's processing throughput for the years ended December 31, 2011, 2010 and 2009, respectively, was attributable to natural gas production owned or controlled by Anadarko.

       In connection with the MGR acquisition, the Partnership entered into 10-year, fee-based gathering and processing agreements with Anadarko effective December 1, 2011, for all affiliate throughput on the MGR assets.

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

Omnibus agreement.Pursuant to the omnibus agreement, Anadarko and the general partner perform centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing; and midstream administration. The Partnership's reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership was capped at $9.0 million and $6.9 million for the years ended December 31, 2010 and 2009, respectively. The cap under the omnibus agreement expired on December 31, 2010. Expenses in excess of the cap for the years ended December 31, 2010 and 2009, were recorded as capital contributions from Anadarko and did not impact the Partnership's cash flows. For the year ended December 31, 2011, and thereafter, Anadarko, in accordance with the partnership and omnibus agreements, determined, in its reasonable discretion, amounts to be allocated to the Partnership in exchange for services provided under the omnibus agreement. Such amount was $19.5 million for the year ended December 31, 2011,comprised of $11.8 million of allocated general and administrative expenses and $7.7 million of public company expenses. The Partnership also incurred $8.0 million and $7.5 million in public company expenses not subject to the cap previously contained in the omnibus agreement, excluding equity-based compensation, during the years ended December 31, 2010 and 2009, respectively. See Summary of affiliate transactions below.

Services and secondment agreement.Pursuant to the services and secondment agreement, specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement extends through May 2018 and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination before the applicable twelve-month period expires. The consolidated financial statements of the Partnership include costs allocated by Anadarko pursuant to the services and secondment agreement for periods including and subsequent to the Partnership's acquisition of the Partnership assets.

Tax sharing agreement.Pursuant to a tax sharing agreement, the Partnership reimburses Anadarko for the Partnership's estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, borne by Anadarko on behalf of the Partnership as a result of the Partnership's results being included in a combined or consolidated tax return filed by Anadarko with respect to periods including and subsequent to the Partnership's acquisition of the Partnership assets. Anadarko may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. Nevertheless, the Partnership is required to reimburse Anadarko for its estimated share of taxes 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 incurred by Anadarko 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 the allocation method employed by Anadarko is reasonable. While it is not practicable to determine what these direct and allocated costs would be on a stand-alone basis if the Partnership were to directly obtain these services, management believes these costs would be substantially the same.

Long-term incentive plan.The general partner awarded phantom units under the LTIP primarily to (i) the general partner'sChief Executive Officer and(ii) independent directors in 2011, and primarily to independent directors in 2010 and 2009. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense attributable to the phantom units granted under the LTIP is recognized entirely by the Partnership over the vesting period and was approximately $0.3 million, $0.3 million and $0.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. As of December 31, 2011, there was $0.6 million of unrecognized compensation expense attributable to the LTIP, of which $0.5 million will be allocated to the Partnership,and is expected to be recognized over a weighted-average period of 2.3 years.

The following table summarizes LTIP award activity for the years ended December 31, 2011, 2010 and 2009:

		2011			2010			2009
		Weighted-			Weighted-			Weighted-
		Average			Average			Average
		Grant-Date			Grant-Date			Grant-Date
		Fair Value		Units	Fair Value		Units	Fair Value		Units
Phantom units outstanding
	at beginning of year	$	20.19	17,503	$	15.02	21,970	$	16.50	30,304
Vested		$	20.51	(15,119)	$	15.02	(19,751)	$	16.50	(30,304)
Granted		$	35.66	21,594	$	20.94	15,284	$	15.02	21,970
Phantom units outstanding
	at end of year	$	33.92	23,978	$	20.19	17,503	$	15.02	21,970

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, 2011, 2010 and 2009 included approximately $13.9 million, $5.4 million and $4.1 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.

       As of December 31, 2011, the Partnership estimates that $5.5 million of unrecognized compensation expense attributable to the Incentive Plan will be allocated to the Partnership over a weighted-average period of 1.4 years. In addition, the Partnership estimates that $3.7 million of unrecognized compensation expense attributable to the Anadarko Incentive Plans, excluding performance-based awards, will be allocated to the Partnership over a weighted-average period of 2.0 years. As of December 31, 2011, the compensation cost related to performance-based awards under the Anadarko Incentive Plans that could be allocated to the Partnership during the next three years is approximately $0.1 million.

Equipment purchase and sale. In September 2010, the Partnership sold idle compressors with a net carrying value of $2.6 million to Anadarko for $2.8 million in cash. The gain on the sale was recorded as an adjustment to Partners' capital. In November 2010, the Partnership purchased compressors with a net carrying value of $0.4 million from Anadarko for $0.4 million in cash.

In November 2011, the Partnership purchased equipment with a net carrying value of $2.0 million from Anadarko for $3.8 million in cash, with the difference recorded as an adjustment to Partners' capital.

Summary of affiliate transactions.Affiliate transactions include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas. The following table summarizes affiliate transactions, including transactions with Anadarko, its affiliates and the general partner:

		Year Ended December 31,
thousands		2011		2010		2009
Revenues (1)		$	648,997	$	571,628	$	521,850
Cost of product (1)			83,722		95,667		94,999
Operation and maintenance (2)			51,339		46,379		41,444
General and administrative (3)			31,855		23,807		27,408
	Operating expenses		166,916		165,853		163,851
Interest income, net (4)			28,560		20,243		20,717
Interest expense (5)			4,935		6,924		9,096
Distributions to unitholders (6)			68,039		52,337		44,450
Contributions from noncontrolling interest owners			16,476		2,019		34,011
Distributions to noncontrolling interest owners			9,437		6,476		5,410

____________________________________________________________

(1)Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

(2)Represents expenses incurred under the services and secondment agreement, as applicable.

(3)Represents general and administrative expense incurred under the omnibus agreement, as applicable.

(4)Represents interest income recognized on the note receivable from Anadarko. This line item also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

(5)Represents interest expense recognized on the note payable to Anadarko.

(6)Represents distributions paid under the partnership agreement.

Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership's consolidated revenues for all periods presented on the Partnership's consolidated statements of income.

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Tax Expense (Benefit) [Abstract]

Income Taxes

The components of the Partnership's income tax expense (benefit) are as follows:

		Year Ended December 31,
thousands		2011		2010		2009
Current income tax expense (benefit)
	Federal income tax expense (benefit)	$	15,890	$	10,580	$	20,253
	State income tax expense		524		1,534		1,856
	Total current income tax expense (benefit)		16,414		12,114		22,109
Deferred income tax expense (benefit)
	Federal income tax expense (benefit)		2,464		9,709		696
	State income tax expense (benefit)		140		(121)		(646)
	Total deferred income tax expense (benefit)		2,604		9,588		50
Total income tax expense		$	19,018	$	21,702	$	22,159

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,
thousands except percentages		2011		2010		2009
Income before income taxes		$	207,364	$	178,899	$	148,654
Statutory tax rate			0%		0%		0%
Tax computed at statutory rate		$	—	$	—	$	—
Adjustments resulting from:
	Federal taxes on income attributable to Partnership assets pre-acquisition		18,354		20,678		21,407
	State taxes on income attributable to Partnership assets pre-acquisition
	(net of federal benefit)		—		724		852
	Texas margin tax expense (benefit)		664		300		(100)
Income tax expense		$	19,018	$	21,702	$	22,159
Effective tax rate			9%		12%		15%

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

	December 31,
thousands	2011		2010
Credit carryforwards	$	14	$	14
Other		—		2
Net current deferred income tax assets		14		16
Depreciable property		(83,566)		(100,889)
Partnership basis		(24,481)		(26,320)
Credit carryforwards		556		570
Other		114		(207)
Net long-term deferred income tax liabilities		(107,377)		(126,846)
Total net deferred income tax liabilities	$	(107,363)	$	(126,830)

Credit carryforwards, which are available for utilization on future income tax returns, consist of $0.6 million of state income tax credits that expire in 2026.

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Other Intangible Assets

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangible Assets

The intangible asset balance in the Partnership's consolidated balance sheets represents the fairvalue, net of amortization, related to the contracts assumed bythe Partnership in connection with the Platte Valley acquisition in February 2011, which dedicate certaincustomers' field production to the acquired gathering and processing system. These long-term contracts provide anextended commercial relationship with the existing customers whereby the Partnership will have the opportunity to gather and processfutureproduction from the customers' acreage.Thesecontractsare generally limited, however, by the quantity and production life of the underlying natural gas resource base.

At December 31, 2011, the carrying value of the Partnership's customer relationship intangible assets was$52.9 million, net of $0.9million of accumulated amortization, and was included in goodwill and other intangible assets in the Partnership's consolidated balance sheets. Customer relationships are amortized on a straight-line basis over 50 years, which is the estimated productive life of the reserves covered by the underlying acreageultimately expected to be produced and gathered or processed through the Partnership's assets subject to current contractual arrangements. No intangible asset impairment has been recognized in connection with these assets (see Note 1).

Estimated future amortization for these intangible assets over the next five years is as follows:

	Future
thousands	Amortization
2012	$	1,075
2013		1,075
2014		1,075
2015		1,075
2016		1,075

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Debt and Interest Expense - Debt Outstanding Table (details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009	Dec. 31, 2010 Revolving Credit Facility [Member]	Dec. 31, 2011 5.375% Senior Notes due 2021	May 31, 2011 5.375% Senior Notes due 2021	Dec. 31, 2010 Wattenberg Term Loan [Member]	Aug. 31, 2010 Wattenberg Term Loan [Member]	Dec. 31, 2011 Note Payable To Anadarko [Member]	Dec. 31, 2010 Note Payable To Anadarko [Member]	Dec. 31, 2008 Note Payable To Anadarko [Member]
Debt Instrument Line Items
Principal	$ 675,000,000	[1]	$ 474,000,000	[1]		$ 49,000,000	$ 500,000,000	$ 500,000,000	$ 250,000,000	$ 250,000,000	$ 175,000,000	$ 175,000,000	$ 175,000,000
Carrying Value	669,178,000	[1]	474,000,000	[1]	175,000,000	49,000,000	494,178,000		250,000,000		175,000,000	175,000,000
Fair Value	674,478,000	[1]	467,116,000	[1]		49,000,000	499,950,000		250,000,000		174,528,000	168,116,000
Table Text Block Supplement Abstract
Accrued interest expense	$ 2,700,000		$ 1,300,000

[1] The Partnership’s consolidated balance sheets include accrued interest expense of $2.7 million and $1.3 million as of December 31, 2011 and 2010, respectively, which is included in accrued liabilities.

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Debt and Interest Expense - Interest Expense Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Debt Instrument Line Items
Interest Expense	$ 30,345	[1],[2]	$ 18,794	[1],[2]	$ 9,955	[1],[2]
Third Parties [Member]
Debt Instrument Line Items
Interest expense on long-term debt	20,533		8,530		304
Amortization of debt issuance costs and commitment fees Credit facility commitment fees	5,297	[3]	3,340	[3]	555	[3]
Capitalized interest	(420)
Interest Expense	25,410		11,870		859
Affiliated Entity Member
Debt Instrument Line Items
Interest expense on note payable to Anadarko	4,935		6,828		8,953
Amortization of debt issuance costs and commitment fees Credit facility commitment fees			96		143
Interest Expense	$ 4,935	[4]	$ 6,924	[4]	$ 9,096	[4]

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Includes affiliate (as defined in Note 1) interest expense of $4.9 million, $6.9 million and $9.1 million for years ended December 31, 2011, 2010 and 2009, respectively. See Note 10.

[3] For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees related to the Notes.

[4] Represents interest expense recognized on the note payable to Anadarko.

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Asset Retirement Obligations (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Carrying amount of asset retirement obligations at beginning of year	$ 44,777	$ 55,862
Liabilities incurred	15,390	800
Liabilities settled		(104)
Accretion expense	3,781	3,740
Revisions in estimated liabilities	(679)	(15,521)
Carrying amount of asset retirement obligations at end of year	$ 63,269	$ 44,777

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Commitments and Contingencies (table)

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

thousands	Operating Leases
2012	$	261
2013		228
2014		168
2015		168
2016		168
Thereafter		103
Total	$	1,096

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Transactions With Affiliates - Gains Losses Commodity Price Swap Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ (30,191)		$ (191)		$ 4,104
Sales Member
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	(2,957)	[1]	23,153	[1]	20,642	[1]
Related to purchases
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	(27,234)	[2]	(23,344)	[2]	(16,538)	[2]
Natural gas sales | Sales Member
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	33,845	[1]	20,200	[1]	18,446	[1]
Natural Gas Liquids [Member] | Sales Member
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ (36,802)	[1]	$ 2,953	[1]	$ 2,196	[1]

[1] Reported in natural gas, NGLs and condensate sales in the Partnership’s consolidated statements of income in the period in which the related sale is recorded.

[2] Reported in cost of product in the Partnership’s consolidated statements of income in the period in which the related purchase is recorded.

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Condensed Consolidating Financial Statements

12 Months Ended

Dec. 31, 2011

Condensed Consolidating Financial Statements [Abstract]

Condensed Consolidating Financial Statements

The Partnership may issue an indeterminate amount of common units and various debt securities under its effective shelf registration statement on file with the SEC. The Notesare, and any future debt securities issued under such registration statement may be, guaranteed by the Subsidiary Guarantors. The guaranteesare full, unconditional, joint and several. The following condensed consolidating financial information reflects the Partnership's stand-alone accounts, the combined accounts of the Subsidiary Guarantors, the accounts of the Non-Guarantor Subsidiary, consolidating adjustments, and eliminations and the Partnership's consolidated financial information. Thecondensed consolidating financial information should be read in conjunction with the Partnership's accompanyingconsolidated financial statements and related notes.

Western Gas Partners, LP's and the Subsidiary Guarantors' investment in and equity income from their subsidiaries are presented in accordance with the equity method of accounting in which the equity income from 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, 2011
		Western				Non-
		Gas		Subsidiary		Guarantor
thousands		Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Revenues		$	(2,957)	$	756,764	$	69,458	$	—	$	823,265
Operating expenses			61,009		512,374		40,689		—		614,072
Operating income (loss)			(63,966)		244,390		28,769		—		209,193
Interest income, net – affiliates			16,900		11,693		—		(33)		28,560
Interest expense			(30,378)		—		—		33		(30,345)
Other income (expense), net			(1,745)		1,689		12		—		(44)
Equity income			219,349		14,678		—		(234,027)		—
Income before income taxes			140,160		272,450		28,781		(234,027)		207,364
Income tax expense			—		19,018		—		—		19,018
Net income			140,160		253,432		28,781		(234,027)		188,346
Net income attributable to
	noncontrolling interests		—		14,103		—		—		14,103
Net income attributable to
	Western Gas Partners, LP	$	140,160	$	239,329	$	28,781	$	(234,027)	$	174,243

		Statement of Income
		Year Ended December 31, 2010
		Western				Non-
		Gas		Subsidiary		Guarantor
thousands		Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Revenues		$	23,153	$	596,033	$	44,088	$	—	$	663,274
Operating expenses			44,593		419,058		21,635		—		485,286
Operating income (loss)			(21,440)		176,975		22,453		—		177,988
Interest income, net – affiliates			16,900		3,374		—		(31)		20,243
Interest expense			(18,825)		—		—		31		(18,794)
Other income (expense), net			(2,331)		1,787		6		—		(538)
Equity income			139,613		11,454		—		(151,067)		—
Income before income taxes			113,917		193,590		22,459		(151,067)		178,899
Income tax expense			—		21,702		—		—		21,702
Net income			113,917		171,888		22,459		(151,067)		157,197
Net income attributable to
	noncontrolling interests		—		11,005		—		—		11,005
Net income attributable to
	Western Gas Partners, LP	$	113,917	$	160,883	$	22,459	$	(151,067)	$	146,192

		Statement of Income
		Year Ended December 31, 2009
		Western				Non-
		Gas		Subsidiary		Guarantor
thousands		Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Revenues		$	20,642	$	557,115	$	42,007	$	—	$	619,764
Operating expenses			34,602		427,820		21,078		—		483,500
Operating income (loss)			(13,960)		129,295		20,929		—		136,264
Interest income, net – affiliates			16,900		3,834		—		(17)		20,717
Interest expense			(9,972)		—		—		17		(9,955)
Other income (expense), net			32		1,586		10		—		1,628
Equity income			78,408		5,138		—		(83,546)		—
Income before income taxes			71,408		139,853		20,939		(83,546)		148,654
Income tax expense			—		22,159		—		—		22,159
Net income			71,408		117,694		20,939		(83,546)		126,495
Net income attributable to
	noncontrolling interests		—		10,260		—		—		10,260
Net income attributable to
	Western Gas Partners, LP	$	71,408	$	107,434	$	20,939	$	(83,546)	$	116,235

	Balance Sheet
	December 31, 2011
	Western				Non-
	Gas		Subsidiary		Guarantor
thousands	Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Current assets	$	207,913	$	110,619	$	25,977	$	(88,061)	$	256,448
Note receivable – Anadarko		260,000		—		—		—		260,000
Investment in consolidated
subsidiaries		1,232,245		130,396		—		(1,362,641)		—
Net property, plant and equipment		735		1,812,275		239,214		—		2,052,224
Other long-term assets		8,164		260,790		—		—		268,954
Total assets	$	1,709,057	$	2,314,080	$	265,191	$	(1,450,702)	$	2,837,626
Current liabilities	$	95,817	$	56,762	$	12,078	$	(88,061)	$	76,596
Long-term debt		669,178		—		—		—		669,178
Deferred income taxes		—		107,377		—		—		107,377
Asset retirement obligations and other		104		64,980		2,085		—		67,169
Total liabilities		765,099		229,119		14,163		(88,061)		920,320
Partners’ capital		943,958		1,964,237		251,028		(1,362,641)		1,796,582
Noncontrolling interests		—		120,724		—		—		120,724
Total liabilities, equity
and partners’ capital	$	1,709,057	$	2,314,080	$	265,191	$	(1,450,702)	$	2,837,626

	Balance Sheet
	December 31, 2010
	Western				Non-
	Gas		Subsidiary		Guarantor
thousands	Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Current assets	$	24,972	$	209,649	$	10,346	$	(200,342)	$	44,625
Note receivable – Anadarko		260,000		—		—		—		260,000
Investment in consolidated
subsidiaries		1,052,073		97,018		—		(1,149,091)		—
Net property, plant and equipment		165		1,572,383		181,214		—		1,753,762
Other long-term assets		2,361		202,346		—		—		204,707
Total assets	$	1,339,571	$	2,081,396	$	191,560	$	(1,349,433)	$	2,263,094
Current liabilities	$	201,989	$	47,946	$	2,127	$	(200,342)	$	51,720
Long-term debt		474,000		—		—		—		474,000
Deferred income taxes		—		126,846		—		—		126,846
Asset retirement obligations and other		38		46,507		1,954		—		48,499
Total liabilities		676,027		221,299		4,081		(200,342)		701,065
Partners’ capital		663,544		1,769,635		187,479		(1,149,091)		1,471,567
Noncontrolling interests		—		90,462		—		—		90,462
Total liabilities, equity
and partners’ capital	$	1,339,571	$	2,081,396	$	191,560	$	(1,349,433)	$	2,263,094

		Statement of Cash Flows
		Year Ended December 31, 2011
		Western				Non-
		Gas		Subsidiary		Guarantor
thousands		Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Net income		$	140,160	$	253,432	$	28,781	$	(234,027)	$	188,346
Adjustments to reconcile net income to
	net cash provided by operating activities:
	Equity income		(219,349)		(14,678)		—		234,027		—
	Depreciation, amortization and impairments		55		106,230		5,619		—		111,904
	Change in other items, net		(93,715)		118,719		1,917		—		26,921
Net cash provided by
	(used in) operating activities		(172,849)		463,703		36,317		—		327,171
Net cash used in investing activities			(25,416)		(409,715)		(55,384)		17,564		(472,951)
Net cash provided by
	(used in) financing activities		382,049		(53,988)		34,768		(17,564)		345,265
Net increase (decrease) in cash and cash
	equivalents		183,784		—		15,701		—		199,485
Cash and cash equivalents
	at beginning of period		21,479		—		5,595		—		27,074
Cash and cash equivalents at end of period		$	205,263	$	—	$	21,296	$	—	$	226,559

		Statement of Cash Flows
		Year Ended December 31, 2010
		Western				Non-
		Gas		Subsidiary		Guarantor
thousands		Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Net income		$	113,917	$	171,888	$	22,459	$	(151,067)	$	157,197
Adjustments to reconcile net income to
	net cash provided by operating activities:
	Equity income		(139,613)		(11,454)		—		151,067		—
	Depreciation, amortization and impairments		54		85,199		5,757		—		91,010
	Change in other items, net		149,408		(130,554)		(3,312)		—		15,542
Net cash provided by operating activities			123,766		115,079		24,904		—		263,749
Net cash used in investing activities			(734,780)		(147,924)		(2,803)		—		(885,507)
Net cash provided by
	(used in) financing activities		570,863		32,845		(24,860)		—		578,848
Net increase (decrease) in cash and
	cash equivalents		(40,151)		—		(2,759)		—		(42,910)
Cash and cash equivalents
	at beginning of period		61,630		—		8,354		—		69,984
Cash and cash equivalents at end of period		$	21,479	$	—	$	5,595	$	—	$	27,074

		Statement of Cash Flows
		Year Ended December 31, 2009
		Western				Non-
		Gas		Subsidiary		Guarantor
thousands		Partners, LP		Guarantors		Subsidiary		Eliminations		Consolidated
Net income		$	71,408	$	117,694	$	20,939	$	(83,546)	$	126,495
Adjustments to reconcile net income to
	net cash provided by operating activities:
	Equity income		(78,408)		(5,138)		—		83,546		—
	Depreciation, amortization and impairments		54		86,134		4,504		—		90,692
	Change in other items, net		2,112		(3,946)		(15,081)		12,493		(4,422)
Net cash provided by
	(used in) operating activities		(4,834)		194,744		10,362		12,493		212,765
Net cash used in investing activities			—		(183,750)		(39,378)		—		(223,128)
Net cash provided by
	(used in) financing activities		33,157		(10,994)		34,603		(12,493)		44,273
Net increase (decrease) 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

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Partnership Distributions (tables)

12 Months Ended

Dec. 31, 2011

Distributions Made to Members or Limited Partners [Abstract]

Cash Distributions Table

	Total Quarterly
thousands except per-unit amounts	Distribution		Total Cash		Date of
Quarters Ended	per Unit		Distribution		Distribution
2009
March 31	$	0.300	$	17,030	May 2009
June 30	$	0.310	$	17,718	August 2009
September 30	$	0.320	$	18,289	November 2009
December 31	$	0.330	$	21,393	February 2010
2010
March 31	$	0.340	$	22,042	May 2010
June 30	$	0.350	$	24,378	August 2010
September 30	$	0.370	$	26,381	November 2010
December 31	$	0.380	$	30,564	February 2011
2011
March 31	$	0.390	$	33,168	May 2011
June 30	$	0.405	$	36,063	August 2011
September 30	$	0.420	$	40,323	November 2011
December 31 (1)	$	0.440	$	43,027	February 2012

_______________________________________________________________

(1)On January 18, 2012, the board of directors of the Partnership's general partner declared a cash distribution to the Partnership's unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

Incentive Distribution Rights Table

				Marginal Percentage
	Total Quarterly Distribution			Interest in Distributions
	Target Amount			Unitholders	General Partner
Minimum quarterly distribution		$	0.300	98.0%	2.0%
First target distribution	up to	$	0.345	98.0%	2.0%
Second target distribution	above $ 0.345 up to	$	0.375	85.0%	15.0%
Third target distribution	above $ 0.375 up to	$	0.450	75.0%	25.0%
Thereafter	above	$	0.450	50.0%	50.0%

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Equity and Partners' Capital - Additional Information (details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Investments Line Items
General partner units owned	1,839,613	1,583,128
General partner's interest	2.00%
Conversion of subordinated units	26,536,306
Subordinated Units End Date	8/15/2011
Subordinated Units Effective End Date	7/1/2011
Anadarko [Member]
Schedule Of Investments Line Items
General partner units owned	1,839,613
General partner's interest	2.00%
Ownership interest	43.30%
Public [Member]
Schedule Of Investments Line Items
Ownership interest	54.70%
Common [Member]
Schedule Of Investments Line Items
Units owned	90,140,999	51,036,968
Common [Member] | Anadarko [Member]
Schedule Of Investments Line Items
Units owned	39,789,221
Ownership interest	43.30%
Common [Member] | Public [Member]
Schedule Of Investments Line Items
Units owned	50,351,778
Ownership interest	54.70%
Subordinated [Member]
Schedule Of Investments Line Items
Units owned		26,536,306
Incentive Distribution Rights [Member] | Anadarko [Member]
Schedule Of Investments Line Items
Ownership interest	100.00%

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Acquisitions - Pro Forma Condensed Financial Information Table (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Business Combinations [Abstract]
Revenues	$ 839,304
Net income	191,072
Net income attributable to Western Gas Partners, LP	$ 176,969
Earnings per common unit - basic and diluted	$ 1.67

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Consolidated Balance Sheet (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
General partner units outstanding	1,839,613		1,583,128
Accounts receivable, net	$ 22,703	[1],[2]	$ 11,607	[1],[2]
Other current assets	7,186	[2],[3]	5,944	[2],[3]
Accounts and natural gas imbalance payables	26,600	[2],[4]	17,058	[2],[4]
Accrued liabilities	41,315	[2],[5]	28,240	[2],[5]
Subordinated Units End Date	8/15/2011
Affiliates
Accounts receivable, net			1,800
Other current assets	500
Accounts and natural gas imbalance payables	5,900		1,500
Accrued liabilities	$ 300		$ 600
Common [Member]
Units outstanding	90,140,999		51,036,968
Subordinated [Member]
Units outstanding			26,536,306

[1] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of zero and $1.8 million as of December 31, 2011 and 2010, respectively.

[2] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[3] Other current assets includes natural gas imbalance receivables from affiliates of $0.5 million and zero as of December 31, 2011 and 2010, respectively.

[4] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $5.9 million and $1.5 million as of December 31, 2011 and 2010, respectively.

[5] Accrued liabilities include amounts payable to affiliates of $0.3 million and $0.6 million as of December 31, 2011 and 2010, respectively.

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Acquisitions

12 Months Ended

Dec. 31, 2011

Business Combinations [Abstract]

Acquisitions

The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2011, 2010 and 2009, anddetails the funding for those acquisitions through borrowings, cash on hand and/or the issuance of Partnership equity:

thousands except unit and		Acquisition	Percentage			Cash		Common	GP Units
	percent amounts	Date	Acquired	Borrowings		On Hand		Units Issued	Issued
Chipeta (1)		07/01/09	51%	$	101,451	$	4,638	351,424	7,172
Granger (2)		01/29/10	100%		210,000		31,680	620,689	12,667
Wattenberg (3)		08/02/10	100%		450,000		23,100	1,048,196	21,392
White Cliffs (4)		09/28/10	10%		—		38,047	—	—
Platte Valley (5)		02/28/11	100%		303,000		602	—	—
Bison (6)		07/08/11	100%		—		25,000	2,950,284	60,210

____________________________________________________________

(1)The assets acquired from Anadarko include a 51% membership interest in Chipeta, together with an associated NGL pipeline. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. Chipeta owns a natural gas processing plant with two processing trains: a refrigeration unit and a cryogenic unit. In addition, in November 2009, Chipeta acquired the Natural Buttes plant including a compressor station and processing plant from a third party for $9.1 million, of which $4.5 million was contributed by the noncontrolling interest owners to fund their proportionate share. 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.”

(2)The assets acquired from Anadarkoinclude (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of cryogenic trains, a refrigeration train, an NGLs fractionation facility and ancillary equipment. These assets, located in southwestern Wyoming, are referred to collectively as the “Granger assets”and the acquisition as the “Granger acquisition.”

(3)The assets acquired from Anadarko include the Wattenberg gathering system and related facilities, including the Fort Lupton processing plant. These assets, located in the Denver-JulesburgBasin, north and east of Denver, Colorado, are referred to collectively as the “Wattenberg assets”and the acquisition as the “Wattenberg acquisition.”

(4)White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma, whichbecame operational in June 2009. The Partnership's acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko combined with the acquisition of an additional 9.6% interest in White Cliffs from a third party, are referred to collectively as the “White Cliffs acquisition.” The Partnership's interest in White Cliffs is referred to as the “White Cliffs investment.”

(5)The assets acquired from a third partyinclude (i) a natural gas gathering system and related compression and other ancillary equipment, and (ii) cryogenic gas processing facilities. These assets, located in the Denver-Julesburg Basin, are referred to collectively as the “Platte Valley assets”and the acquisition as the “Platte Valley acquisition.” See further information below, including the final allocation of the purchase price in August 2011.

(6)The Bison gas treating facility acquired from Anadarko is located in the Powder River Basin in northeastern Wyoming, and includes (i) three amine treating units, (ii) compressor units, and (iii) generators.These assets are referred to collectively as the “Bison assets” and the acquisition as the “Bison acquisition.”The Bison assets are the only treating and delivery point into the third-party-owned Bison pipeline. Anadarko began construction of the Bison assets in 2009 and placed them in service in June 2010. See further information below.

Platte Valley acquisition.The PlatteValleyacquisition has been accounted for under the acquisition method of accounting. The Platte Valley assets and liabilities were recorded in the consolidated balance sheetat their estimated fair values as of the acquisition date. Results of operations attributable tothe PlatteValley assets were included in the Partnership's consolidated statements of income beginning on the acquisition date in the first quarter of 2011.

The table below reflects the final allocation of the purchase price, including a $1.6 million adjustment to intangible assets recorded in August 2011, to the assets acquired and liabilities assumed in the Platte Valley acquisition:

thousands
Property, plant and equipment	$	264,521
Intangible assets		53,754
Asset retirement obligations and other liabilities		(16,318)
Total purchase price	$	301,957

The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the Platte Valley acquisition, after consideration of post-closing purchase price adjustments. The fair values of the plant and processing facilities,related equipment, and intangible assetsacquired were based on the market,costand income approaches. The liabilities assumed include certain amounts associated with environmental contingencies estimated by management. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs.For more information regarding the intangible assets presented in the table above, see Note8.

The following table presents the pro forma condensed financial information of the Partnershipas if the Platte Valley acquisition had occurred on January 1, 2011:

	Year Ended
thousands except per-unit amount	December 31, 2011
Revenues	$	839,304
Net income		191,072
Net income attributable to Western Gas Partners, LP		176,969
Net income per common unit – basic and diluted	$	1.67

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership's pro forma information in the table above includes $83.4million of revenues and $59.1 million of operating expenses, excluding depreciation, amortization and impairments, attributable to the Platte Valley assetsthat are included in the Partnership's consolidated statement of income for the year ended December 31, 2011.The pro forma adjustments reflect pre-acquisition results of the Platte Valley assets for January and February 2011, including (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the purchase price allocated to property, plant and equipment and other intangible assets and estimated useful lives; (c) elimination of $0.7million of acquisition-related costs; and (d) interest on the Partnership's borrowings under its revolving credit facility to finance the Platte Valley acquisition.The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transactions are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the acquisition,nor any future acquisition related expenses. Pro forma information is not presented for periods ended on or before December 31, 2010,as it is not practical to determine revenues and cost of productfor periods prior to January 1, 2011, the effective date of the gathering and processing agreement with the seller.

Bison and MGR acquisitions.On January 13, 2012, the Partnership completed the acquisition of Anadarko's 100% ownership interest in MGR which owns the Red Desert complex, a 22% interest in Rendezvous and related facilities, effective January 1, 2012. The Red Desert complex includes the Patrick Draw processing plant, the Red Desert processing plant, 1,295 miles of gathering lines and related facilities. Rendezvous owns a 338-mile mainline gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, which delivers gas to the Granger complex and other locations. These assets are referred to collectively as the “MGR assets” and the acquisition as the “MGR acquisition.” Consideration paid includes: (i) $159.6 million of cash on hand, (ii) $299.0 million borrowings on the Partnership's senior unsecured revolving credit facility, and (iii) the issuance of 632,783 common units and 12,914 general partner units.

As transfers of net assets between entities under common control, the Partnership's historical financial statements previously filed with the U.S. Securities and Exchange Commission (“SEC”) have been recast in this Current Report on Form 8-K to include the results attributable to the Bison and MGR assets as if the Partnership owned such assets for all periods presented.The consolidated financial statements for periods prior to the Partnership's acquisition of the Partnership assets have been prepared from Anadarko's historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

The following tables present the impact to the historical consolidated statements of income attributable to the Bison and MGR assets, including the elimination of intercompany activity between such assets:

	Year Ended December 31, 2010
	Partnership		Bison		MGR
thousands	Historical		Assets		Assets		Eliminations		Combined
Revenues	$	503,322	$	1,879	$	158,135	$	(62)	$	663,274
Net income (loss)		137,073		(3,194)		23,318		—		157,197
	Year Ended December 31, 2009
	Partnership		Bison		MGR
thousands	Historical		Assets		Assets		Eliminations		Combined
Revenues	$	490,546	$	—	$	129,218	$	—	$	619,764
Net income (loss)		118,166		(657)		8,986		—		126,495

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Income Taxes - Additional Information (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Tax Credit Carryforward [Line Items]
Credit carryforwards	$ 556	$ 570
Tax Credit Carryforward, Expiration Dates	2026

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Commitment and Contingencies - Additional Information (details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Loss Contingencies [Line Items]
Current liability for remediation and reclamation obligations	$ 1.7	$ 0.6
Long-term liability for remediation and reclamation obligations	1.6	0.9
Term Of Payments On Environmental Obligations In Years		5 years
Capital commitments	30.2
Rent expense associated with office and equipment leases	4.1	7.7	10.2
Anadarko [Member]
Loss Contingencies [Line Items]
Purchase of previously leased compression equipment		$ 44.5

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Equity and Partners' Capital (tables)

12 Months Ended

Dec. 31, 2011

Partners Capital Notes Abstract

Equity Offerings Table

						Underwriting
						Discount and
thousands except unit		Common	GP Units	Price Per		Other Offering		Net
	and per-unit amounts	Units Issued (2)	Issued (3)	Unit		Expenses		Proceeds
December 2009 equity offering		6,900,000	140,817	$	18.20	$	5,500	$	122,539
May 2010 equity offering (1)		4,558,700	93,035		22.25		4,427		99,074
November 2010 equity offering		8,415,000	171,734		29.92		10,325		246,729
March 2011 equity offering		3,852,813	78,629		35.15		5,621		132,569
September 2011 equity offering		5,750,000	117,347		35.86		7,655		202,748

_______________________________________________________

(1)Refers collectively to the May 2010 equity offering issuance, and the June 2010 exercise of the underwriters' over-allotment option.

(2)Includes the issuance of 900,000 common units, 558,700 common units, 915,000 common units, 302,813 common units and 750,000 common units pursuant to the exercise, in full or in part, of the underwriters' over-allotment options granted in connection with the December 2009, May 2010, November 2010, March 2011 and September 2011 equity offerings, respectively.

(3)Represents general partner units issued to the general partner in exchange for the general partner's proportionate capital contribution to maintain its 2.0% interest.

Calculation of Net Income Per Unit Table

	Year Ended December 31,
thousands except per-unit amounts	2011		2010		2009
Net income attributable to Western Gas Partners, LP	$	174,243	$	146,192	$	116,235
Pre-acquisition net (income) loss allocated to Parent		(34,084)		(32,061)		(44,827)
General partner interest in net (income) loss		(8,599)		(3,067)		(1,428)
Limited partners’ interest in net income	$	131,560	$	111,064	$	69,980
Net income allocable to common units	$	110,542	$	68,410	$	37,035
Net income allocable to subordinated units		21,018		42,654		32,945
Limited partners’ interest in net income	$	131,560	$	111,064	$	69,980
Net income per unit – basic and diluted
Common units	$	1.64	$	1.66	$	1.25
Subordinated units	$	1.28	$	1.61	$	1.24
Weighted average units outstanding – basic and diluted
Common units		67,333		41,287		29,684
Subordinated units		16,431		26,536		26,536

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Supplemental Quarterly Information (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended						3 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009		Dec. 31, 2011 Supplemental Quarterly Financial Data [Member]	Sep. 30, 2011 Supplemental Quarterly Financial Data [Member]	Jun. 30, 2011 Supplemental Quarterly Financial Data [Member]	Mar. 31, 2011 Supplemental Quarterly Financial Data [Member]	Dec. 31, 2010 Supplemental Quarterly Financial Data [Member]	Sep. 30, 2010 Supplemental Quarterly Financial Data [Member]	Jun. 30, 2010 Supplemental Quarterly Financial Data [Member]	Mar. 31, 2010 Supplemental Quarterly Financial Data [Member]	Dec. 31, 2011 Common Units Supplemental Quarterly Financial Data [Member]		Sep. 30, 2011 Common Units Supplemental Quarterly Financial Data [Member]		Jun. 30, 2011 Common Units Supplemental Quarterly Financial Data [Member]		Mar. 31, 2011 Common Units Supplemental Quarterly Financial Data [Member]		Dec. 31, 2010 Common Units Supplemental Quarterly Financial Data [Member]		Sep. 30, 2010 Common Units Supplemental Quarterly Financial Data [Member]		Jun. 30, 2010 Common Units Supplemental Quarterly Financial Data [Member]		Mar. 31, 2010 Common Units Supplemental Quarterly Financial Data [Member]		Jun. 30, 2011 Subordinated Units Supplemental Quarterly Financial Data [Member]		Mar. 31, 2011 Subordinated Units Supplemental Quarterly Financial Data [Member]		Dec. 31, 2010 Subordinated Units Supplemental Quarterly Financial Data [Member]		Sep. 30, 2010 Subordinated Units Supplemental Quarterly Financial Data [Member]		Jun. 30, 2010 Subordinated Units Supplemental Quarterly Financial Data [Member]		Mar. 31, 2010 Subordinated Units Supplemental Quarterly Financial Data [Member]
Selected Quarterly Financial Information [Line Items]
Revenues	$ 823,265	[1]	$ 663,274	[1]	$ 619,764	[1]	$ 215,197	$ 217,546	$ 209,680	$ 180,842	$ 163,025	$ 163,139	$ 165,915	$ 171,195
Operating income	209,193	[1]	177,988	[1]	136,264	[1]	46,094	53,946	58,181	50,972	49,530	41,335	44,394	42,729
Net income attributable to Western Gas Partners, LP	$ 174,243	[1]	$ 146,192	[1]	$ 116,235	[1]	$ 40,014	$ 45,306	$ 45,026	$ 43,897	$ 41,666	$ 36,189	$ 33,890	$ 34,447
Net income per unit - basic and diluted															$ 0.35	[2]	$ 0.41	[2]	$ 0.40	[2]	$ 0.43	[2]	$ 0.48	[2]	$ 0.44	[2]	$ 0.35	[2]	$ 0.37	[2]	$ 0.38	[2]	$ 0.41	[2]	$ 0.44	[2]	$ 0.44	[2]	$ 0.35	[2]	$ 0.37	[2]

[1] Financial information for the year ended December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information for the years ended December 31, 2010 and 2009, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

[2] Represents net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). In addition, all subordinated units were converted to common units on a one-for-one basis on August 15, 2011. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4. Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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Summary of Significant Accounting Policies - Additional Information (details) (USD $)					12 Months Ended									12 Months Ended										12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2011 Newcastle [Member]	Dec. 31, 2011 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2011 White Cliffs [Member]	Dec. 31, 2011 Fort Union [Member]	Dec. 31, 2011 Long Term Incentive Plan [Member]	Dec. 31, 2011 Incentive Plan [Member]	Dec. 31, 2010 Incentive Plan [Member]	Dec. 31, 2011 Rendezvous [Member]	Dec. 31, 2011 Affiliated Entity Member Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2011 Affiliated Entity Member White Cliffs [Member]	Dec. 31, 2011 Third Parties [Member] Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2011 Gathering System [Member]	Dec. 31, 2011 Natural Gas Treating Facilities [Member]	Dec. 31, 2011 Natural Gas Processing Facilities [Member]	Dec. 31, 2011 Natural Gas Liquids Pipeline [Member]	Dec. 31, 2011 Interstate Pipeline [Member]	Dec. 31, 2011 Equity Method Investee [Member]	Dec. 31, 2011 Intrastate Pipeline [Member]	Dec. 31, 2011 Property, Plant and Equipment, Other Types [Member]	Dec. 31, 2011 Equipment [Member]	Dec. 31, 2010 Equipment [Member]	Dec. 31, 2011 Pipelines And Equipment [Member]	Dec. 31, 2009 Pipelines And Equipment [Member]	Dec. 31, 2010 Asset Under Construction Member
Assets, number of units																13	7	10	2	1	3	1
Units available under LTIP									2,160,848
Units authorized under LTIP									2,250,000
Ownership interest					50.00%	51.00%								0.40%
Ownership interest by noncontrolling owners													24.00%		25.00%
Bad-debt reserve	$ 17,000		$ 17,000
Natural gas imbalance receivables	2,300,000		400,000
Natural gas imbalance payables	3,100,000		2,600,000
Goodwill	82,100,000		82,100,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity							10,400,000	2,700,000				47,900,000
UVR and UAR Valuation										$ 634.00	$ 215.00
Unguaranteed residual value	4,600,000
Capital lease receivable	700,000
Impairment																								7,300,000	600,000	3,000,000	6,100,000	300,000
Other assets	$ 24,143,000	[1]	$ 8,109,000	[1]																			$ 10,600,000

[1] Financial information as of December 31, 2011, has been recast to include the financial position and results attributable to the MGR assets, and the financial information as of December 31, 2010, has been recast to include the financial position and results attributable to the Bison and MGR assets. See Note 2.

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Subsequent Event

12 Months Ended

Dec. 31, 2011

Subsequent Events [Abstract]

Subsequent Event

Refer to Note 2 for a description of the MGR acquisition in January 2012. In conjunction with the MGR acquisition, the Partnership entered into commodity price swap agreements with Anadarko that do not contain fixed notional volumes, each effective for one year beginning January 1, 2012, and extending through December 31, 2016. Below is a summary of the fixed prices on the Partnership's commodity price swap agreements for the system:

	Year Ended December 31,
per barrel except natural gas	2012		2013		2014		2015		2016
Ethane	$	26.87	$	25.34	$	24.10	$	23.41	$	23.11
Propane	$	57.97	$	55.59	$	53.78	$	52.99	$	52.90
Isobutane	$	80.98	$	77.66	$	75.13	$	74.02	$	73.89
Normal butane	$	71.15	$	68.24	$	66.01	$	65.04	$	64.93
Natural gasoline	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Condensate	$	89.51	$	85.84	$	83.04	$	81.82	$	81.68
Natural gas (per MMbtu)	$	3.62	$	4.17	$	4.45	$	4.66	$	4.87