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 13, 2013

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware	001-34046	26-1075808
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer 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 March 5, 2013, 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 on March 1, 2013, of a 33.75% interest in both the Liberty and Rome gas gathering systems from Anadarko Marcellus Midstream, L.L.C. (“AMM”), a wholly owned subsidiary of Anadarko Petroleum Corporation (“Anadarko”). The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” The consideration paid by the Partnership for the Non-Operated Marcellus Interest consisted of $465.5 million in cash and 449,129 common units of the Partnership. The Partnership funded the cash consideration through $250.0 million in borrowings under its revolving credit facility and $215.5 million of cash on hand. The terms of the Non-Operated Marcellus Interest acquisition were approved by the board of directors of the Partnership’s general partner (the “Board”) and by the Board’s special committee on February 27, 2013.

On April 19, 2013, the Partnership 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 Non-Operated Marcellus Interest, the unaudited pro forma financial statements of the Partnership required by Items 9.01(a) and 9.01(b) of Form 8-K and certain 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 and control of Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership, the acquisition of the Non-Operated Marcellus Interest is considered a transfer of net assets between entities under common control. As such, the Partnership is required to recast its financial statements to include the activities of the Non-Operated Marcellus Interest 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 Non-Operated Marcellus Interest as if the Partnership owned the Non-Operated Marcellus Interest since May 2008, the date construction began on the Liberty and Rome gas gathering systems.

The Partnership’s Form 10-K for the year ended December 31, 2012 (the “2012 Form 10-K”), as filed with the Securities and Exchange Commission (the “SEC”) on February 28, 2013, 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 2012 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 2012 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 2012 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 2012 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 2012 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 2012 Form 10-K other than the revisions noted above. This Current Report on Form 8-K should be read in conjunction with the 2012 Form 10-K, and any references herein to Items 6, 7 and 8 under Part II of the 2012 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 13, 2013	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	2012		2011		2010		2009		2008
Earnings:
Income before income taxes	$	170,026	$	239,011	$	178,450	$	148,520	$	205,132
Add:
Fixed charges		48,422		30,993		19,292		10,992		2,965
Distributions from equity investees		20,660		15,999		10,973		11,206		14,428
Amortization of capitalized interest		479		294		256		182		80
Less:
Equity income		16,111		11,261		7,628		7,923		11,118
Capitalized interest		6,196		420		—		—		—
Net income before taxes attributable to noncontrolling interests		14,890		14,103		11,005		10,260		7,965
Earnings	$	202,390	$	260,513	$	190,338	$	152,717	$	203,522
Fixed charges:
Interest expense, including capitalized interest	$	48,256	$	30,765	$	18,794	$	9,955	$	364
Interest component of rent expense		166		228		498		1,037		2,601
Fixed charges	$	48,422	$	30,993	$	19,292	$	10,992	$	2,965
Ratio of earnings to fixed charges		4.2x		8.4x		9.9x		13.9x		68.6x

These ratios were computed by dividing earnings by fixed charges. For this purpose, earnings include pre-tax income, 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), Form S-3 (No. 333-183505) and Form S-8 (No. 333-151317), of Western Gas Partners, LP of our report dated May 13, 2013, with respect to the consolidated balance sheets of Western Gas Partners, LP and subsidiaries as of December 31, 2012 and 2011, 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, 2012, which report appears in the Current Report on Form 8-K of Western Gas Partners, LP and subsidiaries dated May 13, 2013.

/s/ KPMG LLP

Houston, Texas

May 13, 2013

EX-99.1

EXHIBIT 99.1

Item 6.  Selected Financial and Operating Data

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. Our general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko Petroleum Corporation. Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and our general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), and Rendezvous Gas Services, LLC (“Rendezvous”). “Equity method investment throughput” refers to our 14.81% share of  Fort Union and 22% share of Rendezvous gross volumes.

References to the “Partnership assets” refer collectively to the assets we owned as of December 31, 2012, including the Non-Operated Marcellus Interest (as defined below). Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see Note 2—Acquisitions in the Notes to the Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Further, after an acquisition of  assets from Anadarko, we may be required to recast our financial statements to include the activities of such assets as of the date of  common control. For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko, including the Non-Operated Marcellus Interest, 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 from Anadarko as being “our” historical financial results.

 Acquisitions

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 “IPO.” Concurrently 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 completed the acquisition of the Powder River assets from Anadarko, which included (i) the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% membership interest in Fort Union Gas Gathering, LLC (“Fort Union”). In July 2009, we closed on the acquisition of a 51% membership interest in Chipeta Processing LLC (“Chipeta”) from 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, and are referred to collectively as the “White Cliffs acquisition.” The Partnership’s interest in White Cliffs is referred to as the “White Cliffs investment.” 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. In January 2012, we acquired Mountain Gas Resources, LLC (“MGR”) from Anadarko, which acquisition included the Red Desert complex and the 22% interest in Rendezvous. In August 2012, we acquired Anadarko’s then-remaining 24% membership interest in Chipeta (the “additional Chipeta interest”), receiving distributions related to the additional interest effective July 1, 2012.

In March 2013, we completed the acquisition of a 33.75% interest in both the Liberty and Rome gas gathering systems from Anadarko Marcellus Midstream, L.L.C. (“AMM”), a wholly owned subsidiary of Anadarko. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In September 2006, Anadarko and a third party entered into a 50/50 Joint Exploration Agreement covering counties in north-central Pennsylvania within an Area of Mutual Interest that the parties designated as “Area A.” Initial construction of the midstream assets within Area A began in May 2008, and in December 2011, following various sales of interests, AMM and three third-party owners (the “system owners”) entered into a Construction, Ownership and Operation agreement (the “COO Agreement”) to jointly own and develop the midstream assets in Area A (the “AMI Assets”). The AMI Assets are comprised of two systems, the Liberty Gas Gathering System and the Rome Gas Gathering System. 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.

 Dates of common control

In connection with its August 23, 2006, acquisition of Western Gas Resources, Inc. (“Western”), Anadarko acquired MIGC, the Powder River assets, the Granger assets and the assets of MGR. Anadarko acquired the Wattenberg assets and a 75% interest in Chipeta in connection with its August 10, 2006, acquisition of Kerr-McGee Corporation (“Kerr-McGee”). Anadarko made its initial investment in White Cliffs on January 29, 2007.

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 IPO and (ii) the consolidated financial results and operations of Western Gas Partners, LP and its subsidiaries from the closing date of our IPO 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, (b) the financial results and operations of the Chipeta and Wattenberg assets from August 10, 2006, (c) the 0.4% interest in White Cliffs from January 29, 2007, (d) the financial results and operations of the Bison assets from 2009 (when Anadarko began construction of such assets, which were subsequently placed in service in June 2010), and (e) the financial results and operations of the Non-Operated Marcellus Interest from May 2008 (the date construction began on the Liberty and Rome gas gathering systems). Effective August 1, 2012, the Partnership’s noncontrolling interest excludes the financial results and operations of the additional Chipeta interest.

2

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	2012 (1)		2011 (1)		2010 (1)		2009 (1)		2008 (1)
Statement of Income Data (for the year ended):
Total revenues	$	910,587	$	869,405	$	663,274	$	619,764	$	922,314
Costs and expenses		595,085		510,978		394,606		392,939		615,460
Depreciation, amortization and impairments		120,608		113,133		91,129		90,695		116,381
Total operating expenses		715,693		624,111		485,735		483,634		731,841
Operating income		194,894		245,294		177,539		136,130		190,473
Interest income (expense), net		(25,160)		(6,239)		1,449		10,762		13,110
Other income (expense), net		292		(44)		(538)		1,628		1,549
Income tax expense (2)		20,715		32,150		21,517		22,103		53,252
Net income		149,311		206,861		156,933		126,417		151,880
Net income (loss) attributable to noncontrolling interests		14,890		14,103		11,005		10,260		7,908
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928	$	116,157	$	143,972
Key Performance Measures (for the year ended):
Gross margin	$	574,508	$	542,034	$	416,798	$	380,890	$	457,599
Adjusted EBITDA attributable to Western Gas Partners, LP (3)		377,929		361,653		264,694		223,635		304,052
Distributable cash flow (3)		309,945		319,294		237,372		203,245		270,150
General partner interest in net income (4)		28,089		8,599		3,067		1,428		842
Limited partners’ interest in net income (4)		78,897		131,560		111,064		69,980		41,261
Net income per common unit (basic and diluted) (4)	$	0.84	$	1.64	$	1.66	$	1.25	$	0.78
Net income per subordinated unit (basic and diluted) (4)	$	—	$	1.28	$	1.61	$	1.24	$	0.77
Distributions per unit	$	1.9600	$	1.6550	$	1.4400	$	1.2600	$	0.7582
Balance Sheet Data (at period end):
Net property, plant and equipment	$	2,717,956	$	2,121,152	$	1,789,651	$	1,746,197	$	1,694,735
Total assets		3,749,922		2,991,579		2,345,255		2,278,512		2,203,023
Total long-term liabilities		1,284,180		860,092		649,414		568,331		569,256
Total equity and partners’ capital	$	2,280,436	$	2,004,169	$	1,613,311	$	1,627,818	$	1,554,790
Cash Flow Data (for the year ended):
Net cash flows provided by (used in):
Operating activities	$	338,026	$	312,838	$	252,898	$	209,345	$	280,805
Investing activities		(1,249,942)		(479,722)		(921,398)		(223,128)		(607,455)
Financing activities		1,105,338		366,369		625,590		47,694		362,750
Capital expenditures	$	638,121	$	149,717	$	173,891	$	121,295	$	164,360
Operating Data (volumes in MMcf/d):
Gathering, treating and transportation throughput (5)		1,601		1,555		1,181		1,229		1,339
Processing throughput (6)		1,187		962		815		808		557
Equity investment throughput (7)		235		198		228		225		304
Total throughput		3,023		2,715		2,224		2,262		2,200
Throughput attributable to noncontrolling interests		228		242		197		180		124
Throughput attributable to Western Gas Partners, LP		2,795		2,473		2,027		2,082		2,076
Gross margin per Mcf (8)	$	0.52	$	0.55	$	0.51	$	0.46	$	0.57
Gross margin per Mcf attributable to Western Gas Partners, LP (8) (9)	$	0.54	$	0.58	$	0.54	$	0.48	$	0.58

3

⁽¹⁾  Financial information and throughput has been recast to include the results attributable to the Non-Operated Marcellus Interest. 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.

⁽²⁾  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 from Anadarko, 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.

⁽³⁾  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.

⁽⁴⁾  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 Anadarko. All subordinated units were converted into common units on August 15, 2011, on a one-for-one basis. 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.

⁽⁵⁾  Excludes average NGL pipeline volumes from the Chipeta assets of 25 MBbls/d, 24 MBbls/d, 14 MBbls/d, 11 MBbls/d and 3 MBbls/d for the years ended December 31, 2012, 2011, 2010, 2009 and 2008, respectively. Includes 100% of Wattenberg system volumes for all periods presented.

⁽⁶⁾  Consists of 100% of Chipeta and Hilight system volumes, 100% of the Granger and Red Desert complex volumes, 50% of Newcastle volumes, and throughput beginning March 2011 attributable to the Platte Valley system.

⁽⁷⁾  Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes and excludes 6 MBbls/d, 4 MBbls/d and 3 MBbls/d of average oil pipeline volumes for the years ended December 31, 2012, 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.

⁽⁸⁾  Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), 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. Gross margin also includes 100% of gross margin attributable to our NGL pipelines and our 10% interest in income attributable to White Cliffs.

⁽⁹⁾  Excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.

4

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 Delaware master limited partnership (“MLP”) organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently own assets located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), north-central Pennsylvania, and the Mid-Continent (Kansas and Oklahoma) and are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. As of December 31, 2012, we owned and operated twelve natural gas gathering systems, seven natural gas treating facilities, seven natural gas processing facilities, two NGL pipelines, one interstate natural gas pipeline, and one intrastate natural gas pipeline. In addition, including the acquisition of the Non-Operated Marcellus Interest, we had interests in two non-operated natural gas gathering systems, one operated natural gas gathering system and two operated natural gas processing facilities, with separate interests accounted for under the equity method in two natural gas gathering systems and a crude oil pipeline. See also Note 12—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Significant financial highlights during the year ended December 31, 2012, include the following:

• In connection with the closing of the Western Gas Equity Partners, LP (“WGP”) IPO, we sold 8,722,966 common units to WGP and 178,019 general partner units to our general partner. Net proceeds of $409.4 million are being used for general partnership purposes and the funding of capital expenditures.

• We issued $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022. Net proceeds were used to repay all amounts then outstanding under our revolving credit facility (“RCF”) and the note payable to Anadarko, with the remaining net proceeds used for general partnership purposes. See Liquidity and Capital Resources within this Item 7 for additional information.

• We issued 5,000,000 common units to the public, generating net proceeds of $216.4 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds are being used for general partnership purposes, including the funding of capital expenditures. See Equity Offerings under Items 1 and 2 of our 2012 Form 10-K for additional information.

• We completed the acquisition of Anadarko’s MGR assets located in Southwestern Wyoming in January and the acquisition of Anadarko’s then remaining 24% interest in Chipeta in August. See Acquisitions under Items 1 and 2 of our 2012 Form 10-K for additional information.

• We announced two growth projects: (i) the expansion of our processing capacity by 300 MMcf/d at our Wattenberg system with the construction of the Lancaster plant, and (ii) the construction of a new 200 MMcf/d cryogenic processing plant in the Maverick Basin, referred to as the Brasada plant. Startup is anticipated in the first quarter of 2014 for the Lancaster plant and the second quarter of 2013 for the Brasada plant. See Liquidity and Capital Resources within this Item 7 for additional information.

• We raised our distribution to $0.52 per unit for the fourth quarter of 2012, representing a 4% increase over the distribution for the third quarter of 2012, an 18% increase over the distribution for the fourth quarter of 2011, and our fifteenth consecutive quarterly increase.

Significant operational highlights during the year ended December 31, 2012, include the following:

• Throughput attributable to Western Gas Partners, LP totaled 2,795 MMcf/d for the year ended December 31, 2012, representing a 13% increase compared to the year ended December 31, 2011.

• Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.54 per Mcf for the year ended December 31, 2012, representing a 7% decrease compared to the year ended December 31, 2011.

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. Our general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko Petroleum Corporation. Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and our general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), and Rendezvous Gas Services, LLC (“Rendezvous”). “Equity method investment throughput” refers to our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

References to the “Partnership assets” refer collectively to the assets we owned as of December 31, 2012, including the Non-Operated Marcellus Interest. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see Note 2—Acquisitions in the Notes to the Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Further, after an acquisition of assets from Anadarko, we may be required to recast our financial statements to include the activities of such assets as of the date of common control. The consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko 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 from Anadarko as being “our” historical financial results.

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, 2012, approximately 76% of our total revenues and 62% of our throughput (excluding equity investment revenues and throughput) were 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 our Wattenberg, Dew, Pinnacle, Haley, Helper, Clawson and Hugoton gathering systems. Specifically, pursuant to the terms of our applicable gathering agreements, 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, 2012, approximately 70% of our gross margin was attributed to fee-based contracts, under which a fixed fee is received based on the volume or 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 (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements. Fee-based gross margin includes equity income from our interests in Fort Union, White Cliffs and Rendezvous.

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For the year ended December 31, 2012, approximately 30% of our gross margin, including gross margin attributable to condensate sales, was attributable to percent-of-proceeds and keep-whole contracts, pursuant to which we have commodity price exposure. A substantial majority of the commodity price risk associated with our percent-of-proceeds and keep-whole contracts is hedged under commodity price swap agreements with Anadarko. For the year ended December 31, 2012, approximately 98% of our gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements included under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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 2012 Form 10-K.

As a result of our IPO and subsequent acquisitions from Anadarko and third parties, the results of operations, financial position and cash flows may vary significantly for 2012, 2011 and 2010 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, 2012, excluding the acquisition of the Non-Operated Marcellus Interest, we added 139 receipt points to our systems with initial throughput of approximately 1.7 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.

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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 amounts attributable to costs incurred on our behalf and allocations of general and administrative costs by Anadarko and the general partner to us. For periods subsequent to our acquisition of the Partnership assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, allocations and reimbursements of general and administrative expenses are determined by Anadarko in its reasonable discretion, in accordance with our partnership agreement and omnibus agreement. Amounts required to be reimbursed to Anadarko under the omnibus agreement also 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;

• 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.

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.

 Non-GAAP financial measures

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 expense reimbursement cap provided in our omnibus agreement (which cap is no longer effective), interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, and other income. 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.

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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, 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. Adjusted EBITDA and Distributable cash flow should not be considered 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.

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

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The following tables present (a) 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	2012		2011		2010
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	377,929	$	361,653	$	264,694
Less:
Distributions from equity investees		20,660		15,999		10,973
Non-cash equity-based compensation expense (1)		73,508		13,754		4,787
Expenses in excess of omnibus cap		—		—		133
Interest expense		42,060		30,345		18,794
Income tax expense		20,715		32,150		21,517
Depreciation, amortization and impairments (2)		118,279		110,380		88,307
Other expense (2)		1,665		3,683		2,393
Add:
Equity income, net		16,111		11,261		7,628
Interest income, net – affiliates		16,900		24,106		20,243
Other income (2) (3)		368		2,049		267
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928
Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	377,929	$	361,653	$	264,694
Adjusted EBITDA attributable to noncontrolling interests		17,214		16,850		13,823
Interest income (expense), net		(25,160)		(6,239)		1,449
Expenses in excess of omnibus cap		—		—		(133)
Non-cash equity based compensation expense(1)		(69,791)		(10,264)		(2,220)
Debt-related amortization and other items, net		2,319		3,110		1,705
Current income tax expense		9,398		(15,570)		(11,978)
Other income (expense), net (3)		(1,292)		(1,628)		(2,122)
Distributions from equity investees less than (in excess of) equity income, net		(4,549)		(4,738)		(3,345)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		23,520		(47,415)		(14,661)
Accounts payable, accrued liabilities and natural gas imbalance payable		5,045		30,884		5,407
Other		3,393		(13,805)		279
Net cash provided by operating activities	$	338,026	$	312,838	$	252,898
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	338,026	$	312,838	$	252,898
Net cash used in investing activities	$	(1,249,942)	$	(479,722)	$	(921,398)
Net cash provided by financing activities	$	1,105,338	$	366,369	$	625,590

⁽¹⁾  Includes $69.8 million of equity-based compensation associated with the Incentive Plan (as defined and described in 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), paid and contributed by Anadarko during the year ended December 31, 2012.

⁽²⁾  Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; and other income attributable to Chipeta.

⁽³⁾  Excludes income of $1.6 million for each of the years ended December 31, 2012, 2011 and 2010, respectively, related to a component of a gas processing agreement accounted for as a capital lease. 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.

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	Year Ended December 31,
thousands except Coverage ratio	2012			2011		2010
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	309,945		$	319,294	$	237,372
Less:
Distributions from equity investees		20,660			15,999		10,973
Non-cash equity-based compensation expense(1)		73,508			13,754		4,787
Expenses in excess of omnibus cap		—			—		133
Interest expense, net (non-cash settled)		326			—		—
Income tax expense		20,715			32,150		21,517
Depreciation, amortization and impairments (2)		118,279			110,380		88,307
Other expense (2)		1,665			3,683		2,393
Add:
Equity income, net		16,111			11,261		7,628
Cash paid for maintenance capital expenditures (2) (3)		36,459			28,304		24,921
Capitalized interest		6,196			420		—
Cash paid for income taxes		495			190		507
Other income (2) (4)		368			2,049		267
Interest income, net (non-cash settled)		—			7,206		3,343
Net income attributable to Western Gas Partners, LP	$	134,421		$	192,758	$	145,928
Distributions declared (5)
Limited partners	$	190,123
General partner		30,358
Total	$	220,481
Coverage ratio		1.41	x

⁽¹⁾  Includes $69.8 million of equity-based compensation associated with the Incentive Plan (as defined and described in 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), paid and contributed by Anadarko during the year ended December 31, 2012.

⁽²⁾  Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to Chipeta.

⁽³⁾  Net of a prior period adjustment reclassifying approximately $0.7 million from capital expenditures to operating expenses for the year ended December 31, 2012.

⁽⁴⁾  Excludes income of $1.6 million for each of the years ended December 31, 2012, 2011 and 2010, respectively, related to a component of a gas processing agreement accounted for as a capital lease. 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.

⁽⁵⁾  Reflects distributions of $1.96 per unit declared for the year ended December 31, 2012.

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:

Gathering and processing agreements. The gathering agreements of our initial assets and the Non-Operated Marcellus Interest allow for rate resets that target a return on invested capital in those assets over the life of the agreement. Effective July 1, 2010, contracts covering all of Wattenberg’s affiliate throughput were converted from primarily keep-whole contracts into a 10-year fee-based agreement. This contract change impacts the comparability of the consolidated statements of income and cash flows. In addition, in connection with the MGR acquisition, we entered into 10-year, fee-based gathering and processing agreements with Anadarko effective December 1, 2011, for all affiliate throughput on the MGR assets. 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.

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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 commodity price 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 Granger, Hilight, Hugoton, Newcastle, MGR and Wattenberg assets, with various expiration dates through December 2016. In December 2011, we extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2013. 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.

Income taxes. Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, including and subsequent to the date of the acquisition of the Partnership assets, is subject only to Texas margin tax.

With respect to assets acquired from Anadarko, we record Anadarko’s historic current and deferred income taxes for the periods prior to our ownership of the assets. For periods subsequent to our acquisitions from Anadarko, we are not subject to tax except for the Texas margin tax and accordingly, do not record current and deferred federal income taxes related to such assets.

General and administrative expenses. Pursuant to the omnibus agreement, Anadarko and the general partner perform centralized corporate functions for us. Prior to our acquisition of the Partnership assets from Anadarko, 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, 2012, 2011 and 2010, we reimbursed Anadarko $14.9 million, $11.8 million and $9.0 million, respectively, in general and administrative expenses. Prior to December 31, 2010, the general and administrative expenses for which we reimbursed Anadarko were subject to a cap as set forth in the omnibus agreement. In addition, our general and administrative expenses for the year ended December 31, 2010, included $0.1 million of expenses incurred by Anadarko and the general partner in excess of the cap contained in the omnibus agreement. Such expenses were recorded as capital contributions from Anadarko and did not impact the Partnership’s cash flows. The amounts reimbursed 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 acquisition of the Partnership assets from Anadarko. Our public company expenses, such as external audit and consulting fees, that were reimbursed to Anadarko were $6.8 million, $7.7 million and $8.0 million, during the years ended December 31, 2012, 2011 and 2010, respectively. We record the equity-based compensation allocated to us by Anadarko as an adjustment to partners’ capital in our consolidated financial statements in the period in which it is contributed. During the fourth quarter of 2012, we were allocated $54.9 million of general and administrative expenses from Anadarko associated with the Incentive Plan. 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 information.

Interest on intercompany balances. For periods prior to our acquisition of the Partnership assets from Anadarko, 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 IPO, the Powder River acquisition, the Chipeta acquisition, the Granger acquisition, the Wattenberg acquisition, the acquisition of a 0.4% interest in White Cliffs, the Bison acquisition, the MGR acquisition and the Non-Operated Marcellus Interest 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. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

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

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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 RCF. These assets, acquired from a third-party, have been recorded in our 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 in 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.

Noncontrolling interests. Prior to August 1, 2012, the 24% membership interest in Chipeta held by Anadarko and the 25% membership interest in Chipeta held by a third-party were reflected as noncontrolling interests in our consolidated financial statements for the years ended December 31, 2011 and 2010. On August 1, 2012, we acquired Anadarko’s then remaining 24% membership interest in Chipeta, receiving distributions related to this additional interest beginning July 1, 2012. Since we acquired an additional interest in an already-consolidated entity, the acquisition of Anadarko’s then remaining 24% membership interest was accounted for on a prospective basis. As such, effective August 1, 2012, our noncontrolling interest excludes the financial results and operations of the additional Chipeta interest. The remaining 25% membership interest held by a third-party member is reflected as noncontrolling interests in our consolidated financial statements for all periods presented. See Note 1—Summary of Significant Accounting Policies and 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 further information.

Execution of COO Agreement for the Non-Operated Marcellus Interest. In March 2013, we completed the acquisition of the Non-Operated Marcellus Interest. Anadarko and a third party entered into a 50/50 Joint Exploration Agreement, dated September 1, 2006, covering counties in north-central Pennsylvania within an Area of Mutual Interest that the parties designated as “Area A.” Initial construction of the midstream assets within Area A began in May 2008, and limited gathering services were provided to producers in 2008, 2009 and 2010, with the midstream assets becoming fully operational in 2011. In December 2011, following various sales of interests, AMM and three third-party owners (the “system owners”) entered into a Construction, Ownership and Operation agreement (the “COO Agreement”) to jointly own and develop the midstream assets in Area A (the “AMI Assets”). Deferred revenues and expenses associated with the third-party operation of the AMI Assets were recognized in 2011 upon the execution of the COO Agreement.

GENERAL TRENDS AND OUTLOOK

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

Impact of natural gas and NGL prices. The relatively low natural gas price environment, which has persisted over the past three years, has led to lower levels of drilling activity in areas 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 in those areas. 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.

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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 capital markets financing or, in some cases, temporarily made such financing unavailable. If we are unable either to access the 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 2012. 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. As of December 31, 2012, Anadarko’s total domestic midstream asset portfolio, excluding the assets we own, consisted of 16 gathering systems, approximately 4,559 miles of pipeline and 8 processing and/or treating facilities. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time.

    As of December 31, 2012, WGP and affiliates held a 46.2% limited partner interest in us, and through its ownership of our general partner, indirectly held a 2.0% general partner interest in us and 100% of our incentive distribution rights (“IDRs”). Given Anadarko’s significant interests in us, we believe Anadarko will continue to be motivated to promote and support the successful execution of our business plan and to pursue projects that help to enhance the value of our business. 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.

10

RESULTS OF OPERATIONS

OPERATING RESULTS

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

	Year Ended December 31,
thousands	2012		2011		2010
Gathering, processing and transportation of natural gas and natural gas liquids	$	382,330	$	347,469	$	253,273
Natural gas, natural gas liquids and condensate sales		508,339		502,383		396,037
Equity income and other, net		19,918		19,553		13,964
Total revenues (1)		910,587		869,405		663,274
Total operating expenses (1)		715,693		624,111		485,735
Operating income		194,894		245,294		177,539
Interest income, net – affiliates		16,900		24,106		20,243
Interest expense		(42,060)		(30,345)		(18,794)
Other income (expense), net		292		(44)		(538)
Income before income taxes		170,026		239,011		178,450
Income tax expense		20,715		32,150		21,517
Net income		149,311		206,861		156,933
Net income attributable to noncontrolling interests		14,890		14,103		11,005
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928
Key Performance Metrics (2)
Gross margin	$	574,508	$	542,034	$	416,798
Adjusted EBITDA attributable to Western Gas Partners, LP	$	377,929	$	361,653	$	264,694
Distributable cash flow	$	309,945	$	319,294	$	237,372

⁽¹⁾  Revenues include amounts earned from services provided to our affiliates, as well as from the sale of residue, 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 and Distributable cash flow are defined under the caption Key Performance Metrics within this Item 7. Such caption also includes reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP.

  For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2012” refer to the comparison of the year ended December 31, 2012 to the year ended December 31, 2011, and 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.

11

Operating Statistics

	Year Ended December 31,
throughput in MMcf/d	2012		2011		D		2010		D
Gathering, treating and transportation (1)		1,601		1,555		3%		1,181		32%
Processing (2)		1,187		962		23%		815		18%
Equity investment (3)		235		198		19%		228		(13)%
Total throughput (4)		3,023		2,715		11%		2,224		22%
Throughput attributable to noncontrolling interests		228		242		(6)%		197		23%
Total throughput attributable to Western Gas Partners, LP		2,795		2,473		13%		2,027		22%

⁽¹⁾  Excludes average NGL pipeline volumes of 25 MBbls/d, 24 MBbls/d and 14 MBbls/d for the years ended December 31, 2012, 2011 and 2010, respectively. Includes 100% of Wattenberg system volumes for all periods presented.

⁽²⁾  Consists of 100% of Chipeta and Hilight system volumes, 100% of the Granger and Red Desert complex volumes, 50% of Newcastle volumes, and 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 our 10% share of average White Cliffs pipeline volumes consisting of 6 MBbls/d, 4 MBbls/d and 3 MBbls/d for the years ended December 31, 2012, 2011 and 2010, respectively.

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

  Gathering, treating and transportation throughput increased by 46 MMcf/d for the year ended December 31, 2012, primarily due to increased drilling behind the Non-Operated Marcellus Interest. This increase was partially offset by throughput decreases at the Pinnacle and Dew systems resulting from natural production declines in those areas; throughput decreases at MIGC due to the September 2012 expiration of a firm transportation agreement; and throughput decreases at the Bison facility resulting from reduced drilling activity in the area driven by unfavorable producer economics.

  Gathering, treating and transportation throughput increased by 374 MMcf/d for the year ended December 31, 2011, primarily due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, which triggered the recognition of the related throughput, and the startup of the Bison assets in June 2010. 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, and Dew systems resulting from natural production declines in those areas.

  Processing throughput increased by 225 MMcf/d for the year ended December 31, 2012, primarily due to volumes processed at a plant included in the MGR acquisition under a new contract effective January 2012, with no volumes in the comparable period, and throughput increases at the Chipeta system resulting from increased drilling activity. 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.

  Equity investment volumes increased by 37 MMcf/d for the year ended December 31, 2012, resulting from higher throughput at the Fort Union system due to producers choosing to route additional gas to reach desired end markets and at the Rendezvous system due to increased third-party drilling activity. 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.

12

Natural Gas Gathering, Processing and Transportation Revenues

	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Gathering, processing and transportation of natural gas and natural gas liquids	$	382,330	$	347,469		10%	$	253,273		37%

  Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $34.9 million for the year ended December 31, 2012, primarily due to increases of $15.0 million and $13.4 million at the Non-Operated Marcellus Interest and Chipeta system, respectively, due to increased volumes, and a $13.6 million increase at the Wattenberg system due to increased gathering rates and volumes. These increases were partially offset by decreased revenue of $3.0 million at the Helper system due to a downward rate revision effective April 1, 2012, decreased revenue of $3.0 million at MIGC due to the expiration of firm transportation agreements, and decreased revenue of $2.4 million at the Granger system due to diverted volumes.

  Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $94.2 million for the year ended December 31, 2011, primarily due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, which resulted in an increase of $46.1 million; the acquisition of the Platte Valley system in February 2011, which resulted in an increase of $23.5 million; the June 2010 startup of the Bison assets, which resulted in an increase of $19.3 million; and increased fee revenue of $15.3 million 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 of $8.5 million at MIGC due to the January 2011 expiration of certain contracts, an aggregate decrease of $6.4 million due to decreased volume resulting from 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.

Natural Gas, Natural Gas Liquids and Condensate Sales

thousands except percentages and per-unit amounts	Year Ended December 31,
	2012		2011		D		2010		D
Natural gas sales	$	101,116	$	129,939		(22)%	$	91,452		42%
Natural gas liquids sales		377,377		345,375		9%		279,915		23%
Drip condensate sales		29,846		27,069		10%		24,670		10%
Total	$	508,339	$	502,383		1%	$	396,037		27%
Average price per unit:
Natural gas (per Mcf)	$	4.24	$	5.32		(20)%	$	5.17		3%
Natural gas liquids (per Bbl)	$	48.22	$	47.44		2%	$	39.94		19%
Drip condensate (per Bbl)	$	75.88	$	73.60		3%	$	70.50		4%

  Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $6.0 million for the year ended December 31, 2012, which consisted of a $32.0 million increase in NGLs sales and a $2.8 million increase in drip condensate sales, partially offset by a $28.8 million decrease in natural gas sales.

  For the year ended December 31, 2012, the increase in NGLs sales was primarily due to increases of $10.3 million, $9.2 million, and $3.1 million resulting from higher volumes sold at the Chipeta, Hilight, and Wattenberg systems, respectively; increases of $5.1 million and $2.3 million at the Granger system and Red Desert complex, respectively, due to increased pricing, offset by a decrease in volumes; and an increase of $9.6 million related to volumes processed at a plant included in the MGR acquisition under a new contract effective January 2012, with no volumes in the comparable period. These increases were partially offset by an $8.5 million price-related decrease at the Platte Valley system.

  The increase in drip condensate sales for the year ended December 31, 2012, was primarily due to a $2.9 million increase at the Wattenberg system and a $0.7 million increase at the Platte Valley system, both resulting from increased volumes. These increases were partially offset by a $0.8 million decrease at the Hugoton system as a result of lower volumes.

13

  The decrease in natural gas sales was primarily due to a 20% decrease in overall natural gas sales prices and lower sales volumes for a decrease of $17.0 million at the Hilight system, a decrease of $3.8 million at the Red Desert complex, and a decrease of $2.7 million at the Wattenberg system. Also contributing to the overall decrease in natural gas sales was a decline at the Platte Valley system of $3.2 million resulting from price decreases, partially offset by an increase in volumes sold.

  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 $65.5 million increase in NGLs sales, a $38.5 million increase in natural gas sales and a $2.4 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 MGR assets for which commodity price swap agreements were not effective until January 1, 2012. These increases were partially offset by a decrease 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. 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 was primarily due to a higher average sales price at the Wattenberg and Hugoton systems and Platte Valley sales.

  The average natural gas and NGL prices for the year ended December 31, 2012, include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and the MGR assets. The average natural gas and NGLs prices for the years ended December 31, 2011 and 2010, include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle and Wattenberg 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

	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Equity income	$	16,111	$	11,261		43%	$	7,628		48%
Other revenues, net		3,807		8,292		(54)%		6,336		31%
Total	$	19,918	$	19,553		2%	$	13,964		40%

  Equity income increased by $4.9 million for the year ended December 31, 2012, primarily due to the increase in income from White Cliffs of $3.8 million and from Rendezvous of $0.7 million as a result of increased volumes. 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 decreased by $4.5 million for the year ended December 31, 2012, primarily due to indemnity fees associated with volume commitments received in the prior year at the Red Desert complex and Hugoton system, with no comparable activity in the current period, along with changes in gas imbalance positions at the Wattenberg and Hilight systems. Other revenues, net increased by $2.0 million for the year ended December 31, 2011, primarily due to the collection of deficiency fees associated with volume commitments, predominantly associated with MGR gathering agreements.

14

Cost of Product and Operation and Maintenance Expenses

	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Cost of product	$	336,079	$	327,371		3%	$	246,476		33%
Operation and maintenance		140,106		126,464		11%		103,887		22%
Total cost of product and operation and maintenance expenses	$	476,185	$	453,835		5%	$	350,363		30%

  Including the effects of commodity price swap agreements on purchases, cost of product expense increased by $8.7 million for the year ended December 31, 2012, primarily due to a $22.8 million increase attributable to higher pricing and increases in purchases of NGL volumes at the Chipeta system for an increase of $12.3 million, at the Hilight system for an increase of $6.4 million, and at the Wattenberg system for an increase of $2.1 million. In addition, cost of product expense for NGL purchases increased by $4.7 million for the MGR assets due to commodity price swap agreements beginning January 2012. Partially offsetting the increase in NGL purchases was a $3.5 million decrease at the Platte Valley system due to lower pricing subsequent to its acquisition in February 2011.

  Cost of product expense also increased by $4.9 million due to the higher cost of residue purchases at the MGR assets resulting from commodity price swap agreements beginning January 2012, offset by a $15.3 million decrease at the Hilight system due to declines in residue purchase prices. The impact of other gathering purchases and changes in gas imbalance positions decreased cost of product by $2.4 million.

  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.

  Cost of product expense for the year ended December 31, 2012, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and for the MGR assets. Cost of product expense for the year ended December 31, 2011, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle, and Wattenberg 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.

  Operation and maintenance expense increased by $13.6 million for the year ended December 31, 2012, primarily due to increased contract labor expense of $5.1 million at the Platte Valley and Wattenberg systems, increased expense of $1.1 million related to general equipment for operations and increased maintenance expense at the Wattenberg system, increased expense of $1.7 million related to plant repairs and turnaround expenses at the Bison facility and Hilight system, and increased facility expense of $0.8 million at the Non-Operated Marcellus Interest.

  Operation and maintenance expense increased by $22.6 million for the year ended December 31, 2011, primarily due to an increase of $12.1 million resulting from the acquisition of the Platte Valley system, an increase of $7.4 million due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, and an increase of $3.8 million resulting from the June 2010 startup of the Bison assets. These increases were partially offset by a $1.8 million reduction in compressor lease expenses resulting from the purchase of compressors used at the Wattenberg system leased during 2010.

15

General and Administrative, Depreciation and Other Expenses

	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
General and administrative	$	99,212	$	40,564		145%	$	29,970		35%
Property and other taxes		19,688		16,579		19%		14,273		16%
Depreciation, amortization and impairments		120,608		113,133		7%		91,129		24%
Total general and administrative, depreciation and other expenses	$	239,508	$	170,276		41%	$	135,372		26%

  General and administrative expenses increased by $58.6 million for the year ended December 31, 2012, due to an increase of $59.8 million in non-cash compensation expenses primarily attributable to the increase in the value of the outstanding awards under the Incentive Plan from $634.00 per Unit Appreciation Right (“UAR”) to $2,745.00 per UAR and the related increase of $1.2 million in payroll taxes. In addition, corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement increased $3.6 million. These increases were partially offset by a $3.9 million decrease in management fees allocated to the Bison and MGR assets, the agreements for which were discontinued as of the respective dates of contribution, and a $1.2 million decrease in consulting and audit fees.

  General and administrative expenses increased by $10.6 million for the year ended December 31, 2011, due to an increase of $7.2 million in non-cash payroll expenses primarily due to an increase in the collective value of awards under the Incentive Plan, from $215.00 per UAR to $634.00 per UAR and an increase of $2.7 million in corporate and management personnel costs for which we reimbursed Anadarko pursuant to the omnibus agreement.

  Property and other taxes increased by $3.1 million for the year ended December 31, 2012, primarily due to ad valorem tax increases at the Platte Valley and Wattenberg assets.

  Property and other taxes increased by $2.3 million for the year ended December 31, 2011, primarily due to ad valorem tax increases for the Platte Valley, Bison and Wattenberg assets.

  Depreciation, amortization and impairments increased by $7.5 million for the year ended December 31, 2012, primarily attributable to the addition of the Platte Valley assets, and depreciation associated with capital projects completed at the Wattenberg, Hilight, and Chipeta systems, the Non-Operated Marcellus Interest, and the Red Desert complex, partially offset by a $3.9 million decrease in impairment expense. The decrease is primarily due to a $6.6 million impairment recognized during 2012 related to a gathering system in central Wyoming and a relocated compressor, as compared to $10.3 million in impairment expense recognized during 2011, related to an indefinitely postponed expansion project at the Red Desert complex and a pipeline included in the MGR acquisition. See Note 7—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

  Depreciation, amortization and impairments increased by $22.0 million for the year ended December 31, 2011, primarily attributable to the addition of the Platte Valley and Bison assets, depreciation associated with the Non-Operated Marcellus Interest, 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.

16

Interest Income, Net – Affiliates and Interest Expense

	Year Ended December 31,
thousands except percentages	2012		2011		D	2010		D
Interest income on note receivable	$	16,900	$	16,900	—%	$	16,900	—%
Interest income, net on affiliate balances (2)		—		7,206	(100)%		3,343	116%
Interest income, net – affiliates	$	16,900	$	24,106	(30)%	$	20,243	19%
Third parties
Interest expense on long-term debt	$	(41,171)	$	(20,533)	101%	$	(8,530)	141%
Amortization of debt issuance costs and commitment fees (3)		(4,319)		(5,297)	(18)%		(3,340)	59%
Capitalized interest (4)		6,196		420	nm (1)		—	nm
Affiliates
Interest expense on note payable to Anadarko (5)		(2,440)		(4,935)	(51)%		(6,828)	(28)%
Interest expense, net on affiliate balances (6)		(326)		—	nm		—	nm
Credit facility commitment fees		—		—	nm		(96)	(100)%
Interest expense	$	(42,060)	$	(30,345)	39%	$	(18,794)	61%

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

⁽²⁾  Incurred on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets, the Bison assets, the White Cliffs investment and the 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 net investment by Anadarko.

⁽³⁾  For the year ended December 31, 2012, includes $1.1 million of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, as defined below, (ii) original issue discount for the 2021 Notes, as defined below, and (iii) underwriters’ fees. For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees for the 2021 Notes. 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.

⁽⁴⁾  For the year ended December 31, 2012, $2.2 million of interest associated with capital projects at Chipeta was capitalized and $3.5 million of interest associated with the construction of the Brasada and Lancaster gas processing facilities was capitalized. 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.

⁽⁵⁾  In June 2012, the note payable to Anadarko was repaid in full. 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.

⁽⁶⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures incurred in 2011 related to the construction of the Brasada and Lancaster plants. During the year ended December 31, 2012, the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants was repaid. 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.

  Interest expense increased by $11.7 million for the year ended December 31, 2012, primarily due to interest expense incurred on the $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”), partially offset by increased capitalized interest associated with the construction of a second cryogenic train at the Chipeta plant and a decrease in interest expense on the 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).

  Interest expense increased by $11.6 million for the year ended December 31, 2011, due to interest expense incurred on the $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 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 (as defined in Liquidity and Capital Resources within this Item 7) in March 2011. 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.

17

Other Income (Expense), Net

	Year Ended December 31,
thousands except percentages	2012		2011		D	2010		D
Other income (expense), net	$	292	$	(44)	nm	$	(538)		(92)%

    For the year ended December 31, 2012, other income (expense), net was primarily comprised of $1.6 million of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition, primarily offset by a realized loss of $1.7 million resulting from U.S. Treasury Rate lock agreements settled simultaneously with our June 2012 issuance of the 2022 Notes (see Note 10—Debt and Interest Expense included in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). For the year ended December 31, 2011, other income (expense), net was primarily comprised of a $1.9 million loss realized upon termination of an interest-rate swap agreement in May 2011, concurrent with the issuance of the 2021 Notes. For the year ended December 31, 2010, other income (expense), net was primarily comprised of a $2.4 million loss realized upon termination of financial agreements entered into in April 2010 to fix the underlying 10-year Treasury rates with respect to a potential note issuance that was not realized. 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 discussed above.

Income Tax Expense

	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Income before income taxes	$	170,026	$	239,011		(29)%	$	178,450		34%
Income tax expense		20,715		32,150		(36)%		21,517		49%
Effective tax rate		12%		13%				12%

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

  Income attributable to (a) the Non-Operated Marcellus Interest prior to and including February 2013, (b) the MGR assets prior to and including January 2012, (c) the Bison assets prior to and including June 2011, (d) the Wattenberg assets prior to and including July 2010 and (e) the Granger assets prior to and including January 2010, were subject to federal and state income tax. Income earned by the Non-Operated Marcellus Interest and the MGR, Bison, Wattenberg and Granger assets for periods subsequent to February 2013, January 2012, June 2011, July 2010 and January 2010, respectively, was subject only to Texas margin tax on the portion of their incomes apportionable to Texas.

Noncontrolling Interests

	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Net income attributable to noncontrolling interests	$	14,890	$	14,103		6%	$	11,005		28%

  For the years ended December 31, 2012 and 2011, net income attributable to noncontrolling interests increased by $0.8 million and $3.1 million, respectively, primarily due to higher volumes at the Chipeta system. For the year ended December 31, 2012, the increase was partially offset by the acquisition of Anadarko’s then remaining 24% membership interest in Chipeta in August 2012. See Note 2—Acquisitions included 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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KEY PERFORMANCE METRICS

thousands except percentages and gross margin per Mcf	Year Ended December 31,
	2012		2011		D		2010		D
Gross margin	$	574,508	$	542,034		6%	$	416,798		30%
Gross margin per Mcf (1)		0.52		0.55		(5)%		0.51		8%
Gross margin per Mcf attributable to Western Gas Partners, LP (1) (2)		0.54		0.58		(7)%		0.54		7%
Adjusted EBITDA attributable to Western Gas Partners, LP (3)		377,929		361,653		5%		264,694		37%
Distributable cash flow (3)	$	309,945	$	319,294		(3)%	$	237,372		35%

⁽¹⁾  Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), 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. Gross margin also includes 100% of gross margin attributable to our NGL pipelines and our 10% interest in income attributable to White Cliffs.

⁽²⁾  Excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.

⁽³⁾  For reconciliations 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 caption Reconciliation to GAAP measures under Non-GAAP financial measures.

Gross margin and Gross margin per Mcf. Gross margin increased by $32.5 million for the year ended December 31, 2012, primarily due to higher margins at the Non-Operated Marcellus Interest and at the Wattenberg and Chipeta systems due to increases in volumes sold (including the impact of commodity price swap agreements at the Wattenberg system). These increases were partially offset by lower gross margins at the Red Desert complex due to higher prices in 2011, as we entered into commodity price swap agreements associated with the MGR acquisition that became effective in January 2012.

  Gross margin increased by $125.2 million for the year ended December 31, 2011, primarily due to the December 2011 execution of the COO Agreement governing the Non-Operated Marcellus Interest, the acquisition of the Platte Valley system; the startup of the Bison assets in June 2010; higher margins at the Wattenberg and Chipeta systems (including the impact of commodity price swap agreements at the Wattenberg system), due to an increase in volumes; and higher margins at our Red Desert complex due to increased NGL prices during 2011. 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 system due to naturally declining production volumes.

    For the year ended December 31, 2012, gross margin per Mcf decreased by $0.03, primarily due to a decrease in volumes sold at the Red Desert complex coupled with an increase in cost of product as a result of commodity price swap agreements associated with the MGR acquisition which became effective in January 2012, partially offset by increases associated with growth in certain of our lower-margin assets.

    For the year ended December 31, 2011, gross margin per Mcf increased by $0.04, 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 our portfolio.

Adjusted EBITDA. Adjusted EBITDA increased by $16.3 million for the year ended December 31, 2012, primarily due to a $36.3 million increase in total revenues excluding equity income, a $4.7 million increase in distributions from equity investees, and a $1.1 million decrease in general and administrative expenses excluding non-cash equity-based compensation. These increases were partially offset by a $13.6 million increase in operation and maintenance expenses, an $8.7 million increase in cost of product, a $3.1 million increase in property and other tax expense, and a $0.8 million increase in net income attributable to noncontrolling interests.

  Adjusted EBITDA increased by $97.0 million for the year ended December 31, 2011, primarily due to a $202.5 million increase in total revenues excluding equity income, partially offset by an $80.9 million increase in cost of product, a $22.6 million increase in operation and maintenance expenses and a $1.8 million increase in general and administrative expenses, excluding non-cash equity-based compensation and expenses in excess of the 2010 omnibus cap.

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Distributable cash flow. Distributable cash flow decreased by $9.3 million for the year ended December 31, 2012, primarily due to a $17.2 million increase in net cash paid for interest expense, an $8.2 million increase in cash paid for maintenance capital expenditures and a $0.3 million increase in cash paid for income taxes, partially offset by the $16.3 million increase in Adjusted EBITDA.

  Distributable cash flow increased by $81.9 million for the year ended December 31, 2011, primarily due to the $97.0 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.

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 owner. Our sources of liquidity as of December 31, 2012, included cash and cash equivalents, 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 equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, 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 equity and debt issuances, to fund expansion capital expenditures, and fund 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 each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. On January 21, 2013, the board of directors of our general partner declared a cash distribution to our unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

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 statements. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Please read Item 1A—Risk Factors of our 2012 Form 10-K.

Working capital. As of December 31, 2012, we had $291.9 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.

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Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or develop new midstream infrastructure. 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 expenditures to construct new midstream infrastructure and 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:

	Year Ended December 31,
thousands	2012		2011		2010
Acquisitions	$	611,719	$	330,794	$	752,827
Expansion capital expenditures	$	600,893	$	121,318	$	148,925
Maintenance capital expenditures		37,228		28,399		24,966
Total capital expenditures (1)	$	638,121	$	149,717	$	173,891
Capital incurred (2)	$	690,041	$	182,536	$	147,069

⁽¹⁾  Capital expenditures for the year ended December 31, 2012, included $6.8 million of capitalized interest. Capital expenditures included the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners for all periods presented. Capital expenditures for the years ended December 31, 2012, 2011 and 2010, included $178.8 million, $20.1 million and $137.1 million, respectively, of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest and the MGR, Bison, Wattenberg and Granger assets.

⁽²⁾  Capital incurred for the year ended December 31, 2012, included $6.8 million of capitalized interest. Capital incurred for the years ended December 31, 2012, 2011 and 2010, included $160.9 million, $45.7 million and $108.9 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest and the MGR, Bison, Wattenberg and Granger assets and included the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

  Acquisitions included Anadarko’s remaining 24% membership interest in Chipeta, and the MGR, Bison, Platte Valley, White Cliffs, Wattenberg and Granger 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.

  Capital expenditures, excluding acquisitions, increased by $488.4 million for the year ended December 31, 2012. Expansion capital expenditures increased by $479.6 million for the year ended December 31, 2012, primarily due to an increase of $189.3 million related to the construction of the Brasada and Lancaster gas processing facilities, $167.3 million in expenditures for the Non-Operated Marcellus Interest, $127.3 million in expenditures at our Wattenberg, Chipeta, and Platte Valley systems and at the Red Desert complex, and $6.8 million of capitalized interest expense. These increases were partially offset by a $7.2 million decrease related to the Bison assets due to the continued startup costs incurred in early 2011, and a $1.2 million decrease at the Granger complex. Maintenance capital expenditures increased by $8.8 million, primarily as a result of increased expenditures of $10.0 million due to higher well connects at the Non-Operated Marcellus Interest, the Platte Valley and Haley systems, and the Red Desert complex, partially offset by $2.3 million in 2011 improvements at the Hugoton system.

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  Capital expenditures, excluding acquisitions, decreased by $24.2 million for the year ended December 31, 2011. Expansion capital expenditures decreased by $27.6 million for the year ended December 31, 2011, primarily due to a $29.1 decrease in expenditures for the Non-Operated Marcellus Interest, the purchase of previously leased compressors at the Wattenberg system during the year ended December 31, 2010, for $37.5 million, partially offset by an increase of $39.5 million in expenditures primarily at our Chipeta, Bison, Hilight and Wattenberg systems. Maintenance capital expenditures increased by $3.4 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.

  We estimate our total capital expenditures for the year ending December 31, 2013, including our 75% share of Chipeta’s capital expenditures and excluding acquisitions, to be $550 million to $600 million and our maintenance capital expenditures to be approximately 5% to 10% of total capital expenditures. Expected 2013 capital projects include the continued construction of new cryogenic processing plants in Northeast Colorado and South 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 and discussion presents a summary of our net cash flows provided by (used in) operating activities, investing activities and financing activities:

	Year Ended December 31,
thousands	2012		2011		2010
Net cash provided by (used in):
Operating activities	$	338,026	$	312,838	$	252,898
Investing activities		(1,249,942)		(479,722)		(921,398)
Financing activities		1,105,338		366,369		625,590
Net increase (decrease) in cash and cash equivalents	$	193,422	$	199,485	$	(42,910)

Operating Activities. For expanded discussion, refer to Operating Results within this Item 7. Net cash provided by operating activities increased by $25.2 million for the year ended December 31, 2012, primarily due to the following items:

• an increase of $62.3 million of working capital changes and other items, net, due to accruals of expected future operating cash receipts and cash payments;

• a $36.3 million increase in revenues, excluding equity income, due to increased drilling activity in certain of our operating areas, increased average commodity prices pursuant to commodity price swap agreements and the addition of the Platte Valley assets in March 2011;

• a $25.0 million decrease in current income tax expense, due to income earned by assets acquired from Anadarko being subject to federal and state income tax prior to our acquisition;

• a $4.9 million increase in equity income, due to the increase in income from White Cliffs and Rendezvous; and

• a $0.3 million increase in other income (expense), net.

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

• a $58.4 million increase in general and administrative expenses, excluding an increase of $0.2 million of non-cash equity-based compensation expense under the Anadarko Incentive Plans and the LTIP, primarily due to the vesting and settlement of the Incentive Plan awards during the fourth quarter of 2012;

• a $13.6 million increase in operation and maintenance expense, primarily due to increased expenses at the Platte Valley and Wattenberg systems;

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• a $12.5 million increase in interest expense, primarily due to the 2022 Notes offering in June 2012 and October 2012, excluding a decrease of $0.8 million of debt-related amortization expense and other items, net;

• an $8.7 million increase in cost of product expense, due to increased processing throughput as a result of increased drilling activity in certain of our operating areas, partially offset by pricing received at Platte Valley;

• a $7.2 million decrease in interest income related to Bison and MGR affiliate balances for periods prior to our acquisition of such assets from Anadarko in July 2011 and January 2012, respectively, partially offset by interest income related to affiliate balances of the Non-Operated Marcellus Interest; and

• a $3.1 million increase in property and other taxes expense.

  Net cash provided by operating activities increased by $59.9 million for the year ended December 31, 2011, primarily due to the following items:

• a $202.5 million increase in revenues, excluding equity income, due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest, increased processing throughput as a result of increased drilling activity in certain of our operating areas, and the addition of the Platte Valley assets in March 2011.

  The impact of these items was partially offset by the following:

• an $80.9 million increase in cost of product expense, due to increased processing throughput as a result of increased drilling activity in certain of our operating areas and additional throughput from the Platte Valley assets beginning in March 2011;

• a $22.6 million increase in operation and maintenance expenses, due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, the addition of the Platte Valley system in March 2011, as well as the June 2010 startup of the Bison assets;

• a decrease of $21.4 million of working capital changes and other items, net, due to accruals of expected future operating cash receipts and cash payments;

• a $10.1 million increase in interest expense, excluding an increase of $1.4 million of debt-related amortization expense and other items, net, primarily due to the 2021 Notes offering in May 2011;

• a $3.6 million increase in current income tax expense, due to income earned by assets acquired from Anadarko in 2011 being subject to higher federal and state income tax for the 2011 pre-acquisition period as compared to 2010; and

• a $2.3 million increase in property and other tax expense, primarily due to ad valorem taxes for the Platte Valley, Bison and Wattenberg assets beginning in March 2011, July 2011, and August 2010, respectively.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2012, included the following:

• $638.1 million of capital expenditures;

• $458.6 million of cash paid for the MGR acquisition;

• $128.3 million of cash paid for the additional 24% membership interest in Chipeta; and

• $24.7 million of cash paid for equipment purchases from Anadarko.

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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;

• $149.7 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;

• $173.9 million of capital expenditures;

• $38.0 million paid for the White Cliffs acquisition; and

• a $5.6 million offset related to 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.

Financing Activities. Net cash provided by financing activities for the year ended December 31, 2012, included the following:

• $511.3 million and $156.4 million of net proceeds from our 2022 Notes offerings in June 2012 and October 2012, respectively, after original issue premiums and discounts, underwriting discounts and offering costs;

• $409.4 million of net proceeds from the issuance of WES common and general partner units sold in connection with the closing of the WGP IPO;

• $299.0 million of borrowings to fund the MGR acquisition; and

• $216.4 million of net proceeds from our June 2012 equity offering.

  Proceeds from our 2022 Notes offering were used to repay amounts outstanding under our RCF and our note payable to Anadarko.

  Net contributions from Anadarko attributable to intercompany balances were $171.1 million during 2012, attributable to the Non-Operated Marcellus Interest acquisition, the compensation expense allocated to us since the inception of the Incentive Plan and the settlement of intercompany transactions attributable to the Bison assets.

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

• $493.9 million of net proceeds from our 2021 Notes offering in May 2011, after underwriting and original issue discounts and offering costs;

• $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.

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  Proceeds from our 2021 Notes offering and our March 2011 equity offering were used to repay $619.0 million of borrowings outstanding under our RCF.

  Net distributions to Anadarko attributable to pre-acquisition intercompany balances were $36.0 million during 2011, attributable to the Non-Operated Marcellus Interest acquisition and the net non-cash settlement of intercompany transactions attributable to the MGR and Bison 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;

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

• $210.0 million to partially fund the Granger acquisition; and

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

  Proceeds from our May 2010 and November 2010 equity offerings were used to repay $361.0 million of borrowings outstanding under our RCF.

  Net contributions from Anadarko attributable to pre-acquisition intercompany balances were $91.0 million during 2010, attributable to the Non-Operated Marcellus Interest acquisition and the net non-cash settlement of intercompany transactions attributable to the Granger, Wattenberg, Bison and MGR assets.

  For the years ended December 31, 2012, 2011 and 2010, we paid $197.9 million, $140.1 million and $94.2 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $29.1 million, $33.6 million and $2.1 million during the years ended December 31, 2012, 2011 and 2010, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $17.3 million, $17.5 million and $13.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, representing the distributions for the four preceding quarterly periods ended September 30^th of the respective year.

Debt and credit facility. As of December 31, 2012, the carrying value of our outstanding debt consisted of $673.6 million of the 2022 Notes and $494.7 million of the 2021 Notes. 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.

Senior Notes. In June 2012, we completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, we issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The additional notes were issued under the same indenture as, and as a single class of securities with, the June 2012 issuance. The notes issued in June 2012 and in October 2012 are referred to as the “2022 Notes.” Including the effects of the issuance discount for the June 2012 offering, the issuance premium for the October 2012 offering, and underwriting discounts, the effective interest rate of the 2022 Notes was 4.040%. Interest is paid semi-annually on January 1 and July 1 of each year. Proceeds (net of underwriting discounts of $4.4 million and debt issuance costs) were used to repay all amounts then outstanding under our RCF and the $175.0 million note payable to Anadarko (see below), with the remaining net proceeds used for general partnership purposes.

    The 2022 Notes mature on July 1, 2022, unless redeemed at a redemption price that includes a make-whole premium. We may redeem the 2022 Notes in whole or in part, at any time before April 1, 2022, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2022 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 2022 Notes) plus 37.5 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 April 1, 2022, the 2022 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2022 Notes to be redeemed, plus accrued interest on the 2022 Notes to be redeemed to the date of redemption.

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    In May 2011, we completed the offering of the 2021 Notes at a price to the public of 98.778% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the 2021 Notes is paid semi-annually on June 1 and December 1 of each year. Proceeds from the offering of the 2021 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 RCF, with the remainder used for general partnership purposes. Upon issuance, the 2021 Notes were fully and unconditionally guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees were immediately released on June 13, 2012, upon the Subsidiary Guarantors becoming released from their obligations under our RCF, as discussed below.

    The 2021 Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. We may redeem the 2021 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 2021 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2021 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 2021 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 2021 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2021 Notes to be redeemed, plus accrued interest on the 2021 Notes to be redeemed to the date of redemption.

    The indentures governing the 2022 Notes and the 2021 Notes contain customary events of default including, among others, (i) default for 30 days in the payment of interest when due; (ii) default in payment, when due, of principal of or premium, if any, at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency. The indentures also contain covenants that limit, among other things, our ability, as well as that of certain of our subsidiaries, 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, 2012, we were in compliance with all covenants under the indentures.

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. In June 2012, the note payable to Anadarko was repaid in full with proceeds from the issuance of the 2022 Notes.

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 a $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%, in each case plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.71% and 1.80% at December 31, 2012 and 2011, respectively. 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. The facility fee rate was 0.25% at December 31, 2012 and 2011.

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  On June 13, 2012, following the receipt of a second investment grade rating as defined in the RCF, the guarantees provided by our wholly owned subsidiaries were released, and we are no longer subject to certain of the restrictive covenants associated with the RCF, including the maintenance of an interest coverage ratio and adherence to covenants that limit, among other things, our ability, and that of certain of our subsidiaries, to dispose of assets and make certain investments or payments. The RCF continues to contain certain covenants that limit, among other things, our ability, and that of certain of our subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of our business, enter into certain affiliate transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and a maximum consolidated leverage ratio as of the end of each fiscal quarter (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. As of December 31, 2012, we had no outstanding borrowings and $6.7 million in outstanding letters of credit issued under our $800.0 million RCF. At December 31, 2012, we were in compliance with all remaining covenants under the RCF. Refer to Note 2—Acquisitions and Note 12—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for a discussion of borrowing activity under the RCF in March 2013, related to acquisitions which closed after December 31, 2012.

    The 2022 Notes, the 2021 Notes and obligations under the RCF are recourse to our general partner. In turn, our general partner has been indemnified by a wholly owned subsidiary of Anadarko against any claims made against the general partner under the 2022 Notes, the 2021 Notes and/or 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 statements on file with the U.S. Securities and Exchange Commission.

    In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to $125.0 million of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of December 31, 2012, we had not issued any common units under this registration statement.

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. A substantial portion of our throughput, however, comes from producers that have investment-grade ratings.

  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, 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, Anadarko’s note payable to us, our omnibus agreement, the services and secondment agreement, contribution agreements or the commodity price swap agreements.

27

CONTRACTUAL OBLIGATIONS

  The following is a summary of our contractual cash obligations as of December 31, 2012, including the contractual obligations of the Non-Operated Marcellus Interest. 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 2013.

	Obligations by Period
thousands	2013		2014		2015		2016		2017		Thereafter		Total
Long-term debt
Principal	$	—	$	—	$	—	$	—	$	—	$	1,170,000	$	1,170,000
Interest		53,161		53,143		53,124		53,105		53,084		210,648		476,265
Asset retirement obligations		1,711		184		1,490		119		—		63,219		66,723
Capital expenditures		55,878		—		—		—		—		—		55,878
Credit facility fees		2,000		2,000		2,000		460		—		—		6,460
Environmental obligations		799		485		485		171		171		541		2,652
Operating leases		235		169		169		169		169		42		953
Total	$	113,784	$	55,981	$	57,268	$	54,024	$	53,424	$	1,444,450	$	1,778,931

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 that the amounts reflected in our recorded 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 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.

28

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, 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 23 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by approximately $14.6 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, our 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.

  During the fourth quarter of 2012, we recognized a $6.0 million impairment related to a gathering system in central Wyoming that was impaired to its estimated fair value using Level 3 fair-value inputs. Also in the fourth quarter of 2012, an impairment of $0.6 million was recognized for the original installation costs on a compressor relocated within our operating assets.

  During the year ended December 31, 2011, we recognized a $7.3 million impairment related to certain equipment and materials. The costs of the equipment and materials, previously capitalized as assets under construction and related to a Red Desert complex 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 was reclassified from within property, plant and equipment to other assets on the consolidated balance sheet and was approximately $10.6 million 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 that was impaired to its estimated fair value using Level 3 fair-value inputs.

29

During the year ended December 31, 2010, we recognized a $0.6 million impairment related to a compressor sold during the year to a third party, and a $0.3 million impairment due to cancelled capital projects and additional costs recorded on a project previously impaired to salvage value.

Impairments of goodwill. Goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the assets we have 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 acquired.

We evaluate whether goodwill has been impaired annually as of October 1, unless facts and circumstances make it necessary to test more frequently. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. 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, 2012, was $100.5 million for the gathering and processing reporting unit and $4.8 million for the transportation reporting unit.

The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If we conclude that the fair value of the reporting unit more than likely exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary. If the qualitative assessment is not performed or indicates the fair value of the reporting unit may be less than its carrying amount, we would compare the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill, and determine whether an impairment is necessary. In this manner, estimating the fair value of our reporting units was not necessary based on the evaluation as of October 1, 2012. However, fair-value estimates of our reporting units may be required for goodwill impairment testing in the future, and if the carrying amount of a reporting unit exceeds its fair value, goodwill is written down to the implied fair value 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, when necessary. Management uses information available to make these fair value estimates, including market multiples of earnings before interest, taxes, depreciation, and amortization (“EBITDA”). Specifically, our management estimates fair value by applying an estimated multiple to projected 2013 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, based on a qualitative assessment, that it is more likely than not that the fair value of each reporting unit 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 as of December 31, 2012 and 2011, represents the fair value, net of amortization, of the contracts we assumed 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.

In November 2012, Chipeta entered into interconnect agreements with a third party, whereby the third party will construct, own and operate an inlet interconnect to the Chipeta plant and a redelivery interconnect from the Chipeta plant. Chipeta will pay the third party $3.7 million and will be granted access rights to the third-party infrastructure, thereby providing us the ability to enter into processing agreements with additional third-party producers. Our intangible asset balance as of December 31, 2012, includes this payment, which will be amortized on a straight-line basis over the 10-year life of the agreements.

30

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.

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 our 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 multiples 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

None.

31

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, 2012, 2011 and 2010	3
Consolidated Balance Sheets as of December 31, 2012 and 2011	4
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2012, 2011 and 2010	5
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	6
Notes to Consolidated Financial Statements	7
Supplemental Quarterly Information	35

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, 2012 and 2011, 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, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

May 13, 2013

2

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
thousands except per-unit amounts	2012 (1)		2011 (1)		2010 (1)
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	249,997	$	227,535	$	192,286
Natural gas, natural gas liquids and condensate sales		436,423		417,547		369,903
Equity income and other, net		17,717		13,598		9,439
Total revenues – affiliates		704,137		658,680		571,628
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		132,333		119,934		60,987
Natural gas, natural gas liquids and condensate sales		71,916		84,836		26,134
Other, net		2,201		5,955		4,525
Total revenues – third parties		206,450		210,725		91,646
Total revenues		910,587		869,405		663,274
Operating expenses
Cost of product (2)		336,079		327,371		246,476
Operation and maintenance (2)		140,106		126,464		103,887
General and administrative (2)		99,212		40,564		29,970
Property and other taxes		19,688		16,579		14,273
Depreciation, amortization and impairments		120,608		113,133		91,129
Total operating expenses		715,693		624,111		485,735
Operating income		194,894		245,294		177,539
Interest income, net – affiliates		16,900		24,106		20,243
Interest expense (3)		(42,060)		(30,345)		(18,794)
Other income (expense), net		292		(44)		(538)
Income before income taxes		170,026		239,011		178,450
Income tax expense		20,715		32,150		21,517
Net income		149,311		206,861		156,933
Net income attributable to noncontrolling interests		14,890		14,103		11,005
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928
Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928
Pre-acquisition net (income) loss allocated to Anadarko		(27,435)		(52,599)		(31,797)
General partner interest in net (income) loss (4)		(28,089)		(8,599)		(3,067)
Limited partners’ interest in net income (4)	$	78,897	$	131,560	$	111,064
Net income per common unit – basic and diluted	$	0.84	$	1.64	$	1.66
Net income per subordinated unit – basic and diluted (5)	$	—	$	1.28	$	1.61

⁽¹⁾  Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

⁽²⁾  Cost of product includes product purchases from Anadarko (as defined in Note 1) of $145.3 million, $83.7 million and $95.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Operation and maintenance includes charges from Anadarko of $51.2 million, $51.3 million and $46.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. General and administrative includes charges from Anadarko of $92.8 million, $33.3 million and $24.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 5.

⁽³⁾  Includes affiliate (as defined in Note 1) interest expense of $2.8 million, $4.9 million and $6.9 million for the years ended December 31, 2012, 2011 and 2010, 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 Note 4.

⁽⁵⁾  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.

3

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
thousands except number of units	2012 (1)		2011 (1)
ASSETS
Current assets
Cash and cash equivalents	$	419,981	$	226,559
Accounts receivable, net (2)		50,233		90,328
Other current assets (3)		6,998		7,186
Total current assets		477,212		324,073
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		3,432,392		2,708,271
Less accumulated depreciation		714,436		587,119
Net property, plant and equipment		2,717,956		2,121,152
Goodwill		105,336		99,536
Other intangible assets		55,490		52,858
Equity investments		106,130		109,817
Other assets		27,798		24,143
Total assets	$	3,749,922	$	2,991,579
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables (4)	$	25,154	$	26,600
Accrued ad valorem taxes		11,949		8,186
Income taxes payable		552		495
Accrued liabilities (5)		147,651		92,037
Total current liabilities		185,306		127,318
Long-term debt – third parties		1,168,278		494,178
Note payable – Anadarko		—		175,000
Deferred income taxes		47,153		123,544
Asset retirement obligations and other		68,749		67,370
Total long-term liabilities		1,284,180		860,092
Total liabilities		1,469,486		987,410
Equity and partners’ capital
Common units (104,660,553 and 90,140,999 units issued and outstanding at December 31, 2012 and 2011, respectively)		1,957,066		1,495,253
General partner units (2,135,930 and 1,839,613 units issued and outstanding at December 31, 2012 and 2011, respectively)		52,752		31,729
Net investment by Anadarko		199,960		356,463
Total partners’ capital		2,209,778		1,883,445
Noncontrolling interests		70,658		120,724
Total equity and partners’ capital		2,280,436		2,004,169
Total liabilities, equity and partners’ capital	$	3,749,922	$	2,991,579

⁽¹⁾  Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

⁽²⁾  Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $19.1 million and zero as of December 31, 2012 and 2011, respectively.

⁽³⁾  Other current assets includes natural gas imbalance receivables from affiliates of $0.4 million and $0.5 million as of December 31, 2012 and 2011, respectively.

⁽⁴⁾  Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.5 million and $5.9 million as of December 31, 2012 and 2011, respectively.

⁽⁵⁾  Accrued liabilities include amounts payable to affiliates of $0.1 million and $0.3 million as of December 31, 2012 and 2011, respectively.

See accompanying Notes to Consolidated Financial Statements.

4

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

	Partners’ Capital
	Net
	Investment		Common		Subordinated		General		Noncontrolling
thousands	by Anadarko		Units		Units		Partner Units		Interests		Total
Balance at December 31, 2009 (1)	$	749,369	$	497,230	$	276,571	$	13,726	$	90,922	$	1,627,818
Net income		31,797		68,410		42,654		3,067		11,005		156,933
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)
Acquisition from affiliates		(684,487)		(49,662)		—		(631)		—		(734,780)
Net pre-acquisition contributions from (distributions to) Anadarko		95,881		—		—		—		—		95,881
Contribution of other assets from Anadarko		—		10,500		—		215		—		10,715
Elimination of net deferred tax liabilities		214,464		—		—		—		—		214,464
Other		1,219		864		44		9		(296)		1,840
Balance at December 31, 2010 (1)	$	408,243	$	810,717	$	282,384	$	21,505	$	90,462	$	1,613,311
Net income		52,599		110,542		21,018		8,599		14,103		206,861
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)
Acquisitions from affiliates		(92,666)		66,313		—		1,353		—		(25,000)
Contributions of equity-based compensation from Anadarko (3)		—		9,472		—		194		—		9,666
Net pre-acquisition contributions from (distributions to) Anadarko		(33,785)		—		—		—		—		(33,785)
Elimination of net deferred tax liabilities		22,072		—		—		—		—		22,072
Other		—		(267)		—		(47)		—		(314)
Balance at December 31, 2011 (1)	$	356,463	$	1,495,253	$	—	$	31,729	$	120,724	$	2,004,169
Net income		27,435		78,897		—		28,089		14,890		149,311
Issuance of common and general partner units, net of offering expenses		—		613,188		—		12,689		—		625,877
Contributions from noncontrolling interest owners		—		—		—		—		29,108		29,108
Distributions to noncontrolling interest owners		—		—		—		—		(17,303)		(17,303)
Distributions to unitholders		—		(175,639)		—		(22,211)		—		(197,850)
Acquisition from affiliates		(482,701)		23,458		—		479		—		(458,764)
Acquisition of additional 24% interest in Chipeta (4)		—		(44,071)		—		162		(77,195)		(121,104)
Contributions of equity-based compensation from Anadarko (3)		—		84,971		—		2,086		—		87,057
Net pre-acquisition contributions from (distributions to) Anadarko		192,259		(106,597)		—		—		—		85,662
Net distributions of other assets to Anadarko		—		(15,002)		—		(273)		(21)		(15,296)
Elimination of net deferred tax liabilities		106,504		—		—		—		—		106,504
Other		—		2,608		—		2		455		3,065
Balance at December 31, 2012 (1)	$	199,960	$	1,957,066	$	—	$	52,752	$	70,658	$	2,280,436

⁽¹⁾  Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. 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.

⁽³⁾  Associated with the Anadarko Incentive Plans for the year ended December 31, 2011, and associated with the Anadarko Incentive Plans and the Incentive Plan for the year ended December 31, 2012, as defined and described in Note 1 and Note 5.

⁽⁴⁾  See Note 2 for a description of the acquisition of Anadarko’s then remaining 24% membership interest in Chipeta in August 2012. The $43.9 million decrease to partners’ capital resulting from the August 2012 Chipeta acquisition together with net income attributable to Western Gas Partners, LP totaled $90.5 million for the year ended December 31, 2012.

See accompanying Notes to Consolidated Financial Statements.

5

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
thousands	2012 (1)		2011 (1)		2010 (1)
Cash flows from operating activities
Net income	$	149,311	$	206,861	$	156,933
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		120,608		113,133		91,129
Non-cash equity-based compensation expense		3,717		3,490		2,567
Deferred income taxes		30,113		16,580		9,539
Debt-related amortization and other items, net		2,319		3,110		1,705
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		22,916		(44,725)		(15,039)
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net		5,045		30,884		5,407
Change in other items, net		3,997		(16,495)		657
Net cash provided by operating activities		338,026		312,838		252,898
Cash flows from investing activities
Capital expenditures		(638,121)		(149,717)		(173,891)
Acquisitions from affiliates		(611,719)		(28,837)		(734,780)
Acquisitions from third parties		—		(301,957)		(18,047)
Investments in equity affiliates		(862)		(93)		(310)
Proceeds from sale of assets to affiliates		760		382		2,805
Proceeds from sale of assets to third parties		—		500		2,825
Net cash used in investing activities		(1,249,942)		(479,722)		(921,398)
Cash flows from financing activities
Borrowings, net of debt issuance costs		1,041,648		1,055,939		660,000
Repayments of debt		(549,000)		(869,000)		(361,000)
Increase (decrease) in outstanding checks		1,800		4,039		(4,805)
Revolving credit facility issuance costs		—		—		(12)
Proceeds from issuance of common and general partner units, net of offering expenses		625,877		335,317		345,803
Distributions to unitholders		(197,850)		(140,118)		(94,194)
Contributions from noncontrolling interest owners		29,108		33,637		2,053
Distributions to noncontrolling interest owners		(17,303)		(17,478)		(13,222)
Net contributions from (distributions to) Anadarko		171,058		(35,967)		90,967
Net cash provided by financing activities		1,105,338		366,369		625,590
Net increase (decrease) in cash and cash equivalents		193,422		199,485		(42,910)
Cash and cash equivalents at beginning of period		226,559		27,074		69,984
Cash and cash equivalents at end of period	$	419,981	$	226,559	$	27,074
Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets	$	15,296	$	(29)	$	7,827
Interest paid, net of capitalized interest	$	28,042	$	25,828	$	16,497
Taxes paid	$	495	$	190	$	507

⁽¹⁾  Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. 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 is a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to own, operate, acquire and develop midstream energy assets. The Partnership closed its initial public offering (“IPO”) to become publicly traded in 2008.

For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership (see Western Gas Equity Partners, LP below, Note 4 and Note 5). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko Petroleum Corporation” refers to Anadarko Petroleum Corporation excluding its subsidiaries and affiliates. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”). “Equity investment throughput” refers to the Partnership’s 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as third-party producers and customers. As of December 31, 2012, the Partnership owned and operated twelve natural gas gathering systems, seven natural gas treating facilities, seven natural gas processing facilities, two NGL pipelines, one interstate natural gas pipeline, and one intrastate natural gas pipeline. In addition, including the effect of the acquisition of the Non-Operated Marcellus Interest (see Note 2), the Partnership had interests in two non-operated natural gas gathering systems, one operated natural gas gathering system, and two operated natural gas processing facilities, with separate interests in Fort Union, White Cliffs and Rendezvous accounted for under the equity method. These assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming), north-central Pennsylvania, and the Mid-Continent (Kansas and Oklahoma). The Partnership had facilities under construction in South Texas and Northeast Colorado at the end of 2012.

Western Gas Equity Partners, LP. WGP was formed to own three types of interests in the Partnership: (i) the 2.0% general partner interest through WGP’s 100% ownership of the Partnership’s general partner; (ii) all of the incentive distribution rights (“IDRs”) in the Partnership; and (iii) all of the limited partner interests in the Partnership held by Anadarko at the time of WGP’s IPO. WGP has no independent operations or material assets other than its partnership interests in WES.

  In December 2012, WGP completed its IPO of 19,758,150 common units representing limited partner interests in WGP, including 2,577,150 common units issued in connection with the full exercise of the underwriters’ over-allotment option, at a price of $22.00 per common unit. WGP used the net proceeds from the offering to purchase common and general partner units of the Partnership (see Note 4) resulting in aggregate proceeds to the Partnership of approximately $409.4 million, which will be used for general partnership purposes, including the funding of capital expenditures.

Basis of presentation. The consolidated financial statements 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. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 33.75% share of the assets, liabilities, revenues and expenses attributable to the Non-Operated Marcellus Interest and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system in the accompanying consolidated financial statements. All significant intercompany transactions have been eliminated. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial statements.

7

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement (the “Chipeta LLC agreement”). On August 1, 2012, the Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (the “additional Chipeta interest”). Prior to this transaction, the interests in Chipeta held by Anadarko and a third-party member were reflected as noncontrolling interests in the consolidated financial statements. The acquisition of Anadarko’s then remaining 24% interest was accounted for on a prospective basis as the Partnership acquired an additional interest in an already-consolidated entity. As such, effective August 1, 2012, the Partnership’s noncontrolling interest excludes the financial results and operations of the additional Chipeta interest. The remaining 25% membership interest held by the third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented. See Note 2.

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of December 31, 2012. Because Anadarko controls the Partnership through its control of WGP, which owns the Partnership’s general partner, each of the Partnership’s acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such assets as of the date of common control. See Note 2.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of Partnership assets from Anadarko, including the Non-Operated Marcellus Interest, 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 reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other methods considered reasonable under the particular 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 business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

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).

8

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. 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 debts on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. As of December 31, 2012, there was no reserve for bad debts. The third-party accounts receivable balance at December 31, 2011, was 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’ pipelines. 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, 2012, natural gas imbalance receivables and payables were approximately $1.7 million and $3.1 million, respectively. As of December 31, 2011, natural gas imbalance receivables and payables were approximately $2.3 million and $3.1 million, respectively. Changes in natural gas imbalances are reported in equity income and other, net for imbalance receivables or in cost of product for imbalance payables.

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 assets acquired 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. All construction-related direct labor and material costs are capitalized. 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 using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. 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.

9

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Management 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. Refer to Note 7 for a description of impairments recorded during the years ended December 31, 2012, 2011 and 2010.

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. 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 a third-party entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s goodwill balance does not represent, and in some cases is significantly different from, 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. During 2011, the carrying amount of goodwill increased from $82.1 million to $99.5 million, due to the acquisition of the Non-Operated Marcellus Interest. The carrying amount of goodwill is not deductible for tax purposes. During 2012, the carrying amount of goodwill increased from $99.5 million to $105.3 million, attributable to allocated goodwill related to the acquisition of the additional 24% interest in Chipeta (see Note 2), 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 Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. For years 2011 and prior, the first step in the goodwill impairment test was to compare the fair value of each reporting unit to which goodwill had been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. For years 2012 and forward, an initial qualitative assessment may be performed prior to proceeding to the first step performed in previous years (described above). If the Partnership concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value through a charge to operating expense based on a hypothetical purchase price allocation. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement. Estimating the fair value of the Partnership’s reporting units was not necessary based on the evaluation as of October 1, 2012, and no goodwill impairment has been recognized in these consolidated financial statements.

Other intangible assets. The intangible asset balance in the consolidated balance sheets includes 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. Customer contract intangible assets 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.

10

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

In November 2012, Chipeta entered into interconnect agreements with a third party, whereby the third party will construct, own and operate an inlet interconnect to the Chipeta plant and a redelivery interconnect from the Chipeta plant. Chipeta will pay the third party $3.7 million and will be granted access rights to the third-party infrastructure, thereby providing the Partnership with the ability to enter into processing agreements with additional third-party producers. The Partnership’s intangible asset balance as of December 31, 2012, includes this payment, which will be amortized on a straight-line basis over the 10-year life of the agreements.

The Partnership assesses intangible assets 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. See Property, plant and equipment within this Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. No intangible asset impairment has been recognized in these consolidated financial statements. As of December 31, 2012, the carrying value of the Partnership’s intangible assets was $55.5 million, net of $2.0 million of accumulated amortization. The Partnership estimates that it will record $1.4 million of intangible asset amortization for each of the next five years. As of December 31, 2011, the carrying value of the Partnership’s intangible assets was $52.9 million, net of $0.9 million of accumulated amortization.

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, 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
Investment earnings, net of amortization		6,383		7,871		1,857
Contributions		—		862		—
Distributions		(5,198)		(8,876)		(6,586)
Balance at December 31, 2012	$	23,453	$	17,567	$	65,110

⁽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.

⁽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. 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.

11

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The investment balance at December 31, 2012, includes $2.6 million and $45.9 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. (the entity that previously 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 such 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 investment balance in White Cliffs at December 31, 2012, is $9.8 million less than the Partnership’s underlying equity in White Cliffs’ net assets as of December 31, 2012, 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 adjusted to its expected settlement value through accretion expense, which is reported within depreciation, amortization and impairments in the consolidated statements of income. 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 obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations 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 gather, process, compress, treat and transport Anadarko and third-party natural gas, condensate, NGLs and crude oil in the United States.

12

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 cost-of-service gathering agreements, the Partnership earns fees for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate are sold. The percentage of the product sale paid to the producer is recorded as a related cost of product expense.

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 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. 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 than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price uncertainty that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. See Note 5. 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.

Proceeds from the sale of residue, 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.

13

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 2,144,947 units remain available for future issuance as of December 31, 2012. 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) the 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 and 2012 Omnibus Incentive Compensation Plans (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”). Equity-based compensation granted under the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities and is recorded as an adjustment to partners’ capital in the consolidated financial statements at the time of contribution. 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. 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. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership’s acquisition of these assets from Anadarko.

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 satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2012 or 2011.

With respect to assets acquired from Anadarko, the Partnership recorded Anadarko’s historic current and deferred income taxes for the periods prior to the Partnership’s ownership of the assets. For periods subsequent to the Partnership’s acquisition, the Partnership is not subject to tax except for the Texas margin tax and accordingly, does not record current and deferred federal income taxes related to the assets acquired from Anadarko.

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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 partner units and 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 the years ended December 31, 2012 and 2011, other assets on the consolidated balance sheets include $0.4 million and $0.7 million, respectively, for a receivable recognized in conjunction with the capital lease component of a processing agreement assumed in connection with the acquisition of Mountain Gas Resources, LLC (“MGR”). See Note 2. The agreement, in which WES 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 consolidated statements of income.

Accounts Payable. Included in accounts payable at December 31, 2012 and 2011, are liabilities of $11.6 million and $9.8 million, respectively, representing the amount by which checks issued, but not presented to the Partnership’s banks for collection, exceed balances in applicable bank accounts.

15

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, 2012, 2011 and 2010, and identifies the funding sources for such acquisitions:

thousands except unit and     percent amounts	Acquisition   Date		Percentage   Acquired		Borrowings		Cash      On Hand		Common     Units Issued		GP Units     Issued
Granger (1)		01/29/10		100%	$	210,000	$	31,680		620,689		12,667
Wattenberg (2)		08/02/10		100%		450,000		23,100		1,048,196		21,392
White Cliffs (3)		09/28/10		10%		—		38,047		—		—
Platte Valley (4)		02/28/11		100%		303,000		602		—		—
Bison (5)		07/08/11		100%		—		25,000		2,950,284		60,210
MGR (6)		01/13/12		100%		299,000		159,587		632,783		12,914
Chipeta (7)		08/01/12		24%		—		128,250		151,235		3,086

⁽¹⁾  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.”

⁽²⁾  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.”

⁽³⁾  White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. 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.”

⁽⁴⁾  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.”

⁽⁵⁾  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. The Bison assets were placed in service in June 2010.

⁽⁶⁾  The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a 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.”

⁽⁷⁾  The Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (as described in Note 1), with the Partnership receiving distributions related to the additional interest beginning July 1, 2012. This transaction brought the Partnership’s total membership interest in Chipeta to 75%. The remaining 25% membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented.

Non-Operated Marcellus Interest acquisition. On March 1, 2013, the Partnership acquired a 33.75% interest in both the Liberty and Rome gas gathering systems from Anadarko Marcellus Midstream, L.L.C. (“AMM”), a wholly owned subsidiary of Anadarko. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” Consideration paid includes $465.5 million in cash and 449,129 common units of the Partnership. The Partnership funded the cash consideration through $250.0 million in borrowings under its revolving credit facility and $215.5 million of cash on hand.

16

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.  ACQUISITIONS (CONTINUED)

Anadarko and a third party entered into a 50/50 Joint Exploration Agreement, dated September 1, 2006, covering counties in north-central Pennsylvania within an Area of Mutual Interest that the parties designated as “Area A.” Initial construction of the midstream assets within Area A began in May 2008, and in December 2011, following various sales of interests, AMM and three third-party owners (the “system owners”) entered into a Construction, Ownership and Operation agreement (the “COO Agreement”) to jointly own and develop the midstream assets in Area A (the “AMI Assets”). As of December 31, 2012, four parties, including AMM, were owners of the AMI Assets.

The AMI Assets consist of the Liberty Gas Gathering System (the “Liberty GGS”) and the Rome Gas Gathering System (the “Rome GGS”). Both systems gather gas from the third-party system owners, Anadarko, and other third parties producing in the area.

The gas gathering agreements for the AMI Assets provide for gathering and compression rates (either fixed or based on a cost-of-service model, depending on the agreement) and have various expiration dates through 2027. The gathering and compression rates for the anchor shippers (as defined in the COO Agreement) are based on a cost-of-service model, which is reviewed on an annual basis, and the gathering fee is adjusted accordingly.

Due to Anadarko’s control of the Partnership through its ownership and control of WGP, the acquisition of the Non-Operated Marcellus Interest is considered a transfer of net assets under common control. As such, the Partnership’s historical financial statements previously filed with the SEC have been recast in this Current Report on Form 8-K to include the results attributable to the Non-Operated Marcellus Interest as of May 2008, when construction began on the Liberty GGS and Rome GGS. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko 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 Non-Operated Marcellus Interest during the periods reported.

The following tables present the impact to the historical consolidated statements of income attributable to the Non-Operated Marcellus Interest:

	Year Ended December 31, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	849,440	$	61,147	$	910,587
Net income		121,876		27,435		149,311
	Year Ended December 31, 2011
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	823,265	$	46,140	$	869,405
Net income		188,346		18,515		206,861
	Year Ended December 31, 2010
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	663,274	$	—	$	663,274
Net income (loss)		157,197		(264)		156,933

17

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.  PARTNERSHIP DISTRIBUTIONS

The partnership agreement of Western Gas Partners, LP 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:

thousands except per-unit amounts Quarters Ended	Total Quarterly      Distribution per Unit	Total Cash         Distribution	Date of         Distribution
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	$    0.440	$  43,027	February 2012
2012
March 31	$    0.460	$  46,053	May 2012
June 30	$    0.480	$  52,425	August 2012
September 30	$    0.500	$  56,346	November 2012
December 31 (1)	$    0.520	$  65,657	February 2013

⁽¹⁾  On January 21, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

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		Marginal Percentage 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.

4.  EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public offerings of its common units during 2010, 2011 and 2012:

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
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
June 2012 equity offering		5,000,000		102,041		43.88		7,468		216,409

⁽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 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 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% general partner interest.

Common, subordinated and general partner units. The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.” In connection with the closing of the WGP IPO in December 2012, WGP purchased common and general partner units of the Partnership at a price of $46.00 per unit, pursuant to a unit purchase agreement among the Partnership, the general partner and WGP.

19

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

The following table summarizes common and general partner units issued during the years ended December 31, 2011 and 2012:

	Common Units		Subordinated Units		General Partner Units		Total
Balance at December 31, 2010		51,036,968		26,536,306		1,583,128		79,156,402
March 2011 equity offering		3,852,813		—		78,629		3,931,442
Long-Term Incentive Plan awards		14,628		—		299		14,927
Bison acquisition		2,950,284		—		60,210		3,010,494
Conversion of subordinated units		26,536,306		(26,536,306)		—		—
September 2011 equity offering		5,750,000		—		117,347		5,867,347
Balance at December 31, 2011		90,140,999		—		1,839,613		91,980,612
MGR acquisition		632,783		—		12,914		645,697
Long-Term Incentive Plan awards		12,570		—		257		12,827
June 2012 equity offering		5,000,000		—		102,041		5,102,041
Chipeta acquisition		151,235		—		3,086		154,321
WGP unit purchase agreement		8,722,966		—		178,019		8,900,985
Balance at December 31, 2012		104,660,553		—		2,135,930		106,796,483

Conversion of subordinated units. Upon payment of the cash distribution for the second quarter of 2011, the requirements for the conversion of all subordinated units were satisfied under the partnership agreement. As a result, the 26,536,306 subordinated units were converted into common units on August 15, 2011, on a one-for-one basis. 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.

WGP and Affiliate holdings of Partnership equity. As of December 31, 2012, WGP and Affiliates held 49,296,205 of the Partnership’s common units, representing a 46.2% limited partner interest in the Partnership, and, through its ownership of the general partner, indirectly held 2,135,930 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the IDRs. As of December 31, 2012, the public held 55,364,348 common units, representing a 51.8% limited partner interest in the Partnership.

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 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 and the limited partners in accordance with their respective ownership percentages (see Net income per common unit in Note 1).

Basic and diluted net income per common unit are 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.

20

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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	2012		2011		2010
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928
Pre-acquisition net (income) loss allocated to Anadarko		(27,435)		(52,599)		(31,797)
General partner interest in net (income) loss		(28,089)		(8,599)		(3,067)
Limited partners’ interest in net income	$	78,897	$	131,560	$	111,064
Net income allocable to common units	$	78,897	$	110,542	$	68,410
Net income allocable to subordinated units		—		21,018		42,654
Limited partners’ interest in net income	$	78,897	$	131,560	$	111,064
Net income per unit – basic and diluted
Common units	$	0.84	$	1.64	$	1.66
Subordinated units	$	—	$	1.28	$	1.61
Weighted average units outstanding – basic and diluted
Common units		93,936		67,333		41,287
Subordinated units		—		16,431		26,536

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, 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 Partnership’s omnibus agreement. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues. 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 net investment by Anadarko in connection with the acquisition of the Partnership assets. Subsequent to the acquisition of Partnership assets from Anadarko, 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. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

Note receivable from and amounts payable to Anadarko. Concurrent with the closing of the Partnership’s May 2008 IPO, 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 $334.8 million and $303.7 million at December 31, 2012, and December 31, 2011, 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. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.

21

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

In 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko, which was repaid in full in June 2012 using the proceeds from the issuance of the 4.000% Senior Notes due 2022 (the “2022 Notes”). See Note 10.

During the first quarter of 2012, the board of directors of the Partnership’s general partner approved the continued construction by the Partnership of the Brasada and Lancaster gas processing facilities in South Texas and Northeast Colorado, respectively, which were previously under construction by Anadarko. The Partnership agreed to reimburse Anadarko for $18.9 million of certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. In February 2012, these expenditures were transferred to the Partnership and a corresponding current payable was recorded, which the Partnership repaid during the fourth quarter of 2012.

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 commodity price 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 Granger, Hilight, Hugoton, Newcastle, MGR and Wattenberg assets, with various expiration dates through December 2016. 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. The Partnership has not entered into any new commodity price swap agreements since the fourth quarter of 2011.

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of December 31, 2012:

per barrel except natural gas	2013			2014			2015			2016
Ethane	$	18.32 –	30.10	$	18.36 –	30.53	$	18.41 –	23.41	$	23.11
Propane	$	45.90 –	55.84	$	46.47 –	53.78	$	47.08 –	52.99	$	52.90
Isobutane	$	60.44 –	77.66	$	61.24 –	75.13	$	62.09 –	74.02	$	73.89
Normal butane	$	53.20 –	68.24	$	53.89 –	66.01	$	54.62 –	65.04	$	64.93
Natural gasoline	$	70.89 –	92.23	$	71.85 –	83.04	$	72.88 –	81.82	$	81.68
Condensate	$	74.04 –	85.84	$	75.22 –	83.04	$	76.47 –	81.82	$	81.68
Natural gas (per MMbtu)	$	3.75 –	6.09	$	4.45 –	6.20	$	4.66 –	5.96	$	4.87

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

	Year Ended December 31,
thousands	2012		2011		2010
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	37,665	$	33,845	$	20,200
Natural gas liquids sales		66,260		(36,802)		2,953
Total		103,925		(2,957)		23,153
Losses on commodity price swap agreements related to purchases (2)		(89,710)		(27,234)		(23,344)
Net gains (losses) on commodity price swap agreements	$	14,215	$	(30,191)	$	(191)

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

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

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Gas gathering and processing agreements. The Partnership has significant gas gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The gathering agreements of the Partnership’s initial assets allow for rate resets that target an 18% return on invested capital in those assets. Approximately 64%, 67% and 73% of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) for the years ended December 31, 2012, 2011 and 2010, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 59%, 64% and 66% of the Partnership’s processing throughput (excluding equity investment throughput and volumes measured in barrels) for the years ended December 31, 2012, 2011 and 2010, 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 for the year ended December 31, 2010 and the cap expired on December 31, 2010. Expenses in excess of the cap for the year ended December 31, 2010 were recorded as capital contributions from Anadarko and did not impact the Partnership’s cash flows. The Partnership also incurred $8.0 million in public company expenses, such as external audit and consulting fees, not subject to the cap previously contained in the omnibus agreement, during the year ended December 31, 2010.

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 reimbursed by the Partnership in exchange for services provided under the omnibus agreement. Such amount was $21.7 million for the year ended December 31, 2012, comprised of $14.9 million of general and administrative expenses and $6.8 million of public company expenses. The Partnership reimbursed Anadarko $19.5 million for the year ended December 31, 2011, comprised of $11.8 million of general and administrative expenses and $7.7 million of public company expenses. 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 include costs allocated by Anadarko for expenses incurred under 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 its estimated share of applicable state taxes. These taxes include income taxes attributable to the Partnership’s income which are directly borne by Anadarko through its filing of a combined or consolidated tax return with respect to periods including and subsequent to the acquisition of the Partnership assets from Anadarko. Anadarko may use its own tax attributes to reduce or eliminate the tax liability of its combined or consolidated group, which may include the Partnership as a member. However, under this circumstance, the Partnership nevertheless is required to reimburse Anadarko for its allocable share of taxes that would have been owed had tax attributes not been available to Anadarko.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Allocation of costs. For periods prior to the Partnership’s acquisition of the Partnership assets, the consolidated financial statements 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 allocates costs to the Partnership for its share of personnel costs, including costs associated with equity-based compensation plans, non-contributory defined pension and postretirement plans, defined contribution savings plan pursuant to the omnibus agreement and services and secondment agreement. 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. Most general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, and do not include any mark-up or subsidy component. With respect to allocated costs, management believes the allocation method employed by Anadarko is reasonable. Although it is not practicable to determine what the amount of these direct and allocated costs would be if the Partnership were to directly obtain these services, management believes that aggregate costs charged to the Partnership by Anadarko are reasonable.

Long-term incentive plan. The general partner awards phantom units under the LTIP primarily to its Chief Executive Officer and its independent directors. 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 is recognized over the vesting period and was approximately $0.4 million, $0.3 million and $0.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. As of December 31, 2012, there was $0.8 million of unrecognized compensation expense attributable to the outstanding awards under the LTIP, of which $0.7 million will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 2.2 years.

The following table summarizes LTIP award activity for the years ended December 31, 2012, 2011 and 2010:

	2012				2011				2010
	Weighted- Average Grant-Date Fair Value		Units		Weighted- Average Grant-Date Fair Value		Units		Weighted- Average Grant-Date Fair Value		Units
Phantom units outstanding at beginning of year	$	33.92		23,978	$	20.19		17,503	$	15.02		21,970
Vested	$	33.20		(14,260)	$	20.51		(15,119)	$	15.02		(19,751)
Granted	$	45.91		15,901	$	35.66		21,594	$	20.94		15,284
Phantom units outstanding at end of year	$	41.77		25,619	$	33.92		23,978	$	20.19		17,503

Anadarko Incentive Plans. For the years ended December 31, 2012, 2011 and 2010, the Partnership’s general and administrative expenses include $3.3 million, $2.5 million and $2.3 million, respectively, of equity-based compensation expense for awards granted to the executive officers of the general partner and other employees under the Anadarko Incentive Plans, which was allocated to the Partnership by Anadarko. As of December 31, 2012, the Partnership estimates that $4.4 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 1.9 years. As of December 31, 2012, the compensation cost related to performance-based awards under the Anadarko Incentive Plans that could be allocated to the Partnership during the next two years was approximately $0.1 million.

During the fourth quarter of 2011, the Partnership recorded $9.7 million to partners’ capital in its consolidated financial statements for accumulated compensation expense attributable to the Anadarko Incentive Plans.

24

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

The Incentive Plan. For the years ended December 31, 2012, 2011 and 2010, the Partnership’s general and administrative expenses include $68.8 million, $11.4 million and $3.1 million, respectively, of compensation expense for grants of Unit Value Rights (“UVRs”), Unit Appreciation Rights (“UARs”) and Distribution Equivalent Rights (“DERs”) under the Incentive Plan to certain executive officers of the general partner as a component of their compensation, which was allocated to the Partnership by Anadarko.

Under the terms of the Incentive Plan, the value of a UAR was equal to an amount calculated by dividing the “determined value” by 1,000,000, less the applicable UAR exercise price. Prior to WGP’s IPO in December 2012, the value of awards issued under the Incentive Plan were 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. UARs outstanding under the Incentive Plan as of December 31, 2011 and 2010, were valued at $634.00 per UAR and $215.00 per UAR, respectively. Anadarko and the Incentive Plan participants entered into a Memorandum of Understanding (the “MOU”) that, among other things, confirmed the intent and the understanding that the WGP IPO resulted in the vesting of all unvested Incentive Plan awards and that the value of the Partnership’s common units held by WGP prior to its IPO would not be considered in the valuation of the Incentive Plan awards.

The WGP IPO and concurrent execution of the MOU triggered the exercise of all outstanding UARs and lump-sum cash payments (less any applicable withholding taxes) to plan participants equal to the value of each award, less its exercise price, if applicable. Pursuant to the MOU, the “determined value” was defined as equal to the aggregate WGP equity value, as determined using the market price of WGP based on the IPO price of WGP’s common units, reduced by the market value of the Partnership’s common units owned by WGP prior to its IPO (based on the closing price of the Partnership’s common units on the day of the pricing of the IPO). Awards outstanding under the Incentive Plan at the time of the WGP IPO (and the effective termination of the Incentive Plan) were valued at $2,745.00 per UAR and $12.00 per DER. Outstanding UVRs that vested concurrent with the WGP IPO were cash-settled at their grant-date fair value.

In addition to the execution of the MOU, WGP, the Partnership’s general partner and Anadarko entered into a contribution agreement whereby cash, in an amount equal to the aggregate cash payment required to settle all outstanding awards, was contributed to the Partnership’s general partner by Anadarko. The cash payments made in connection with WGP’s IPO and the vesting, exercise and settlement of all outstanding awards under the Incentive Plan as described above, impacted the Partnership’s cash flows to the extent compensation expense was allocated to the Partnership since the inception of the Incentive Plan. The compensation expense allocated to the Partnership since the inception of the Incentive Plan, and subsequently contributed by Anadarko during the fourth quarter of 2012, was recorded to partners’ capital in the consolidated financial statements.

Equipment purchase and sale. The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment:

	Purchases						Sales
	Year Ended December 31,
thousands	2012		2011		2010		2012		2011		2010
Net carrying value	$	8,009	$	1,998	$	429	$	393	$	316	$	2,576
Cash consideration		24,705		3,837		361		760		382		2,805
Partners’ capital adjustment	$	16,696	$	1,839	$	(68)	$	367	$	66	$	229

25

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Capital expenditures transfer. As described in Note receivable from and amounts payable to Anadarko above, Anadarko incurred certain expenditures related to the construction of the Brasada and Lancaster gas processing facilities during 2011. These amounts, along with related capitalized interest, were transferred to the Partnership in the first quarter of 2012, and are included in property, plant and equipment as of December 31, 2012.

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	2012		2011		2010
Revenues (1)	$	704,137	$	658,680	$	571,628
Cost of product (1)		145,250		83,722		95,667
Operation and maintenance (2)		51,237		51,339		46,379
General and administrative (3)		92,847		33,305		24,137
Operating expenses		289,334		168,366		166,183
Interest income, net (4)		16,900		24,106		20,243
Interest expense (5)		2,766		4,935		6,924
Distributions to unitholders (6)		98,280		68,039		52,337
Contributions from noncontrolling interest owners (7)		12,588		16,476		2,019
Distributions to noncontrolling interest owners (7)		6,528		9,437		6,476

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

⁽²⁾  Represents expenses incurred during periods including and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.

⁽³⁾  Represents general and administrative expense incurred during periods including and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see Anadarko Incentive Plans and Incentive Plan within this Note 5).

⁽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 aforementioned assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.

⁽⁵⁾  Represents interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. During 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note receivable from and amounts payable to Anadarko within this Note 5.

⁽⁶⁾  Represents distributions paid under the partnership agreement.

⁽⁷⁾  As described in Note 1 and Note 2, the Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.

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 consolidated statements of income.

26

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6.  INCOME TAXES

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

	Year Ended December 31,
thousands	2012		2011		2010
Current income tax expense (benefit)
Federal income tax expense (benefit)	$	(7,555)	$	15,248	$	10,476
State income tax expense (benefit)		(1,843)		322		1,502
Total current income tax expense (benefit)		(9,398)		15,570		11,978
Deferred income tax expense (benefit)
Federal income tax expense		22,328		13,075		9,673
State income tax expense (benefit)		7,785		3,505		(134)
Total deferred income tax expense		30,113		16,580		9,539
Total income tax expense	$	20,715	$	32,150	$	21,517

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	2012		2011		2010
Income before income taxes	$	170,026	$	239,011	$	178,450
Statutory tax rate		0%		0%		0%
Tax computed at statutory rate	$	—	$	—	$	—
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition		17,251		29,502		20,534
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)		2,206		1,984		683
Texas margin tax expense (benefit)		1,258		664		300
Income tax expense	$	20,715	$	32,150	$	21,517
Effective tax rate		12%		13%		12%

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

	December 31,
thousands	2012		2011
Credit carryforwards	$	14	$	14
Net current deferred income tax assets		14		14
Depreciable property		(47,558)		(99,733)
Partnership basis		—		(24,481)
Credit carryforwards		541		556
Other		(136)		114
Net long-term deferred income tax liabilities		(47,153)		(123,544)
Total net deferred income tax liabilities	$	(47,139)	$	(123,530)

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.

27

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      Useful Life		December 31,
thousands			2012		2011
Land		n/a	$	501	$	364
Gathering systems		5 to 47 years		2,911,572		2,479,184
Pipelines and equipment		15 to 45 years		91,126		90,883
Assets under construction		n/a		422,002		132,913
Other		3 to 25 years		7,191		4,927
Total property, plant and equipment				3,432,392		2,708,271
Accumulated depreciation				714,436		587,119
Net property, plant and equipment			$	2,717,956	$	2,121,152

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. See Note 8.

During the fourth quarter of 2012, the Partnership recognized a $6.0 million impairment related to a gathering system in central Wyoming that was impaired to its estimated fair value using Level 3 fair-value inputs. Also in the fourth quarter of 2012, an impairment of $0.6 million was recognized for the original installation costs on a compressor relocated within the Partnership’s operating assets.

During the year ended December 31, 2011, the Partnership recognized a $7.3 million impairment related to 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 was reclassified from within property, plant and equipment to other assets on the consolidated balance sheet and was approximately $10.6 million 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 that was impaired to its estimated fair value using Level 3 fair-value inputs.

During the year ended December 31, 2010, the Partnership recognized a $0.6 million impairment related to a compressor sold during the year to a third party, and a $0.3 million impairment due to cancelled capital projects and additional costs recorded on a project previously impaired to salvage value.

8. ACCRUED LIABILITIES

A summary of accrued liabilities is as follows:

	December 31,
thousands	2012		2011
Accrued capital expenditures	$	112,311	$	60,391
Accrued plant purchases		16,350		19,607
Accrued interest expense		15,868		2,251
Accrued charges under COO Agreement (see Note 2)		—		5,299
Short-term asset retirement obligations		1,711		875
Short-term remediation and reclamation obligations		799		1,679
Other		612		1,935
Total accrued liabilities	$	147,651	$	92,037

28

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	2012		2011
Carrying amount of asset retirement obligations at beginning of year	$	64,345	$	45,269
Liabilities incurred		9,414		15,462
Liabilities settled		(786)		(133)
Accretion expense		4,270		3,791
Revisions in estimated liabilities		(10,520)		(44)
Carrying amount of asset retirement obligations at end of year	$	66,723	$	64,345

Revisions in estimated liabilities for the year ended December 31, 2012, related primarily to the change in the estimated timing of settling the Partnership’s asset retirement obligations at the Wattenberg system. The liabilities incurred for the year ended December 31, 2012, represented the increase in asset retirement obligations primarily related to the capital expansion at the Wattenberg system.

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

10.  DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt as of December 31, 2012 and 2011:

	December 31, 2012						December 31, 2011
thousands	Principal		Carrying Value		Fair Value(1)		Principal		Carrying Value		Fair Value(1)
4.000% Senior Notes due 2022	$	670,000	$	673,617	$	669,928	$	—	$	—	$	—
5.375% Senior Notes due 2021		500,000		494,661		499,946		500,000		494,178		499,950
Note payable to Anadarko		—		—		—		175,000		175,000		174,528
Total debt outstanding	$	1,170,000	$	1,168,278	$	1,169,874	$	675,000	$	669,178	$	674,478

⁽¹⁾  Fair value is measured using Level 2 inputs.

29

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, 2012 and 2011:

thousands	Carrying Value
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
Revolving credit facility borrowings		374,000
Issuance of 4.000% Senior Notes due 2022		670,000
Repayment of revolving credit facility		(374,000)
Repayment of note payable to Anadarko		(175,000)
Revolving credit facility borrowings – Swingline		20,000
Repayment of revolving credit facility – Swingline		(20,000)
Other and changes in debt discount or premium		4,100
Balance as of December 31, 2012	$	1,168,278

Senior Notes. In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, the Partnership issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The additional notes were issued under the same indenture as, and as a single class of securities with, the June 2012 issuance. The notes issued in June 2012 and in October 2012 are collectively referred to as the “2022 Notes.” Including the effects of the issuance discount for the June 2012 offering, the issuance premium for the October 2012 offering, and underwriting discounts, the effective interest rate of the 2022 Notes was 4.040%. Interest is paid semi-annually on January 1 and July 1 of each year. Proceeds (net of underwriting discounts of $4.4 million and debt issuance costs) were used to repay all amounts then outstanding under the Partnership’s revolving credit facility (“RCF”) and the $175.0 million note payable to Anadarko (see below), with the remaining net proceeds used for general partnership purposes.

The 2022 Notes mature on July 1, 2022, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the 2022 Notes in whole or in part, at any time before April 1, 2022, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2022 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 2022 Notes) plus 37.5 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 April 1, 2022, the 2022 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2022 Notes to be redeemed, plus accrued interest on the 2022 Notes to be redeemed to the date of redemption.

30

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) at a price to the public of 98.778% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the 2021 Notes is paid semi-annually on June 1 and December 1 of each year. Proceeds from the offering of the 2021 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 RCF, with the remainder used for general partnership purposes. Upon issuance, the 2021 Notes were 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 were immediately released on June 13, 2012, upon the Subsidiary Guarantors becoming released from their obligations under the RCF, as discussed below.

The 2021 Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the 2021 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 2021 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2021 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 2021 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 2021 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2021 Notes to be redeemed, plus accrued interest on the 2021 Notes to be redeemed to the date of redemption.

The indentures governing the 2022 Notes and the 2021 Notes contain customary events of default including, among others, (i) default for 30 days in the payment of interest when due; (ii) default in payment, when due, of principal of or premium, if any, at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency. The indentures also contain covenants that limit, among other things, the ability of the Partnership, as well as that of certain of the Partnership’s subsidiaries, to (i) create liens on 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 the Partnership’s properties or assets to another entity. At December 31, 2012, the Partnership was in compliance with all covenants under the indentures.

Note payable to Anadarko. In 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. In June 2012, the note payable to Anadarko was repaid in full with proceeds from the issuance of the 2022 Notes.

Revolving credit facility. In March 2011, the Partnership 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 a $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%, in each case plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.71% and 1.80% at December 31, 2012 and 2011, 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% at December 31, 2012 and 2011.

31

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

On June 13, 2012, following the receipt of a second investment grade rating as defined in the RCF, the guarantees provided by the Partnership’s wholly owned subsidiaries were released, and the Partnership is no longer subject to certain of the restrictive covenants associated with the RCF, including the maintenance of an interest coverage ratio and adherence to covenants that limit, among other things, the Partnership’s, and certain of the Partnership’s subsidiaries’, ability to dispose of assets and make certain investments or payments. The RCF continues to contain certain covenants that limit, among other things, the ability of the Partnership, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of the Partnership’s business, enter into certain affiliate transactions and use proceeds other than for Partnership purposes. The RCF also contains various customary covenants, customary events of default and a maximum consolidated leverage ratio as of the end of each fiscal quarter (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. As of December 31, 2012, the Partnership had no outstanding borrowings and $6.7 million in outstanding letters of credit issued under its $800.0 million RCF. At December 31, 2012, the Partnership was in compliance with all remaining covenants under the RCF. Refer to Note 2 and Note 12 for a discussion of borrowing activity under the RCF in March 2013, related to acquisitions which closed after December 31, 2012.

The 2022 Notes, the 2021 Notes and obligations under the RCF are recourse to the Partnership’s general partner. In turn, the Partnership’s general partner has been indemnified by a wholly owned subsidiary of Anadarko against any claims made against the general partner under the 2022 Notes, the 2021 Notes and/or the RCF.

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 agreements. In May 2012, the Partnership entered into U.S. Treasury Rate lock agreements to mitigate the risk of rising interest rates prior to the issuance of the 2022 Notes. The Partnership settled the rate lock agreements simultaneously with the June 2012 offering of the 2022 Notes, realizing a loss of $1.7 million, which is included in other income (expense), net in the consolidated statements of income.

In March 2011, the Partnership entered into a forward-starting interest-rate swap agreement to mitigate the risk of rising interest rates prior to the issuance of the 2021 Notes. In May 2011, the Partnership issued the 2021 Notes and terminated the swap agreement, realizing a loss of $1.9 million, which is included in other income (expense), net in the consolidated statements of income.

In April 2010, the Partnership entered into financial agreements to fix the underlying 10-year Treasury rates with respect to a potential note issuance that was not realized. In May 2010, the Partnership terminated the agreements, realizing a loss of $2.4 million, which is included in other income (expense), net in the consolidated statements of income.

32

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	2012		2011		2010
Third parties
Interest expense on long-term debt	$	41,171	$	20,533	$	8,530
Amortization of debt issuance costs and commitment fees (1)		4,319		5,297		3,340
Capitalized interest (2)		(6,196)		(420)		—
Total interest expense – third parties		39,294		25,410		11,870
Affiliates
Interest expense on note payable to Anadarko (3)		2,440		4,935		6,828
Interest expense on affiliate balances (4)		326		—		—
Credit facility commitment fees		—		—		96
Total interest expense – affiliates		2,766		4,935		6,924
Interest expense	$	42,060	$	30,345	$	18,794

⁽¹⁾  For the year ended December 31, 2012, includes $1.1 million of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters’ fees. For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees for the 2021 Notes.

⁽²⁾  For the year ended December 31, 2012, $2.2 million of interest associated with capital projects at Chipeta was capitalized and $3.5 million of interest associated with the construction of the Brasada and Lancaster gas processing facilities was capitalized. See Note 5.

⁽³⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

⁽⁴⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. During 2012, the Partnership repaid the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note 5.

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, 2012 and 2011, asset retirement obligations and other on the consolidated balance sheets included $1.9 million and $1.6 million, respectively, for the long-term liability for remediation and reclamation obligations. The recorded obligations do not include any anticipated insurance recoveries. Substantially all of the payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes that the amounts reflected in the Partnership’s recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership’s overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered. See Note 8.

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.

33

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.  COMMITMENTS AND CONTINGENCIES (CONTINUED)

In July 2011, the Court denied the defendants’ motion to dismiss without ruling on the merits and the case is in the discovery phase. Trial is set for April 2014. 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 its capital spending programs, as well as those of its unconsolidated affiliates. As of December 31, 2012, the Partnership had unconditional payment obligations for services to be rendered, or products to be delivered in connection with its capital projects of approximately $55.9 million, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to the continued construction of the Brasada and Lancaster plants (see Note 5) and include 100% of obligations related to Chipeta, in which the Partnership has a 75% membership interest (see Note 1).

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 corporate offices and shared field offices extend through 2017 and 2018, respectively, and the lease for the warehouse extends through February 2014 and includes an early termination clause.

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 $3.0 million, $4.1 million and $7.7 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2012, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:

thousands	Operating Leases
2013	$	235
2014		169
2015		169
2016		169
2017		169
Thereafter		42
Total	$	953

12.  SUBSEQUENT EVENTS

Refer to Note 2 for a description of the Non-Operated Marcellus Interest acquisition on March 1, 2013. In addition, on March 8, 2013, the Partnership acquired a 33.75% (Anadarko-operated) interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems from a third party for total consideration of $134.9 million, of which $133.5 million was financed with borrowings on the Partnership’s RCF. The assets in both the aforementioned acquisitions serve production from the Marcellus shale in north-central Pennsylvania.

34

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, 2012 and 2011. The Partnership’s operating results reflect the operations of the Partnership assets (as defined in Note 1—Summary of Significant Accounting in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K) from the dates of common control, unless otherwise noted, and have been recast to include results attributable to the Non-Operated Marcellus Interest, as applicable. See Note 1—Summary of Significant Accounting Policies and 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
2012
Revenues	$	224,676	$	220,310	$	234,734	$	230,867
Operating income (loss) (1)	$	67,221	$	59,280	$	61,312	$	7,081
Net income (loss) (1)	$	57,894	$	47,599	$	50,002	$	(6,184)
Net income (loss) attributable to Western Gas Partners, LP (1)	$	53,651	$	43,309	$	46,579	$	(9,118)
Net income (loss) per common unit – basic and diluted (1) (2)	$	0.48	$	0.33	$	0.33	$	(0.27)
2011
Revenues	$	180,842	$	209,680	$	217,546	$	261,337
Operating income	$	50,599	$	57,716	$	53,385	$	83,594
Net income	$	46,083	$	47,004	$	48,109	$	65,665
Net income attributable to Western Gas Partners, LP	$	43,129	$	44,166	$	44,236	$	61,227
Net income per common unit – basic and diluted (2)	$	0.43	$	0.40	$	0.41	$	0.35
Net income per subordinated unit – basic and diluted (2)	$	0.41	$	0.38	$	—	$	—

⁽¹⁾  During the fourth quarter of 2012, the Partnership was allocated $54.9 million of general and administrative expenses from Anadarko associated with the Incentive Plan (as defined and described in Note 1—Summary of Significant Accounting Policies 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).

⁽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.

35

XML

Partnership Distributions - Incentive Distribution Rights Table (details) (USD $)	1 Months Ended	3 Months Ended
	May 31, 2008	Dec. 31, 2012		Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.300	$ 0.520	[1]	$ 0.500	$ 0.480	$ 0.460	$ 0.440	$ 0.420	$ 0.405	$ 0.390	$ 0.380	$ 0.370	$ 0.350	$ 0.340
General Partner Member
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	2.00%
General Partner Member | First Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	2.00%
General Partner Member | Second Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	15.00%
General Partner Member | Third Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	25.00%
General Partner Member | Thereafter [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	50.00%
Unitholders
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	98.00%
Unitholders | First Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	98.00%
Unitholders | Second Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	85.00%
Unitholders | Third Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	75.00%
Unitholders | Thereafter [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Marginal Percentage Interest In Distributions	50.00%
Minimum [Member] | First Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.300
Minimum [Member] | Second Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.345
Minimum [Member] | Third Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.375
Maximum [Member] | First Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.345
Maximum [Member] | Second Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.375
Maximum [Member] | Third Target [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.450
Maximum [Member] | Thereafter [Member]
Incentive Distribution Made To Managing Member Or General Partner Line Items
Total Quarterly Distribution Target Amount	$ 0.450

[1] On January 21, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

XML

Income Taxes - Additional Information (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Tax Credit Carryforward [Line Items]
Credit carryforwards	$ 541	$ 556
Other Tax Carryforward, Expiration Dates	2026-12-31
State And Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Credit carryforwards	$ 600

XML

Transactions With Affiliates - Equipment Purchase and Sale Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction Line Items
Partners' capital adjustment	$ 3,065	$ (314)	$ 1,840
Affiliated Entity Member | Sales [Member]
Related Party Transaction Line Items
Net carrying value	393	316	2,576
Cash received for equipment	760	382	2,805
Partners' capital adjustment	367	66	229
Affiliated Entity Member | Purchases [Member]
Related Party Transaction Line Items
Net carrying value	8,009	1,998	429
Cash paid for equipment	24,705	3,837	361
Partners' capital adjustment	$ 16,696	$ 1,839	$ (68)

XML

Property, Plant and Equipment Table (details) (USD $) In Thousands, unless otherwise specified									12 Months Ended				12 Months Ended						12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2012 Land Member	Dec. 31, 2011 Land Member	Dec. 31, 2012 Gathering systems	Dec. 31, 2011 Gathering systems	Dec. 31, 2012 Gathering systems Minimum [Member]	Dec. 31, 2012 Gathering systems Maximum [Member]	Dec. 31, 2012 Pipelines And Equipment [Member]	Dec. 31, 2011 Pipelines And Equipment [Member]	Dec. 31, 2012 Pipelines And Equipment [Member] Minimum [Member]	Dec. 31, 2012 Pipelines And Equipment [Member] Maximum [Member]	Dec. 31, 2012 Asset Under Construction Member	Dec. 31, 2011 Asset Under Construction Member	Dec. 31, 2012 Other	Dec. 31, 2011 Other	Dec. 31, 2012 Other Minimum [Member]	Dec. 31, 2012 Other Maximum [Member]
Property Plant And Equipment Line Items
Property, plant and equipment	$ 3,432,392	[1]	$ 2,708,271	[1]	$ 501	$ 364	$ 2,911,572	$ 2,479,184			$ 91,126	$ 90,883			$ 422,002	$ 132,913	$ 7,191	$ 4,927
Accumulated depreciation	714,436	[1]	587,119	[1]
Net property, plant and equipment	$ 2,717,956	[1]	$ 2,121,152	[1]
Estimated useful life									5 years	47 years			15 years	45 years					3 years	25 years

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

XML

Transactions With Affiliates - Gains Losses Commodity Price Swap Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ 14,215		$ (30,191)		$ (191)
Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	103,925	[1]	(2,957)	[1]	23,153	[1]
Cost Of Sales Member
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	(89,710)	[2]	(27,234)	[2]	(23,344)	[2]
Natural Gas Per Thousand Cubic Feet Member | Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	37,665	[1]	33,845	[1]	20,200	[1]
Natural Gas Liquids [Member] | Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ 66,260	[1]	$ (36,802)	[1]	$ 2,953	[1]

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

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

XML

Summary of Significant Accounting Policies - Equity Method Investments (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Schedule Of Equity Method Investments Line Items
Balance	$ 109,817	[1]
Contributions	862	[1]	93	[1]	310	[1]
Balance	106,130	[1]	109,817	[1]
Fort Union [Member]
Schedule Of Equity Method Investments Line Items
Balance	22,268		21,428
Investment earnings, net of amortization	6,383		6,067
Distributions	(5,198)		(5,227)
Balance	23,453		22,268
Table Text Block Supplement Abstract
Ownership interest	14.81%
Approval Percentage	65.00%
White Cliffs [Member]
Schedule Of Equity Method Investments Line Items
Balance	17,710		18,978
Investment earnings, net of amortization	7,871		4,023
Contributions	862		93
Distributions	(8,876)		(5,384)
Balance	17,567		17,710
Table Text Block Supplement Abstract
Ownership interest	10.00%
Approval Percentage	75.00%
Rendezvous [Member]
Schedule Of Equity Method Investments Line Items
Balance	69,839		74,056
Investment earnings, net of amortization	1,857		1,171
Distributions	(6,586)		(5,388)
Balance	$ 65,110		$ 69,839
Table Text Block Supplement Abstract
Ownership interest	22.00%
Approval Percentage	100.00%

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

XML

Accrued Liabilities Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Accrued Liabilities [Line Items]
Other accrued liabilities	$ 612		$ 1,935
Accrued interest expense	15,868		2,251
Short-term asset retirement obligations	1,711		875
Short-term remediation and reclamation obligations	799		1,679
Accrued liabilities	147,651	[1],[2]	92,037	[1],[2]
Accrued Capital Expenditures [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	112,311		60,391
Accrued Plant Purchases [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	16,350		19,607
Construction Ownership Operation Agreement [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities			$ 5,299

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

[2] Accrued liabilities include amounts payable to affiliates of $0.1 million and $0.3 million as of December 31, 2012 and 2011, respectively.

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Equity and Partners' Capital (tables)

12 Months Ended

Dec. 31, 2012

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
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
June 2012 equity offering		5,000,000	102,041		43.88		7,468		216,409

____________________________________________________________

(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 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 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 contributionto maintain its 2.0% general partner interest.

Limited Partner and General Partner Units Table

		Common	Subordinated	General
		Units	Units	Partner Units	Total
Balance at December 31, 2010		51,036,968	26,536,306	1,583,128	79,156,402
	March 2011 equity offering	3,852,813	—	78,629	3,931,442
	Long-Term Incentive Plan awards	14,628	—	299	14,927
	Bison acquisition	2,950,284	—	60,210	3,010,494
	Conversion of subordinated units	26,536,306	(26,536,306)	—	—
	September 2011 equity offering	5,750,000	—	117,347	5,867,347
Balance at December 31, 2011		90,140,999	—	1,839,613	91,980,612
	MGR acquisition	632,783	—	12,914	645,697
	Long-Term Incentive Plan awards	12,570	—	257	12,827
	June 2012 equity offering	5,000,000	—	102,041	5,102,041
	Chipeta acquisition	151,235	—	3,086	154,321
	WGP unit purchase agreement	8,722,966	—	178,019	8,900,985
Balance at December 31, 2012		104,660,553	—	2,135,930	106,796,483

Calculation of Net Income Per Unit Table

	Year Ended December 31,
thousands except per-unit amounts	2012		2011		2010
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928
Pre-acquisition net (income) loss allocated to Anadarko		(27,435)		(52,599)		(31,797)
General partner interest in net (income) loss		(28,089)		(8,599)		(3,067)
Limited partners’ interest in net income	$	78,897	$	131,560	$	111,064
Net income allocable to common units	$	78,897	$	110,542	$	68,410
Net income allocable to subordinated units		—		21,018		42,654
Limited partners’ interest in net income	$	78,897	$	131,560	$	111,064
Net income per unit – basic and diluted
Common units	$	0.84	$	1.64	$	1.66
Subordinated units	$	—	$	1.28	$	1.61
Weighted average units outstanding – basic and diluted
Common units		93,936		67,333		41,287
Subordinated units		—		16,431		26,536

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Transactions With Affiliates - Additional Information (details) (USD $)	1 Months Ended	12 Months Ended					1 Months Ended			1 Months Ended		12 Months Ended																					1 Months Ended	12 Months Ended									12 Months Ended
	May 31, 2008	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010	May 31, 2008 Note Receivable From Anadarko [Member]	Dec. 31, 2012 Note Receivable From Anadarko [Member]	Dec. 31, 2011 Note Receivable From Anadarko [Member]	Dec. 31, 2008 Note Payable To Anadarko [Member]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Dec. 31, 2012 Gathering Transportation And Treating [Member]	Dec. 31, 2011 Gathering Transportation And Treating [Member]	Dec. 31, 2010 Gathering Transportation And Treating [Member]	Dec. 31, 2012 Processing [Member]	Dec. 31, 2011 Processing [Member]	Dec. 31, 2010 Processing [Member]	Dec. 31, 2012 Omnibus Agreement [Member]	Dec. 31, 2011 Omnibus Agreement [Member]	Dec. 31, 2012 Omnibus Agreement [Member] Public Company Expenses [Member]	Dec. 31, 2011 Omnibus Agreement [Member] Public Company Expenses [Member]	Dec. 31, 2010 Omnibus Agreement [Member] Public Company Expenses [Member]	Dec. 31, 2010 Omnibus Agreement [Member] Maximum [Member]	Dec. 31, 2012 Omnibus Agreement [Member] No Cap	Dec. 31, 2011 Omnibus Agreement [Member] No Cap	Dec. 31, 2012 Incentive Plan [Member]	Dec. 31, 2011 Incentive Plan [Member]	Dec. 31, 2010 Incentive Plan [Member]	Dec. 31, 2012 Incentive Plan [Member] Unit Appreciation Right [Member]	Dec. 31, 2011 Incentive Plan [Member] Unit Appreciation Right [Member]	Dec. 31, 2010 Incentive Plan [Member] Unit Appreciation Right [Member]	Dec. 31, 2012 Incentive Plan [Member] Distribution Equivalent Right [Member]	Dec. 31, 2011 Gas Gathering And Processing Equipment Member Mountain Gas Resources [Member]	Dec. 31, 2012 Long Term Incentive Plan [Member]	Dec. 31, 2011 Long Term Incentive Plan [Member]	Dec. 31, 2010 Long Term Incentive Plan [Member]	Dec. 31, 2012 Anadarko Incentive Plans [Member]	Dec. 31, 2011 Anadarko Incentive Plans [Member]	Dec. 31, 2010 Anadarko Incentive Plans [Member]	Dec. 31, 2012 Anadarko Incentive Plans [Member] Performance Based Awards [Member]	Mar. 31, 2012 Anadarko [Member] Brasada And Lancaster Agreement [Member]	Dec. 31, 2012 Anadarko [Member] Long Term Incentive Plan [Member]	Dec. 31, 2012 Independent Director Long Term Incentive Plan [Member]
Related Party Transaction Line Items
Note receivable - Anadarko		$ 260,000,000	[1]	$ 260,000,000	[1]		$ 260,000,000
Term of instrument or obligation		1 year					30 years			5 years																							10 years
Fixed annual rate for note receivable bearing interest							6.50%
The fair value of the note receivable								334,800,000	303,700,000
Principal		1,170,000,000		675,000,000						175,000,000
Fixed interest rate											4.00%
Cost reimbursement payable		147,651,000	[1],[2]	92,037,000	[1],[2]																																				18,900,000
Rate Of Return	18.00%
Affiliate throughput percent												64.00%	67.00%	73.00%	59.00%	64.00%	66.00%
Allocated costs from Anadarko																		21,700,000	19,500,000	6,800,000	7,700,000	8,000,000	9,000,000	14,900,000	11,800,000
Equity based compensation expense																										68,800,000	11,400,000	3,100,000						400,000	300,000	300,000	3,300,000	2,500,000	2,300,000
Unvested equity based compensation																																		700,000			4,400,000			100,000		800,000
Weighted average term of unvested awards																																		2 years 2 months 12 days			1 year 10 months 24 days			2 years
Phantom units vesting term																																		3 years									1 year
UVR, UAR and DER Valuation																													$ 2,475.00	$ 634.00	$ 215.00	$ 12.00
Partners' capital adjustment		$ 3,065,000		$ (314,000)		$ 1,840,000																																$ 9,700,000

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

[2] Accrued liabilities include amounts payable to affiliates of $0.1 million and $0.3 million as of December 31, 2012 and 2011, respectively.

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Equity and Partners' Capital - Limited Partner and General Partner Units (details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Capital Unit [Line Items]
Balance	91,980,612	79,156,402
Long-Term Incentive Plan Awards	12,827	14,927
Balance	106,796,483	91,980,612
March 2011 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering		3,931,442
Bison [Member]
Capital Unit [Line Items]
Acquisition		3,010,494
September 2011 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering		5,867,347
Mountain Gas Resources [Member]
Capital Unit [Line Items]
Acquisition	645,697
June 2012 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering	5,102,041
Chipeta Processing LLC
Capital Unit [Line Items]
Acquisition	154,321
WGP
Capital Unit [Line Items]
WGP unit purchase agreement	8,900,985
Common [Member]
Capital Unit [Line Items]
Balance	90,140,999	51,036,968
Long-Term Incentive Plan Awards	12,570	14,628
Conversion of subordinated units		26,536,306
Balance	104,660,553	90,140,999
Common [Member] | March 2011 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering		3,852,813
Common [Member] | Bison [Member]
Capital Unit [Line Items]
Acquisition		2,950,284
Common [Member] | September 2011 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering		5,750,000
Common [Member] | Mountain Gas Resources [Member]
Capital Unit [Line Items]
Acquisition	632,783
Common [Member] | June 2012 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering	5,000,000
Common [Member] | Chipeta Processing LLC
Capital Unit [Line Items]
Acquisition	151,235
Common [Member] | WGP
Capital Unit [Line Items]
WGP unit purchase agreement	8,722,966
General Partner Member
Capital Unit [Line Items]
Balance	1,839,613	1,583,128
Long-Term Incentive Plan Awards	257	299
Balance	2,135,930	1,839,613
General Partner Member | March 2011 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering		78,629
General Partner Member | Bison [Member]
Capital Unit [Line Items]
Acquisition		60,210
General Partner Member | September 2011 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering		117,347
General Partner Member | Mountain Gas Resources [Member]
Capital Unit [Line Items]
Acquisition	12,914
General Partner Member | June 2012 Equity Offering [Member]
Capital Unit [Line Items]
Equity offering	102,041
General Partner Member | Chipeta Processing LLC
Capital Unit [Line Items]
Acquisition	3,086
General Partner Member | WGP
Capital Unit [Line Items]
WGP unit purchase agreement	178,019
Subordinated [Member]
Capital Unit [Line Items]
Balance		26,536,306
Conversion of subordinated units		(26,536,306)

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Acquisitions - Additional Information (details) (USD $)	12 Months Ended						0 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Mar. 01, 2013 Non-Operated Marcellus Interest [Member]	Mar. 01, 2013 Non-Operated Marcellus Interest [Member]
Business Acquisition Line Items
Percentage acquired							33.75%
Total consideration for acquisition								$ 465,500,000
Common units issued								449,129
Borrowings	1,041,648,000	[1]	1,055,939,000	[1]	660,000,000	[1]	250,000,000
Cash on hand							$ 215,500,000

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Income Taxes - Tax Rate Reconciliation Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Related Party Transaction Line Items
Income before income taxes	$ 170,026	[1]	$ 239,011	[1]	$ 178,450	[1]
Statutory tax rate	0.00%		0.00%		0.00%
Adjustments resulting from:
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) Texas margin tax expense (benefit)	1,258		664		300
Total income tax expense	20,715	[1]	32,150	[1]	21,517	[1]
Effective tax rate	12.00%		13.00%		12.00%
Pre Acquisition From Parent [Member]
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition	17,251		29,502		20,534
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) Texas margin tax expense (benefit)	$ 2,206		$ 1,984		$ 683

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Debt and Interest Expense - Interest Expense Table (details) (USD $)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Debt Instrument Line Items
Interest Expense	$ 42,060,000	[1],[2]	$ 30,345,000	[1],[2]	$ 18,794,000	[1],[2]
Chipeta Processing Limited Liability Company [Member]
Debt Instrument Line Items
Capitalized interest	(2,200,000)
Brasada And Lancaster Agreement [Member]
Debt Instrument Line Items
Capitalized interest	(3,500,000)
5.375% Senior Notes due 2021
Table Text Block Supplement Abstract
Amortization related to Senior Notes			500,000
5.375% Senior Notes due 2021 | 4.00% Senior Notes due 2022
Table Text Block Supplement Abstract
Amortization related to Senior Notes	1,100,000
Third Parties [Member]
Debt Instrument Line Items
Interest expense on long-term debt	41,171,000		20,533,000		8,530,000
Amortization of debt issuance costs and commitment fees Credit facility commitment fees	4,319,000	[3]	5,297,000	[3]	3,340,000	[3]
Capitalized interest	(6,196,000)	[4]	(420,000)	[4]
Interest Expense	39,294,000		25,410,000		11,870,000
Affiliated Entity Member
Debt Instrument Line Items
Interest expense on note payable to Anadarko	2,440,000	[5]	4,935,000	[5]	6,828,000	[5]
Interest expense, net on affiliate balances	326,000	[6]
Amortization of debt issuance costs and commitment fees Credit facility commitment fees					96,000
Interest Expense	$ 2,766,000	[7]	$ 4,935,000	[7]	$ 6,924,000	[7]

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

[2] Includes affiliate (as defined in Note 1) interest expense of $2.8 million, $4.9 million and $6.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 10.

[3] For the year ended December 31, 2012, includes $1.1 million of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters’ fees. For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees for the 2021 Notes.

[4] For the year ended December 31, 2012, $2.2 million of interest associated with capital projects at Chipeta was capitalized and $3.5 million of interest associated with the construction of the Brasada and Lancaster gas processing facilities was capitalized. See Note 5.

[5] In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

[6] Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. During 2012, the Partnership repaid the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note 5.

[7] Represents interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. During 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note receivable from and amounts payable to Anadarko within this Note 5.

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Transactions With Affiliates - LTIP Award Activity Table (details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested RollForward
Phantom units outstanding at beginning of year	23,978	17,503	21,970
Vested	(14,260)	(15,119)	(19,751)
Granted	15,901	21,594	15,284
Phantom units outstanding at end of year	25,619	23,978	17,503
Value Per Unit of Phantom Units Outstanding	$ 41.77	$ 33.92	$ 20.19	$ 15.02
Value Per Unit of Phantom Units Vested during the Period	$ 33.20	$ 20.51	$ 15.02
Value Per Unit of Phantom Units Granted during the Period	$ 45.91	$ 35.66	$ 20.94

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Summary of Significant Accounting Policies

General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to own, operate, acquire and develop midstream energy assets. The Partnership closed its initial public offering (“IPO”) to become publicly traded in 2008.

For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership's general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership's general partner, as well as a significant limited partner interest in the Partnership (see Western Gas Equity Partners, LP below, Note 4 and Note 5). Western Gas Equity Holdings, LLC is WGP's general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko Petroleum Corporation” refers to Anadarko Petroleum Corporation excluding its subsidiaries and affiliates. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”). “Equity investment throughput” refers to the Partnership's 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as third-party producers and customers. As of December 31, 2012, the Partnership owned and operated twelvenatural gas gathering systems, seven natural gas treating facilities, seven natural gas processing facilities, two NGL pipelines, one interstate natural gas pipeline, and one intrastate natural gas pipeline. In addition, including the effect of the acquisition of the Non-Operated Marcellus Interest (see Note 2),the Partnership had interests in two non-operatednatural gas gathering systems, one operated natural gas gathering system, and two operated natural gas processing facilities, with separate interests in Fort Union, White Cliffs and Rendezvous accounted for under the equity method. These assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming), north-central Pennsylvania, and the Mid-Continent (Kansas and Oklahoma). The Partnershiphad facilities under construction in South Texas and Northeast Colorado at the end of 2012.

Western Gas Equity Partners, LP. WGP was formed to own three types of interests in the Partnership: (i) the 2.0% general partner interest through WGP's 100% ownership of the Partnership's general partner; (ii) all of the incentive distribution rights (“IDRs”) in the Partnership; and (iii) all of the limited partner interests in the Partnershipheld by Anadarko at the time of WGP's IPO. WGP has no independent operations or material assets other than its partnership interests in WES.

In December 2012, WGP completed its IPO of 19,758,150 common units representing limited partner interests in WGP, including 2,577,150 common units issued in connection with the full exercise of the underwriters' over-allotment option, at a price of $22.00 per common unit. WGP used the net proceeds from the offering to purchase common and general partner units of the Partnership (see Note 4) resulting in aggregate proceeds to the Partnership of approximately $409.4 million, which will be used for general partnership purposes, including the funding of capital expenditures.

Basis of presentation. The consolidated financial statements 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. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 33.75% share of the assets, liabilities, revenues and expenses attributable to the Non-Operated Marcellus Interest and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system in the accompanying consolidated financial statements. All significant intercompany transactions have been eliminated. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the 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 (the “Chipeta LLC agreement”). On August 1, 2012, the Partnership acquired Anadarko's then remaining 24% membership interest in Chipeta (the “additional Chipeta interest”). Prior to this transaction, the interests in Chipeta held by Anadarko and a third-party member were reflected as noncontrolling interests in the consolidated financial statements. The acquisition of Anadarko's then remaining 24% interest was accounted for on a prospective basis as the Partnership acquired an additional interest in an already-consolidated entity. As such, effective August 1, 2012, the Partnership's noncontrolling interest excludes the financial results and operations of the additional Chipetainterest. Theremaining 25% membership interest held by the third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented. See Note 2.

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of December 31, 2012. Because Anadarko controls the Partnership through its control of WGP, which owns the Partnership's general partner, each of the Partnership's acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko's historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such assets as of the date of common control. See Note 2.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership's acquisition of Partnership assets from Anadarko, including the Non-Operated Marcellus Interest,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 reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other methods considered reasonable under the particular 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 business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

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 reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.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 debts on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. As of December 31, 2012, there was no reserve for bad debts. The third-party accounts receivable balance at December 31, 2011, was 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' pipelines. 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, 2012, natural gas imbalance receivables and payables were approximately $1.7 million and $3.1 million, respectively. As of December 31, 2011, natural gas imbalance receivables and payables were approximately $2.3 million and $3.1 million, respectively. Changes in natural gas imbalances are reported in equity income and other, net for imbalance receivablesor in cost of productfor imbalance payables.

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 assets acquired 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. All construction-related direct labor and material costs are capitalized. 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 using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. 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.

Management 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. Refer toNote 7 for a description of impairments recorded during the years ended December 31, 2012, 2011 and 2010.

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. 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 a third-party entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership's goodwill balance does not represent, and in some cases is significantly different from, 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. During 2011, the carrying amount of goodwill increased from $82.1 million to $99.5 million, due to the acquisition of the Non-Operated Marcellus Interest. The carrying amount of goodwill is not deductible for tax purposes. During 2012, the carrying amount of goodwill increased from $99.5 million to $105.3 million, attributable to allocated goodwill related to the acquisition of the additional 24% interest in Chipeta (see Note 2), 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 Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. For years 2011 and prior, the first step in the goodwill impairment test was to compare the fair value of each reporting unit to which goodwill had been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. For years 2012 and forward, an initial qualitative assessment may be performed prior to proceeding to the first step performed in previous years (described above). If the Partnership concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value through a charge to operating expense based on a hypothetical purchase price allocation. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement. Estimating the fair value of the Partnership's reporting units was not necessary based on the evaluation as of October 1, 2012, and no goodwill impairment has been recognized in these consolidated financial statements.

Other intangible assets.The intangible asset balance in the consolidated balance sheets includes 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. Customer contract intangible assets 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.

In November 2012, Chipeta entered into interconnect agreements with a third party, whereby the third party will construct, own and operate an inlet interconnect to the Chipeta plant and a redelivery interconnect from the Chipeta plant. Chipeta will pay the third party $3.7 million and will be granted access rights to the third-party infrastructure, thereby providing the Partnership with the ability to enter into processing agreements with additional third-party producers. The Partnership's intangible asset balance as of December 31, 2012, includes this payment, which will be amortized on a straight-line basis over the 10-year life of the agreements.

The Partnership assesses intangible assetsfor 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. See Property, plant and equipment within this Note 1 for further discussion of management's process to evaluate potential impairment of long-lived assets. No intangible asset impairment has been recognized in these consolidated financial statements. As of December 31, 2012, the carrying value of the Partnership's intangible assets was $55.5 million, net of $2.0million of accumulated amortization. The Partnership estimates that it will record $1.4 million of intangible asset amortization for each of the next five years. As of December 31, 2011, the carrying value of the Partnership's intangible assets was $52.9 million, net of $0.9 million of accumulated amortization.

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, 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
	Investment earnings, net of amortization		6,383		7,871		1,857
	Contributions		—		862		—
	Distributions		(5,198)		(8,876)		(6,586)
Balance at December 31, 2012		$	23,453	$	17,567	$	65,110

____________________________________________________________

(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.

(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. 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, 2012, includes $2.6 million and $45.9 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. (the entity that previously 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 such 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 investment balance inWhite Cliffs at December 31, 2012, is $9.8 million less than the Partnership's underlying equity in White Cliffs' net assets as of December 31, 2012, 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 adjustedto its expected settlement value through accretion expense, which is reported within depreciation, amortization and impairments in the consolidated statements of income. 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 obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations 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 gather, process, compress, treat and transport Anadarko and third-party natural gas, condensate, NGLs and crude oil in the United States.

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 cost-of-service gathering agreements, the Partnership earns fees for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate are sold.The percentage of the product sale paid to the produceris recorded as a related cost of product expense.

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 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. 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 than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price uncertainty that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. See Note 5. 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.

Proceeds from the sale of residue, 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 2,144,947 units remain available for future issuance as of December 31, 2012. 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) the 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 and 2012 Omnibus Incentive Compensation Plans (Anadarko's plans are referred to collectively as the “Anadarko Incentive Plans”). Equity-based compensation granted under the Anadarko Incentive Plans does not impact the Partnership's cash flows from operating activities and is recorded as an adjustment to partners' capital in the consolidated financial statements at the time of contribution. 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. 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. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership's acquisition of these assets from Anadarko.

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 satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2012 or 2011.

With respect to assets acquired from Anadarko, the Partnership recorded Anadarko's historic current and deferred income taxes for the periods prior to the Partnership's ownership of the assets. For periods subsequent to the Partnership's acquisition, the Partnership is not subject to tax except for the Texas margin tax and accordingly, does not record current and deferred federal income taxes related to the assets acquired from Anadarko.

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 partner units and 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 the years ended December 31, 2012 and 2011, other assets on the consolidated balance sheets include $0.4 million and $0.7 million, respectively, for a receivable recognized in conjunction with the capital lease component of a processing agreement assumed in connection with the acquisition of Mountain Gas Resources, LLC (“MGR”). See Note 2. The agreement, in which WES 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 consolidated statements of income.

Accounts Payable.Included in accounts payable at December 31, 2012 and 2011, are liabilities of $11.6 million and $9.8 million, respectively, representing the amount by which checks issued, but not presented to the Partnership's banks for collection, exceed balances in applicable bank accounts.

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Debt and Interest Expense - Additional Information (details) (USD $)	12 Months Ended		1 Months Ended	12 Months Ended		1 Months Ended			1 Months Ended			1 Months Ended	12 Months Ended				1 Months Ended		1 Months Ended			1 Months Ended				1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Dec. 31, 2012 Senior Notes 4 Percent Due 2022 [Member]	Oct. 31, 2012 Senior Notes 4 Percent Due 2022 [Member]	May 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member]	Dec. 31, 2012 Senior Notes 5 Point 375 Percent Due 2021 [Member]	Dec. 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member]	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, 2012 Revolving Credit Facility [Member]	Dec. 31, 2011 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 Wattenberg Term Loan [Member]	Aug. 31, 2010 Wattenberg Term Loan [Member]	Aug. 31, 2010 Wattenberg Term Loan [Member] Maximum [Member]	Aug. 31, 2010 Wattenberg Term Loan [Member] Minimum [Member]	May 31, 2011 Interest Rate Swap [Member]	May 31, 2010 Interest Rate Swap [Member]
Debt Instrument Line Items
Fixed interest rate				4.00%		5.375%			4.00%		2.82%
Principal	$ 1,170,000,000	$ 675,000,000	$ 520,000,000	$ 670,000,000	$ 150,000,000	$ 500,000,000	$ 500,000,000	$ 500,000,000	$ 175,000,000	$ 175,000,000													$ 250,000,000
Offering Percent			99.194%		105.178%	98.778%
Effective interest rate				4.04%		5.648%
Term of instrument or obligation	1 year			10 years		10 years			5 years			5 years											3 years
Underwriting discount				4,400,000		3,300,000
Revolving Credit Facility, current maximum borrowing capacity												800,000,000			450,000,000
Revolving Credit Facility, additional borrowings													0
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													1.71%	1.80%
Facility fee													0.25%	0.25%			0.35%		0.20%
Accelerated amortization expense																						1,300,000
Realized loss on terminated swap agreement			1,700,000																							1,900,000	2,400,000
Outstanding letters of credit													$ 6,700,000
Covenants	The indentures governing the 2022 Notes and the 2021 Notes contain customary events of default including, among others, (i) default for 30 days in the payment of interest when due; (ii) default in payment, when due, of principal of or premium, if any, at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency. The indentures also contain covenants that limit, among other things, the ability of the Partnership, as well as that of certain of the Partnership’s subsidiaries, to (i) create liens on 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 the Partnership’s properties or assets to another entity.
Revolving Credit Facility covenants												The RCF continues to contain certain covenants that limit, among other things, the ability of the Partnership, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of the Partnership’s business, enter into certain affiliate transactions and use proceeds other than for Partnership purposes. The RCF also contains various customary covenants, customary events of default and a maximum consolidated leverage ratio as of the end of each fiscal quarter (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.
Senior Notes redemption provisions				The 2022 Notes mature on July 1, 2022, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the 2022 Notes in whole or in part, at any time before April 1, 2022, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2022 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 2022 Notes) plus 37.5 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 April 1, 2022, the 2022 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2022 Notes to be redeemed, plus accrued interest on the 2022 Notes to be redeemed to the date of redemption.		The 2021 Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the 2021 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 2021 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2021 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 2021 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 2021 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2021 Notes to be redeemed, plus accrued interest on the 2021 Notes to be redeemed to the date of redemption.

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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, 2012		Dec. 31, 2011		Dec. 31, 2010
Earnings Per Unit [Line Items]
Net income attributable to Western Gas Partners, LP	$ 134,421	[1]	$ 192,758	[1]	$ 145,928	[1]
Pre-acquisition net (income) loss allocated to Anadarko	(27,435)	[1]	(52,599)	[1]	(31,797)	[1]
General partner interest in net (income) loss	(28,089)	[1],[2]	(8,599)	[1],[2]	(3,067)	[1],[2]
Limited partners' interest in net income	78,897	[1],[2]	131,560	[1],[2]	111,064	[1],[2]
Common [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	78,897		110,542		68,410
Common [Member] | Limited Partners Member
Net income per unit - basic and diluted
Net income per unit - basic and diluted	$ 0.84	[1]	$ 1.64	[1]	$ 1.66	[1]
Weighted average units outstanding - basic and diluted
Weighted average units outstanding - basic and diluted	93,936		67,333		41,287
Subordinated [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income			$ 21,018		$ 42,654
Subordinated [Member] | 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]
Weighted average units outstanding - basic and diluted
Weighted average units outstanding - basic and diluted			16,431		26,536

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. 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 Note 4.

[3] 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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Accrued Liabilities (table)

12 Months Ended

Dec. 31, 2012

Accrued Liabilities Current Abstract

Accrued Liabilities Table

	December 31,
thousands	2012		2011
Accrued capital expenditures	$	112,311	$	60,391
Accrued plant purchases		16,350		19,607
Accrued interest expense		15,868		2,251
Accrued charges under COO Agreement (see Note 2)		—		5,299
Short-term asset retirement obligations		1,711		875
Short-term remediation and reclamation obligations		799		1,679
Other		612		1,935
Total accrued liabilities	$	147,651	$	92,037

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Property, Plant and Equipment (table)

12 Months Ended

Dec. 31, 2012

Property Plant And Equipment Abstract

Property, Plant and Equipment Table

		Estimated	December 31,
thousands		Useful Life	2012		2011
Land		n/a	$	501	$	364
Gathering systems		5 to 47 years		2,911,572		2,479,184
Pipelines and equipment		15 to 45 years		91,126		90,883
Assets under construction		n/a		422,002		132,913
Other		3 to 25 years		7,191		4,927
	Total property, plant and equipment			3,432,392		2,708,271
Accumulated depreciation				714,436		587,119
	Net property, plant and equipment		$	2,717,956	$	2,121,152

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Property, Plant and Equipment - Additional Information (details) (USD $)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Property Plant And Equipment Line Items
Other assets	$ 27,798,000	[1]	$ 24,143,000	[1]
Asset Under Construction Member
Property Plant And Equipment Line Items
Impairment					300,000
Equipment Member
Property Plant And Equipment Line Items
Impairment	600,000		7,300,000		600,000
Property Plant And Equipment Other Types Member
Property Plant And Equipment Line Items
Other assets			10,600,000
Pipelines And Equipment [Member]
Property Plant And Equipment Line Items
Impairment			3,000,000
Gathering System [Member]
Property Plant And Equipment Line Items
Impairment	$ 6,000,000

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Equity and Partners' Capital - Additional Information (details) (USD $)	1 Months Ended								1 Months Ended	12 Months Ended			12 Months Ended
	Jun. 30, 2012	Sep. 30, 2011	Mar. 31, 2011	Nov. 30, 2010	May 31, 2010		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 WGP And Affiliates [Member]	Dec. 31, 2012 WGP And Affiliates [Member]	Dec. 31, 2011 Common [Member]	Dec. 31, 2012 Common [Member]	Dec. 31, 2012 Common [Member] Public [Member]	Dec. 31, 2012 Common [Member] WGP And Affiliates [Member]	Dec. 31, 2011 Subordinated [Member]	Dec. 31, 2012 Incentive Distribution Rights [Member] WGP And Affiliates [Member]
Schedule Of Investments Line Items
Units owned											90,140,999	104,660,553	55,364,348	49,296,205
Ownership interest													51.80%	46.20%
General partner units owned							2,135,930	1,839,613	2,135,930	2,135,930
General partner's interest										2.00%						100.00%
Conversion of subordinated units											26,536,306				(26,536,306)
Price per unit	$ 43.88	$ 35.86	$ 35.15	$ 29.92	$ 22.25	[1]			$ 46.00

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

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Asset Retirement Obligations (table)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

ScheduleOfChangeInAssetRetirementObligationTableTextBlock

		Year Ended December 31,
thousands		2012		2011
Carrying amount of asset retirement obligations at beginning of year		$	64,345	$	45,269
	Liabilities incurred		9,414		15,462
	Liabilities settled		(786)		(133)
	Accretion expense		4,270		3,791
	Revisions in estimated liabilities		(10,520)		(44)
Carrying amount of asset retirement obligations at end of year		$	66,723	$	64,345

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Debt and Interest Expense (tables)

12 Months Ended

Dec. 31, 2012

Debt Instruments Abstract

Debt Outstanding Table

	December 31, 2012						December 31, 2011
			Carrying		Fair				Carrying		Fair
thousands	Principal		Value		Value (1)		Principal		Value		Value (1)
4.000% Senior Notes due 2022	$	670,000	$	673,617	$	669,928	$	—	$	—	$	—
5.375% Senior Notes due 2021		500,000		494,661		499,946		500,000		494,178		499,950
Note payable to Anadarko		—		—		—		175,000		175,000		174,528
Total debt outstanding	$	1,170,000	$	1,168,278	$	1,169,874	$	675,000	$	669,178	$	674,478

_______________________________________________________

(1)Fair value is measured using Level 2 inputs.

Debt Activity Table

thousands		Carrying Value
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
	Revolving credit facility borrowings		374,000
	Issuance of 4.000% Senior Notes due 2022		670,000
	Repayment of revolving credit facility		(374,000)
	Repayment of note payable to Anadarko		(175,000)
	Revolving credit facility borrowings – Swingline		20,000
	Repayment of revolving credit facility – Swingline		(20,000)
	Other and changes in debt discount or premium		4,100
Balance as of December 31, 2012		$	1,168,278

Interest Expense Table

			Year Ended December 31,
thousands			2012		2011		2010
Third parties
	Interest expense on long-term debt		$	41,171	$	20,533	$	8,530
	Amortization of debt issuance costs and commitment fees (1)			4,319		5,297		3,340
	Capitalized interest (2)			(6,196)		(420)		—
		Total interest expense – third parties		39,294		25,410		11,870
Affiliates
	Interest expense on note payable to Anadarko (3)			2,440		4,935		6,828
	Interest expense on affiliate balances (4)			326		—		—
	Credit facility commitment fees			—		—		96
		Total interest expense – affiliates		2,766		4,935		6,924
Interest expense			$	42,060	$	30,345	$	18,794

___________________________________________________________________

(1)For the year ended December 31, 2012, includes $1.1 million of amortization of (i) the original issue discount for the June 2012 offeringpartially offset by the original issuepremium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters' fees. For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters' fees for the 2021 Notes.

(2)For the year ended December 31, 2012, $2.2 million of interest associated with capital projects at Chipeta was capitalized and $3.5 million of interest associated with the construction of the Brasada and Lancaster gas processing facilities was capitalized. SeeNote 5.

(3)In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

(4)Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of theBrasada and Lancaster plants.During 2012, the Partnership repaid the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note 5.

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Cash flows from operating activities
Net income	$ 149,311	[1]	$ 206,861	[1]	$ 156,933	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	120,608	[1]	113,133	[1]	91,129	[1]
Non-cash equity-based compensation expense	3,717	[1]	3,490	[1]	2,567	[1]
Deferred income taxes	30,113	[1]	16,580	[1]	9,539	[1]
Debt-related amortization and other items, net	2,319	[1]	3,110	[1]	1,705	[1]
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	22,916	[1]	(44,725)	[1]	(15,039)	[1]
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	5,045	[1]	30,884	[1]	5,407	[1]
Change in other items, net	3,997	[1]	(16,495)	[1]	657	[1]
Net cash provided by operating activities	338,026	[1]	312,838	[1]	252,898	[1]
Cash flows from investing activities
Capital expenditures	(638,121)	[1]	(149,717)	[1]	(173,891)	[1]
Investments in equity affiliates	(862)	[1]	(93)	[1]	(310)	[1]
Net cash used in investing activities	(1,249,942)	[1]	(479,722)	[1]	(921,398)	[1]
Cash flows from financing activities
Borrowings, net of debt issuance costs	1,041,648	[1]	1,055,939	[1]	660,000	[1]
Repayments of debt	(549,000)	[1]	(869,000)	[1]	(361,000)	[1]
Increase (decrease) in outstanding checks	1,800	[1]	4,039	[1]	(4,805)	[1]
Revolving credit facility issuance costs					(12)	[1]
Proceeds from issuance of common and general partner units, net of offering expenses	625,877	[1]	335,317	[1]	345,803	[1]
Distributions to unitholders	(197,850)	[1]	(140,118)	[1]	(94,194)	[1]
Contributions from noncontrolling interest owners	29,108	[1]	33,637	[1]	2,053	[1]
Distributions to noncontrolling interest owners	(17,303)	[1]	(17,478)	[1]	(13,222)	[1]
Net contributions from Anadarko	171,058	[1]			90,967	[1]
Net distributions to Anadarko			(35,967)	[1]
Net cash provided by financing activities	1,105,338	[1]	366,369	[1]	625,590	[1]
Net increase (decrease) in cash and cash equivalents	193,422	[1]	199,485	[1]	(42,910)	[1]
Cash and cash equivalents at beginning of period	226,559	[1]	27,074	[1]	69,984	[1]
Cash and cash equivalents at end of period	419,981	[1]	226,559	[1]	27,074	[1]
Supplemental disclosures
Net distributions to Anadarko of other assets	15,296	[1]			7,827	[1]
Net contributions from Anadarko of other assets			(29)
Interest paid, net of capitalized interest	28,042	[1]	25,828	[1]	16,497	[1]
Taxes paid	495	[1]	190	[1]	507	[1]
Affiliated Entity Member
Cash flows from investing activities
Acquisitions	(611,719)	[1]	(28,837)	[1]	(734,780)	[1]
Proceeds	760	[1]	382	[1]	2,805	[1]
Third Parties [Member]
Cash flows from investing activities
Acquisitions			(301,957)	[1]	(18,047)	[1]
Proceeds			$ 500	[1]	$ 2,825	[1]

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Commitments and Contingencies (table)

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies [Abstract]

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

thousands	Operating Leases
2013	$	235
2014		169
2015		169
2016		169
2017		169
Thereafter		42
Total	$	953

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Partnership Distributions - Additional Information (details)	12 Months Ended
	Dec. 31, 2012
Distributions Made to Members or Limited Partners [Abstract]
Partnership agreement day requirement of distribution of available cash	45 days

XML

Income Taxes - Deferred Tax Assets and Liabilities Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Income Tax Expense Benefit Abstract
Credit carryforwards	$ 14		$ 14
Net current deferred income tax assets	14		14
Depreciable property	(47,558)		(99,733)
Partnership basis			(24,481)
Credit carryforwards	541		556
Other	(136)
Other			114
Net long-term deferred income tax liabilities	(47,153)	[1]	(123,544)	[1]
Total net deferred income tax liabilities	$ (47,139)		$ (123,530)

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Revenues
Total revenues	$ 910,587	[1]	$ 869,405	[1]	$ 663,274	[1]
Operating expenses
Cost of product	336,079	[1],[2]	327,371	[1],[2]	246,476	[1],[2]
Operation and maintenance	140,106	[1],[2]	126,464	[1],[2]	103,887	[1],[2]
General and administrative	99,212	[1],[2]	40,564	[1],[2]	29,970	[1],[2]
Property and other taxes	19,688	[1]	16,579	[1]	14,273	[1]
Depreciation, amortization and impairments	120,608	[1]	113,133	[1]	91,129	[1]
Total operating expenses	715,693	[1]	624,111	[1]	485,735	[1]
Operating income	194,894	[1]	245,294	[1]	177,539	[1]
Interest income, net - affiliates	16,900	[1],[3]	24,106	[1],[3]	20,243	[1],[3]
Interest expense	(42,060)	[1],[4]	(30,345)	[1],[4]	(18,794)	[1],[4]
Other income (expense), net	292	[1]	(44)	[1]	(538)	[1]
Income before income taxes	170,026	[1]	239,011	[1]	178,450	[1]
Income tax expense	20,715	[1]	32,150	[1]	21,517	[1]
Net income	149,311	[1]	206,861	[1]	156,933	[1]
Net income attributable to noncontrolling interests	14,890	[1]	14,103	[1]	11,005	[1]
Net income attributable to Western Gas Partners, LP	134,421	[1]	192,758	[1]	145,928	[1]
Limited partners' interest in net income:
Pre-acquisition net (income) loss allocated to Anadarko	(27,435)	[1]	(52,599)	[1]	(31,797)	[1]
General partner interest in net (income) loss	(28,089)	[1],[5]	(8,599)	[1],[5]	(3,067)	[1],[5]
Limited partners' interest in net income	78,897	[1],[5]	131,560	[1],[5]	111,064	[1],[5]
Common [Member]
Limited partners' interest in net income:
Limited partners' interest in net income	78,897		110,542		68,410
Subordinated [Member]
Limited partners' interest in net income:
Limited partners' interest in net income			21,018		42,654
Affiliated Entity Member
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	249,997	[1]	227,535	[1]	192,286	[1]
Natural gas, natural gas liquids and condensate sales	436,423	[1]	417,547	[1]	369,903	[1]
Equity income and Other, net	17,717	[1]	13,598	[1]	9,439	[1]
Total revenues	704,137	[1],[6]	658,680	[1],[6]	571,628	[1],[6]
Operating expenses
Cost of product	145,250	[6]	83,722	[6]	95,667	[6]
Operation and maintenance	51,237	[7]	51,339	[7]	46,379	[7]
General and administrative	92,847	[8]	33,305	[8]	24,137	[8]
Total operating expenses	289,334		168,366		166,183
Interest expense	(2,766)	[9]	(4,935)	[9]	(6,924)	[9]
Third Parties [Member]
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	132,333	[1]	119,934	[1]	60,987	[1]
Natural gas, natural gas liquids and condensate sales	71,916	[1]	84,836	[1]	26,134	[1]
Equity income and Other, net	2,201	[1]	5,955	[1]	4,525	[1]
Total revenues	206,450	[1]	210,725	[1]	91,646	[1]
Operating expenses
Interest expense	$ (39,294)		$ (25,410)		$ (11,870)
Limited Partners Member | Common [Member]
Limited partners' interest in net income:
Net income per unit - basic and diluted	$ 0.84	[1]	$ 1.64	[1]	$ 1.66	[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] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $145.3 million, $83.7 million and $95.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Operation and maintenance includes charges from Anadarko of $51.2 million, $51.3 million and $46.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. General and administrative includes charges from Anadarko of $92.8 million, $33.3 million and $24.1 million for the years ended December 31, 2012, 2011 and 2010, 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 aforementioned assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.

[4] Includes affiliate (as defined in Note 1) interest expense of $2.8 million, $4.9 million and $6.9 million for the years ended December 31, 2012, 2011 and 2010, 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 Note 4.

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

[7] Represents expenses incurred during periods including and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.

[8] Represents general and administrative expense incurred during periods including and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see Anadarko Incentive Plans and Incentive Plan within this Note 5).

[9] Represents interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. During 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note receivable from and amounts payable to Anadarko within this Note 5.

[10] 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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Transactions With Affiliates - Commodity Price Per Unit Table (details)	Dec. 31, 2012
Ethane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	23.11
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 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
Ethane [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	23.41
Public Utilities, Inventory, Propane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.90
Public Utilities, Inventory, Propane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	45.90
Public Utilities, Inventory, Propane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	46.47
Public Utilities, Inventory, Propane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	47.08
Public Utilities, Inventory, Propane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	55.84
Public Utilities, Inventory, Propane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.78
Public Utilities, Inventory, Propane [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.99
Isobutane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	73.89
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 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	77.66
Isobutane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	75.13
Isobutane [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	74.02
Normal Butane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	64.93
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 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	68.24
Normal Butane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	66.01
Normal Butane [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	65.04
Natural Gasoline [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.68
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 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	83.04
Natural Gasoline [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.82
Per Million British Thermal Units Of Natural Gas [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.87
Per Million British Thermal Units Of Natural Gas [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	3.75
Per Million British Thermal Units Of Natural Gas [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.45
Per Million British Thermal Units Of Natural Gas [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.66
Per Million British Thermal Units Of Natural Gas [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	6.09
Per Million British Thermal Units Of Natural Gas [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	6.20
Per Million British Thermal Units Of Natural Gas [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	5.96
Condensate [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.68
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 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	85.84
Condensate [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	83.04
Condensate [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.82

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Consolidated Statement of Equity and Partners' Capital (USD $) In Thousands		Total		Chipeta Processing Limited Liability Company [Member]		Net Investment by Anadarko	Common [Member]	Common [Member] Chipeta Processing Limited Liability Company [Member]		Subordinated [Member]	General Partner Member	General Partner Member Chipeta Processing Limited Liability Company [Member]		Noncontrolling Interest Member	Noncontrolling Interest Member Chipeta Processing Limited Liability Company [Member]
Balance at Dec. 31, 2009	[1]	$ 1,627,818				$ 749,369	$ 497,230			$ 276,571	$ 13,726			$ 90,922
Net income		156,933	[1]			31,797	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) Anadarko		95,881				95,881
Net distributions of other assets to Anadarko	[1]	(7,827)
Elimination of net deferred tax liabilities		214,464				214,464
Contribution of other assets from Anadarko		10,715					10,500				215
Other		1,840				1,219	864			44	9			(296)
Balance at Dec. 31, 2010	[1]	1,613,311				408,243	810,717			282,384	21,505			90,462
Net income		206,861	[1]			52,599	110,542			21,018	8,599			14,103
Conversion of subordinated units to common units	[2]						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 Anadarko	[3]	9,666					9,472				194
Net pre-acquisition contributions from (distributions to) Anadarko		(33,785)				(33,785)
Elimination of net deferred tax liabilities		22,072				22,072
Other		(314)					(267)				(47)
Balance at Dec. 31, 2011	[1]	2,004,169				356,463	1,495,253				31,729			120,724
Net income		149,311	[1]			27,435	78,897				28,089			14,890
Issuance of common and general partner units, net of offering expenses		625,877					613,188				12,689
Contributions from noncontrolling interest owners		29,108												29,108
Distributions to noncontrolling interest owners		(17,303)												(17,303)
Distributions to unitholders		(197,850)					(175,639)				(22,211)
Acquisition from affiliates		(458,764)		(121,104)	[4]	(482,701)	23,458	(44,071)	[4]		479	162	[4]		(77,195)	[4]
Contributions of equity-based compensation from Anadarko	[3]	87,057					84,971				2,086
Net pre-acquisition contributions from (distributions to) Anadarko		85,662				192,259	(106,597)
Net distributions of other assets to Anadarko		(15,296)	[1]				(15,002)				(273)			(21)
Elimination of net deferred tax liabilities		106,504				106,504
Other		3,065					2,608				2			455
Balance at Dec. 31, 2012	[1]	$ 2,280,436				$ 199,960	$ 1,957,066				$ 52,752			$ 70,658

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. 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.

[3] Associated with the Anadarko Incentive Plans for the year ended December 31, 2011, and associated with the Anadarko Incentive Plans and the Incentive Plan for the year ended December 31, 2012, as defined and described in Note 1 and Note 5.

[4] See Note 2 for a description of the acquisition of Anadarko’s then remaining 24% membership interest in Chipeta in August 2012. The $43.9 million decrease to partners’ capital resulting from the August 2012 Chipeta acquisition together with net income attributable to Western Gas Partners, LP totaled $90.5 million for the year ended December 31, 2012.

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Debt and Interest Expense - Debt Outstanding Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010	Dec. 31, 2012 Senior Notes 4 Percent Due 2022 [Member]		Oct. 31, 2012 Senior Notes 4 Percent Due 2022 [Member]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Dec. 31, 2012 Senior Notes 5 Point 375 Percent Due 2021 [Member]		Dec. 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member]		May 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member]	Dec. 31, 2011 Note Payable To Anadarko [Member]		Dec. 31, 2008 Note Payable To Anadarko [Member]
Debt Instrument Line Items
Principal	$ 1,170,000		$ 675,000			$ 670,000		$ 150,000	$ 520,000	$ 500,000		$ 500,000		$ 500,000	$ 175,000		$ 175,000
Carrying Value	1,168,278		669,178		474,000	673,617				494,661		494,178			175,000
Fair Value	$ 1,169,874	[1]	$ 674,478	[1]		$ 669,928	[1]			$ 499,946	[1]	$ 499,950	[1]		$ 174,528	[1]

[1] Fair value is measured using Level 2 inputs.

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Acquisitions - Acquisitions Table (details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended																1 Months Ended								1 Months Ended			12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2012 Affiliated Entity Member		Dec. 31, 2011 Affiliated Entity Member		Dec. 31, 2010 Affiliated Entity Member		Dec. 31, 2011 Third Parties [Member]		Dec. 31, 2010 Third Parties [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]	Jan. 31, 2012 Mountain Gas Resources [Member]	Jan. 31, 2012 Mountain Gas Resources [Member] Rendezvous [Member]	Aug. 31, 2012 Chipeta Processing LLC	Dec. 31, 2012 Chipeta Processing LLC	Aug. 31, 2012 Chipeta Processing LLC Affiliated Entity Member
Business Acquisition Line Items
Percentage acquired																	100.00%	100.00%	10.00%	0.40%	9.60%	100.00%	100.00%		100.00%	22.00%	24.00%	75.00%
Borrowings	$ 1,041,648	[1]	$ 1,055,939	[1]	$ 660,000	[1]											$ 210,000	$ 450,000				$ 303,000			$ 299,000
Cash on hand							$ 611,719	[1]	$ 28,837	[1]	$ 734,780	[1]	$ 301,957	[1]	$ 18,047	[1]	$ 31,680	$ 23,100	$ 38,047			$ 602	$ 25,000		$ 159,587		$ 128,250
Common units issued																	620,689	1,048,196					2,950,284		632,783		151,235
GP units issued	2,135,930		1,839,613														12,667	21,392					60,210		12,914		3,086
Table Text Block Supplement Abstract
Assets, number of units																								3
Ownership interest by noncontrolling owners																												25.00%	24.00%

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Subsequent Events - Additional Information (details) (USD $)	12 Months Ended						0 Months Ended	1 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010		Mar. 08, 2013 Anadarko-Operated Marcellus Interest [Member]	Mar. 31, 2012 Anadarko-Operated Marcellus Interest [Member]	Mar. 08, 2013 Anadarko-Operated Marcellus Interest [Member]
Business Acquisition Line Items
Percentage acquired								33.75%
Total consideration for acquisition									$ 134,900,000
Borrowings	$ 1,041,648,000	[1]	$ 1,055,939,000	[1]	$ 660,000,000	[1]	$ 133,500,000

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Summary of Significant Accounting Policies (Table)

12 Months Ended

Dec. 31, 2012

Accounting Policies Abstract

Equity-Method Investments

		Equity Investments
thousands		Fort Union (1)		White Cliffs (2)		Rendezvous (3)
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
	Investment earnings, net of amortization		6,383		7,871		1,857
	Contributions		—		862		—
	Distributions		(5,198)		(8,876)		(6,586)
Balance at December 31, 2012		$	23,453	$	17,567	$	65,110

____________________________________________________________

(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.

(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. 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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Acquisitions - Impact to Historical Consolidated Statement of Income Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Prior Period Adjustments [Line Items]
Revenues	$ 910,587	[1]	$ 869,405	[1]	$ 663,274	[1]
Net income	149,311	[1]	206,861	[1]	156,933	[1]
Partnership Historical
Prior Period Adjustments [Line Items]
Revenues	849,440		823,265		663,274
Net income	121,876		188,346		157,197
Non-Operated Marcellus Interest [Member]
Prior Period Adjustments [Line Items]
Revenues	61,147		46,140
Net income	$ 27,435		$ 18,515		$ (264)

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Partnership Distributions (tables)

12 Months Ended

Dec. 31, 2012

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
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	$	0.440	$	43,027	February 2012
2012
March 31	$	0.460	$	46,053	May 2012
June 30	$	0.480	$	52,425	August 2012
September 30	$	0.500	$	56,346	November 2012
December 31 (1)	$	0.520	$	65,657	February 2013

___________________________________________________________________

(1)On January 21, 2013, the board of directors of the Partnership's general partner declared a cash distribution to the Partnership's unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

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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Consolidated Statement of Equity and Partners' Capital (Parenthetical) (Partners' Captial, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Chipeta Processing Limited Liability Company [Member]
Acquisition from affiliates		$ 43,900,000
The decrease to partner's capital resulting from the August 2012 Chipeta acquisition together with net income attributable to Western Gas Partners, LP	$ 90,500,000

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Consolidated Statements of Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Cost of product	$ 336,079	[1],[2]	$ 327,371	[1],[2]	$ 246,476	[1],[2]
Operation and maintenance	140,106	[1],[2]	126,464	[1],[2]	103,887	[1],[2]
General and administrative	99,212	[1],[2]	40,564	[1],[2]	29,970	[1],[2]
Interest expense	42,060	[1],[3]	30,345	[1],[3]	18,794	[1],[3]
Affiliated Entity Member
Cost of product	145,250	[4]	83,722	[4]	95,667	[4]
Operation and maintenance	51,237	[5]	51,339	[5]	46,379	[5]
General and administrative	92,847	[6]	33,305	[6]	24,137	[6]
Interest expense	$ 2,766	[7]	$ 4,935	[7]	$ 6,924	[7]

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $145.3 million, $83.7 million and $95.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Operation and maintenance includes charges from Anadarko of $51.2 million, $51.3 million and $46.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. General and administrative includes charges from Anadarko of $92.8 million, $33.3 million and $24.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 5.

[3] Includes affiliate (as defined in Note 1) interest expense of $2.8 million, $4.9 million and $6.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 10.

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

[5] Represents expenses incurred during periods including and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.

[6] Represents general and administrative expense incurred during periods including and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see Anadarko Incentive Plans and Incentive Plan within this Note 5).

[7] Represents interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. During 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note receivable from and amounts payable to Anadarko within this Note 5.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

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		2012		2011
Carrying amount of asset retirement obligations at beginning of year		$	64,345	$	45,269
	Liabilities incurred		9,414		15,462
	Liabilities settled		(786)		(133)
	Accretion expense		4,270		3,791
	Revisions in estimated liabilities		(10,520)		(44)
Carrying amount of asset retirement obligations at end of year		$	66,723	$	64,345

Revisions in estimated liabilities for the year ended December 31, 2012, related primarily to the change in the estimated timing of settling the Partnership's asset retirement obligations at the Wattenberg system. The liabilities incurred for the year ended December 31, 2012, represented the increase in asset retirement obligations primarily related to the capital expansion at the Wattenberg system.

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

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Document and Entity Information	12 Months Ended
	Dec. 31, 2012
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, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY

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Debt and Interest Expense

12 Months Ended

Dec. 31, 2012

Debt Instruments Abstract

Debt and Interest Expense

The following table presents the Partnership's outstanding debt as of December 31, 2012and 2011:

	December 31, 2012						December 31, 2011
			Carrying		Fair				Carrying		Fair
thousands	Principal		Value		Value (1)		Principal		Value		Value (1)
4.000% Senior Notes due 2022	$	670,000	$	673,617	$	669,928	$	—	$	—	$	—
5.375% Senior Notes due 2021		500,000		494,661		499,946		500,000		494,178		499,950
Note payable to Anadarko		—		—		—		175,000		175,000		174,528
Total debt outstanding	$	1,170,000	$	1,168,278	$	1,169,874	$	675,000	$	669,178	$	674,478

_______________________________________________________

(1)Fair value is measured using Level 2 inputs.

Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2012 and 2011:

thousands		Carrying Value
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
	Revolving credit facility borrowings		374,000
	Issuance of 4.000% Senior Notes due 2022		670,000
	Repayment of revolving credit facility		(374,000)
	Repayment of note payable to Anadarko		(175,000)
	Revolving credit facility borrowings – Swingline		20,000
	Repayment of revolving credit facility – Swingline		(20,000)
	Other and changes in debt discount or premium		4,100
Balance as of December 31, 2012		$	1,168,278

Senior Notes. In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount.In October 2012, the Partnership issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The additional notes were issued under the same indenture as, and as a single class of securities with, the June 2012 issuance. The notes issued in June 2012 and in October 2012 are collectivelyreferred to as the “2022 Notes.” Including the effects of the issuance discount for the June 2012 offering, the issuance premium for the October 2012 offering, and underwriting discounts, the effective interest rate of the 2022 Notes was4.040%. Interest is paid semi-annually on January 1 and July 1 of each year. Proceeds (net of underwriting discounts of $4.4 million and debt issuance costs) were used to repay all amounts then outstanding under the Partnership's revolving credit facility (“RCF”) and the $175.0 million note payable to Anadarko (see below), with the remaining net proceeds used for general partnership purposes.

The 2022 Notes mature on July 1, 2022, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the 2022 Notes in whole or in part, at any time before April 1, 2022, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2022 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 2022 Notes) plus 37.5 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 April 1, 2022, the 2022 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2022 Notes to be redeemed, plus accrued interest on the 2022 Notes to be redeemed to the date of redemption.

In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) at a price to the public of 98.778% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the 2021 Notes is paid semi-annually on June 1 and December 1 of each year. Proceeds from the offering of the 2021 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'sRCF, with the remainder used for general partnership purposes. Upon issuance, the 2021 Notes were 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 were immediately released on June 13, 2012, upon the Subsidiary Guarantors becoming released from their obligations under the RCF, as discussed below.

The 2021 Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. The Partnership may redeem the 2021 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 2021 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2021 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 2021 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 2021 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2021 Notes to be redeemed, plus accrued interest on the 2021 Notes to be redeemed to the date of redemption.

The indentures governing the 2022 Notes and the 2021 Notes contain customary events of default including, among others, (i) default for 30 days in the payment of interest when due; (ii) default in payment, when due, of principal of or premium, if any, at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency. The indentures also contain covenants that limit, among other things, the ability of the Partnership, as well as that of certain of the Partnership's subsidiaries, to (i) create liens on 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 the Partnership's properties or assets to another entity. At December 31, 2012, the Partnership was in compliance with all covenants under the indentures.

Note payable to Anadarko.In 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. In June 2012, the note payable to Anadarko was repaid in full with proceeds from theissuance of the 2022 Notes.

Revolving credit facility. In March 2011, the Partnership 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 a $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%, in each case plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.71% and 1.80% at December 31, 2012 and 2011, 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%at December 31, 2012 and 2011.

On June 13, 2012, following the receipt of a second investment grade rating as defined in the RCF, the guarantees provided by the Partnership's wholly owned subsidiaries were released, and the Partnership is no longer subject tocertain of the restrictive covenantsassociated with the RCF, including the maintenance of an interest coverage ratio and adherence to covenants that limit, among other things, the Partnership's, and certain of the Partnership's subsidiaries', ability to dispose of assets and make certain investments or payments.The RCF continues to contain certain covenants that limit, among other things, the ability of the Partnership, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of the Partnership's business, enter into certain affiliate transactions and use proceeds other than for Partnership purposes. The RCF also contains various customary covenants, customary events of default and a maximum consolidated leverage ratio as of the end of each fiscal quarter (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. As of December 31, 2012, the Partnership had no outstanding borrowingsand $6.7 million in outstanding letters of credit issued under its $800.0 million RCF. At December 31, 2012, the Partnership was in compliance with all remaining covenants under the RCF. Refer to Note 2 and Note 12 for a discussion of borrowing activity under the RCF in March 2013, related to acquisitions which closed after December 31, 2012.

The 2022 Notes, the 2021 Notes and obligations under the RCF are recourse to the Partnership's general partner. In turn, the Partnership's general partner has been indemnified by a wholly owned subsidiary of Anadarko against any claims made against the general partner under the 2022 Notes, the 2021 Notes and/or the RCF.

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 agreements. In May 2012, the Partnership entered into U.S. Treasury Rate lock agreements to mitigate the risk of rising interest rates prior to the issuance of the 2022 Notes. The Partnership settled therate lock agreements simultaneously with the June 2012 offering of the 2022 Notes, realizing a loss of $1.7 million, which is included in other income (expense), net in the consolidated statements of income.

In March 2011, the Partnership entered into a forward-starting interest-rate swap agreementto mitigate the risk of rising interest rates prior to the issuance of the 2021 Notes. In May 2011, the Partnership issued the 2021 Notes and terminated the swap agreement, realizing a loss of $1.9 million, which is included in other income(expense), net in the consolidated statements of income.

In April 2010, the Partnership entered into financial agreements to fix the underlying 10-year Treasury rates with respect to a potential note issuance that was not realized. In May 2010, the Partnership terminated the agreements, realizing a loss of $2.4 million, which is included in other income (expense), net in the consolidated statements of income.

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

			Year Ended December 31,
thousands			2012		2011		2010
Third parties
	Interest expense on long-term debt		$	41,171	$	20,533	$	8,530
	Amortization of debt issuance costs and commitment fees (1)			4,319		5,297		3,340
	Capitalized interest (2)			(6,196)		(420)		—
		Total interest expense – third parties		39,294		25,410		11,870
Affiliates
	Interest expense on note payable to Anadarko (3)			2,440		4,935		6,828
	Interest expense on affiliate balances (4)			326		—		—
	Credit facility commitment fees			—		—		96
		Total interest expense – affiliates		2,766		4,935		6,924
Interest expense			$	42,060	$	30,345	$	18,794

___________________________________________________________________

(1)For the year ended December 31, 2012, includes $1.1 million of amortization of (i) the original issue discount for the June 2012 offeringpartially offset by the original issuepremium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters' fees. For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters' fees for the 2021 Notes.

(2)For the year ended December 31, 2012, $2.2 million of interest associated with capital projects at Chipeta was capitalized and $3.5 million of interest associated with the construction of the Brasada and Lancaster gas processing facilities was capitalized. SeeNote 5.

(3)In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

(4)Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of theBrasada and Lancaster plants.During 2012, the Partnership repaid the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note 5.

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Consolidated Balance Sheet (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Current assets
Cash and cash equivalents	$ 419,981	[1]	$ 226,559	[1]
Accounts receivable, net	50,233	[1],[2]	90,328	[1],[2]
Other current assets	6,998	[1],[3]	7,186	[1],[3]
Total current assets	477,212	[1]	324,073	[1]
Note receivable - Anadarko	260,000	[1]	260,000	[1]
Plant, property and equipment
Cost	3,432,392	[1]	2,708,271	[1]
Less accumulated depreciation	714,436	[1]	587,119	[1]
Net property, plant and equipment	2,717,956	[1]	2,121,152	[1]
Goodwill	105,336	[1]	99,536	[1]
Other intangible assets	55,490	[1]	52,858	[1]
Equity investments	106,130	[1]	109,817	[1]
Other assets	27,798	[1]	24,143	[1]
Total assets	3,749,922	[1]	2,991,579	[1]
Current liabilities
Accounts and natural gas imbalance payables	25,154	[1],[4]	26,600	[1],[4]
Accrued ad valorem taxes	11,949	[1]	8,186	[1]
Income taxes payable	552	[1]	495	[1]
Accrued liabilities	147,651	[1],[5]	92,037	[1],[5]
Total current liabilities	185,306	[1]	127,318	[1]
Long-term debt Note payable - Anadarko	1,168,278		669,178
Deferred income taxes	47,153	[1]	123,544	[1]
Asset retirement obligations and other	68,749	[1]	67,370	[1]
Total long-term liabilities	1,284,180	[1]	860,092	[1]
Total liabilities	1,469,486	[1]	987,410	[1]
Equity and partners' capital
Common units (104,660,553 and 90,140,999 units issued and outstanding at December 31, 2012, and December 31, 2011, respectively)	1,957,066	[1]	1,495,253	[1]
General partner units (2,135,930 and 1,839,613 units issued and outstanding at December 31, 2012, and December 31, 2011, respectively)	52,752	[1]	31,729	[1]
Net investment by Anadarko	199,960	[1]	356,463	[1]
Total partners' capital	2,209,778	[1]	1,883,445	[1]
Noncontrolling interests	70,658	[1]	120,724	[1]
Total equity and partners' capital	2,280,436	[1]	2,004,169	[1]
Total liabilities, equity and partners' capital	3,749,922	[1]	2,991,579	[1]
Third Parties [Member]
Current liabilities
Long-term debt Note payable - Anadarko	1,168,278	[1]	494,178	[1]
Affiliated Entity Member
Current assets
Accounts receivable, net	19,100
Other current assets	400		500
Current liabilities
Accounts and natural gas imbalance payables	2,500		5,900
Accrued liabilities	100		300
Long-term debt Note payable - Anadarko			$ 175,000	[1]

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

[2] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $19.1 million and zero as of December 31, 2012 and 2011, respectively.

[3] Other current assets includes natural gas imbalance receivables from affiliates of $0.4 million and $0.5 million as of December 31, 2012 and 2011, respectively.

[4] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.5 million and $5.9 million as of December 31, 2012 and 2011, respectively.

[5] Accrued liabilities include amounts payable to affiliates of $0.1 million and $0.3 million as of December 31, 2012 and 2011, respectively.

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Equity and Partners' Capital

12 Months Ended

Dec. 31, 2012

Partners Capital Notes Abstract

Equity and Partners' Capital

Equity offerings.The Partnership completed the following public offerings of its common units during 2010, 2011 and 2012:

						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
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
June 2012 equity offering		5,000,000	102,041		43.88		7,468		216,409

____________________________________________________________

(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 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 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 contributionto maintain its 2.0% general partner interest.

Common, subordinated and general partner units.The Partnership's common units are listed on the New York Stock Exchange under the symbol “WES.”In connection with the closing of the WGP IPO in December 2012, WGP purchased common and general partner units of the Partnership at a price of $46.00 per unit, pursuant to a unit purchase agreement among the Partnership, the general partner and WGP.

The following table summarizes common and general partner units issued during the years ended December 31, 2011 and 2012:

		Common	Subordinated	General
		Units	Units	Partner Units	Total
Balance at December 31, 2010		51,036,968	26,536,306	1,583,128	79,156,402
	March 2011 equity offering	3,852,813	—	78,629	3,931,442
	Long-Term Incentive Plan awards	14,628	—	299	14,927
	Bison acquisition	2,950,284	—	60,210	3,010,494
	Conversion of subordinated units	26,536,306	(26,536,306)	—	—
	September 2011 equity offering	5,750,000	—	117,347	5,867,347
Balance at December 31, 2011		90,140,999	—	1,839,613	91,980,612
	MGR acquisition	632,783	—	12,914	645,697
	Long-Term Incentive Plan awards	12,570	—	257	12,827
	June 2012 equity offering	5,000,000	—	102,041	5,102,041
	Chipeta acquisition	151,235	—	3,086	154,321
	WGP unit purchase agreement	8,722,966	—	178,019	8,900,985
Balance at December 31, 2012		104,660,553	—	2,135,930	106,796,483

Conversion of subordinated units.Upon payment of the cash distribution for the second quarter of 2011, the requirements for the conversion of all subordinated units were satisfied under the partnership agreement. As a result, the 26,536,306 subordinated units were convertedinto common units on August 15, 2011, on a one-for-one basis. 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.

WGP and Affiliate holdings of Partnership equity. As of December 31, 2012, WGPand Affiliates held 49,296,205of the Partnership's common units, representing a 46.2% limited partner interest in the Partnership, and, through its ownership of the general partner, indirectly held 2,135,930 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the IDRs. As of December 31, 2012, the public held 55,364,348 common units, representing a 51.8%limited partner interest in the Partnership.

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 partnersconsistent 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 and the limited partners in accordance with their respective ownership percentages (see Net income per common unit inNote 1).

Basic and diluted net income per common unit are 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	2012		2011		2010
Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928
Pre-acquisition net (income) loss allocated to Anadarko		(27,435)		(52,599)		(31,797)
General partner interest in net (income) loss		(28,089)		(8,599)		(3,067)
Limited partners’ interest in net income	$	78,897	$	131,560	$	111,064
Net income allocable to common units	$	78,897	$	110,542	$	68,410
Net income allocable to subordinated units		—		21,018		42,654
Limited partners’ interest in net income	$	78,897	$	131,560	$	111,064
Net income per unit – basic and diluted
Common units	$	0.84	$	1.64	$	1.66
Subordinated units	$	—	$	1.28	$	1.61
Weighted average units outstanding – basic and diluted
Common units		93,936		67,333		41,287
Subordinated units		—		16,431		26,536

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Partnership Distributions

12 Months Ended

Dec. 31, 2012

Distributions Made to Members or Limited Partners [Abstract]

Partnership Distributions

The partnership agreement of Western Gas Partners, LP 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
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	$	0.440	$	43,027	February 2012
2012
March 31	$	0.460	$	46,053	May 2012
June 30	$	0.480	$	52,425	August 2012
September 30	$	0.500	$	56,346	November 2012
December 31 (1)	$	0.520	$	65,657	February 2013

___________________________________________________________________

(1)On January 21, 2013, the board of directors of the Partnership's general partner declared a cash distribution to the Partnership's unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

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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Acquisitions (tables)

12 Months Ended

Dec. 31, 2012

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
Granger (1)		01/29/10	100%	$	210,000	$	31,680	620,689	12,667
Wattenberg (2)		08/02/10	100%		450,000		23,100	1,048,196	21,392
White Cliffs (3)		09/28/10	10%		—		38,047	—	—
Platte Valley (4)		02/28/11	100%		303,000		602	—	—
Bison (5)		07/08/11	100%		—		25,000	2,950,284	60,210
MGR (6)		01/13/12	100%		299,000		159,587	632,783	12,914
Chipeta (7)		08/01/12	24%		—		128,250	151,235	3,086

(1)       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.”

(2)       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.”

(3)       White Cliffs owns a crude oil pipeline thatoriginates in Platteville, Colorado and terminates in Cushing, Oklahoma. 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.”

(4)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.”

(5)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.The Bison assets were placed in service in June 2010.

(6)The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a 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.”

(7)The Partnership acquired Anadarko's then remaining 24% membership interest in Chipeta (as described in Note 1), with the Partnership receiving distributions related to the additional interest beginning July 1, 2012. This transaction brought the Partnership's total membership interest in Chipeta to 75%. The remaining 25% membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented.

Impact to Historical Consolidated Statement of Income Table

	Year Ended December 31, 2012
	Partnership		Non-Operated
thousands	Historical		Marcellus Interest		Combined
Revenues	$	849,440	$	61,147	$	910,587
Net income		121,876		27,435		149,311
	Year Ended December 31, 2011
	Partnership		Non-Operated
thousands	Historical		Marcellus Interest		Combined
Revenues	$	823,265	$	46,140	$	869,405
Net income		188,346		18,515		206,861
	Year Ended December 31, 2010
	Partnership		Non-Operated
thousands	Historical		Marcellus Interest		Combined
Revenues	$	663,274	$	-	$	663,274
Net income (loss)		157,197		(264)		156,933

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies [Abstract]

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, 2012 and 2011, asset retirement obligations and other on the consolidated balance sheets included $1.9 million and $1.6 million, respectively, for the long-term liability for remediation and reclamation obligations. The recorded obligations do not include any anticipated insurance recoveries. Substantially all of the payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes that the amounts reflected in the Partnership's recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership's overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered.See Note 8.

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 in the discovery phase. Trial is set for April 2014.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 its capital spending programs, as well as those of its unconsolidated affiliates. As of December 31, 2012, the Partnership had unconditional payment obligations for services to be rendered, or products to be delivered in connection with its capital projects of approximately $55.9 million, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to the continued construction of the Brasada and Lancaster plants (see Note 5) and include 100% of obligations related to Chipeta, in which the Partnership has a 75% membership interest (see Note 1).

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 corporate offices and shared field offices extend through 2017 and 2018, respectively, and the lease for the warehouse extends through February 2014 and includes an early termination clause.

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 $3.0 million, $4.1 million and $7.7 millionfor the years ended December 31, 2012, 2011 and 2010, respectively.

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2012, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:

thousands	Operating Leases
2013	$	235
2014		169
2015		169
2016		169
2017		169
Thereafter		42
Total	$	953

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

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	2012		2011
Land		n/a	$	501	$	364
Gathering systems		5 to 47 years		2,911,572		2,479,184
Pipelines and equipment		15 to 45 years		91,126		90,883
Assets under construction		n/a		422,002		132,913
Other		3 to 25 years		7,191		4,927
	Total property, plant and equipment			3,432,392		2,708,271
Accumulated depreciation				714,436		587,119
	Net property, plant and equipment		$	2,717,956	$	2,121,152

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. See Note 8.

During the fourth quarter of 2012, the Partnership recognized a $6.0 million impairment related to a gathering system in central Wyoming that was impaired to its estimated fair value using Level 3 fair-value inputs. Also in the fourth quarter of 2012, an impairment of $0.6 million was recognized for the original installation costs on a compressor relocated within the Partnership's operating assets.

During the year ended December 31, 2011, the Partnership recognized a $7.3 million impairment related to 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 was reclassified from within property, plant and equipment to other assets on the consolidated balance sheet and was approximately $10.6 million 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 that was impaired to its estimated fair value using Level 3 fair-value inputs.

During the year ended December 31, 2010, the Partnership recognized a $0.6 million impairment related to a compressor sold during the year to a third party, and a $0.3 million impairment due to cancelled capital projects and additional costs recorded on a project previously impaired to salvage value.

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Debt and Interest Expense - Debt Activity Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument Line Items
Balance	$ 669,178	$ 474,000
Other and changes in debt discount or premium	4,100	(5,822)
Balance	1,168,278	669,178
Revolving Credit Facility [Member]
Debt Instrument Line Items
Borrowings	374,000	570,000
Repayments	(374,000)	(619,000)
Revolving Credit Facility [Member] | Swingline [Member]
Debt Instrument Line Items
Borrowings	20,000	30,000
Repayments	(20,000)	(30,000)
Senior Notes 4 Percent Due 2022 [Member]
Debt Instrument Line Items
Borrowings	670,000
Balance	673,617
Note Payable To Anadarko [Member]
Debt Instrument Line Items
Balance	175,000
Repayments	(175,000)
Wattenberg Term Loan [Member]
Debt Instrument Line Items
Repayments		(250,000)
Senior Notes 5 Point 375 Percent Due 2021 [Member]
Debt Instrument Line Items
Borrowings		500,000
Balance	$ 494,661	$ 494,178

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Transactions With Affiliates

12 Months Ended

Dec. 31, 2012

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, 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 Partnership's omnibus agreement. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues. 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 net investment by Anadarko in connection with the acquisition of the Partnership assets. Subsequent to the acquisition of Partnership assets from Anadarko, 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. Chipetacashsettles its transactions directly with third parties andAnadarko,as well as with the other subsidiaries of the Partnership.

Note receivable from and amountspayable to Anadarko.Concurrent with the closing of the Partnership's May 2008 IPO, 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 $334.8 million and $303.7million at December 31, 2012, and December 31, 2011, 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. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.

In 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko, which was repaid in full in June 2012 using the proceeds from the issuance of the 4.000% Senior Notes due 2022 (the “2022 Notes”). See Note 10.

During the first quarter of 2012, the board of directors of the Partnership's general partner approved the continued construction by the Partnership of the Brasada and Lancaster gas processing facilities in South Texas and Northeast Colorado, respectively, which were previously under construction by Anadarko. The Partnership agreed to reimburse Anadarko for $18.9 million of certain expenditures Anadarko incurred in 2011related to the construction of theBrasada and Lancaster plants. In February 2012, these expenditures were transferred to the Partnership and a corresponding current payable was recorded, which the Partnershiprepaid during the fourth quarter of2012.

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 commodity price 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 Granger, Hilight, Hugoton, Newcastle, MGRand Wattenberg assets,with various expiration dates through December 2016.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. The Partnership has not entered into any new commodity price swap agreements since the fourth quarter of 2011.

Below is a summary of the fixed price ranges on the Partnership's outstanding commodity price swap agreements as of December 31, 2012:

	Year Ended December 31,
per barrel except natural gas	2013				2014				2015				2016
Ethane	$	18.32	−	30.10	$	18.36	−	30.53	$	18.41	−	23.41	$	23.11
Propane	$	45.90	−	55.84	$	46.47	−	53.78	$	47.08	−	52.99	$	52.90
Isobutane	$	60.44	−	77.66	$	61.24	−	75.13	$	62.09	−	74.02	$	73.89
Normal butane	$	53.20	−	68.24	$	53.89	−	66.01	$	54.62	−	65.04	$	64.93
Natural gasoline	$	70.89	−	92.23	$	71.85	−	83.04	$	72.88	−	81.82	$	81.68
Condensate	$	74.04	−	85.84	$	75.22	−	83.04	$	76.47	−	81.82	$	81.68
Natural gas (per MMbtu)	$	3.75	−	6.09	$	4.45	−	6.20	$	4.66	−	5.96	$	4.87

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

			Year Ended December 31,
thousands			2012		2011		2010
Gains (losses) on commodity price swap agreements
	related to sales: (1)
	Natural gas sales		$	37,665	$	33,845	$	20,200
	Natural gas liquids sales			66,260		(36,802)		2,953
		Total		103,925		(2,957)		23,153
Losses on commodity price swap agreements
	related to purchases (2)			(89,710)		(27,234)		(23,344)
Net gains (losses) on commodity price swap agreements			$	14,215	$	(30,191)	$	(191)

___________________________________________________________________

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

(2)Reported in cost of product in the 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. The gathering agreements of the Partnership's initial assets allow for rate resets that target an 18% return on invested capital in those assets. Approximately 64%, 67% and 73%of the Partnership's gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) for the years ended December 31, 2012,2011 and 2010, respectively,was attributable to natural gas production owned or controlled by Anadarko. Approximately 59%,64% and 66%of the Partnership's processing throughput (excluding equity investment throughput and volumes measured in barrels) for the years ended December 31, 2012, 2011 and 2010, 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 for the year ended December 31, 2010 and the cap expired on December 31, 2010. Expenses in excess of the cap for the year ended December 31, 2010 were recorded as capital contributions from Anadarko and did not impact the Partnership's cash flows. The Partnership also incurred $8.0 million in public company expenses, such as external audit and consulting fees, not subject to the cap previously contained in the omnibus agreement, during the year ended December 31, 2010.

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 reimbursed by the Partnership in exchange for services provided under the omnibus agreement. Such amount was $21.7 million for the year ended December 31, 2012,comprised of $14.9million of general and administrative expenses and $6.8 million of public company expenses. The Partnership reimbursed Anadarko $19.5 million for the year ended December 31, 2011,comprised of $11.8 million of general and administrative expenses and $7.7 million of public company expenses. 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. Theconsolidated financial statements include costs allocated by Anadarko for expenses incurred under 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 its estimated share of applicable state taxes. These taxes include income taxes attributable to the Partnership's income which are directly borne by Anadarko through its filing of a combined or consolidated tax return with respect to periods including and subsequent to the acquisition of the Partnership assets from Anadarko. Anadarko may use its own tax attributes to reduce or eliminate the tax liability of its combined or consolidated group, which may include the Partnership as a member. However, under this circumstance, the Partnership nevertheless is required to reimburse Anadarko for its allocable share of taxes that would have been owed had tax attributes not been available to Anadarko.

Allocation of costs. For periods prior to the Partnership's acquisition of the Partnership assets, the consolidated financial statements 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 allocates costs to the Partnership for its share of personnel costs, including costs associated with equity-based compensation plans, non-contributory defined pension and postretirement plans, defined contribution savings plan pursuant to the omnibus agreement and services and secondment agreement. 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. Most general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, and do not include any mark-up or subsidy component. With respect to allocated costs, management believes the allocation method employed by Anadarko is reasonable. Although it is not practicable to determine what the amount of these direct and allocated costs would be if the Partnership were to directly obtain these services, management believes that aggregate costs charged to the Partnership by Anadarko are reasonable.

Long-term incentive plan.The general partner awards phantom units under the LTIP primarily to its Chief Executive Officer and its independent directors. 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 is recognized over the vesting period and was approximately $0.4 million, $0.3 million and $0.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. As of December 31, 2012, there was $0.8 million of unrecognized compensation expense attributable to the outstanding awards under the LTIP, of which $0.7 million will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 2.2 years.

The following table summarizes LTIP award activity for the years ended December 31, 2012, 2011 and 2010:

		2012			2011			2010
		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	$	33.92	23,978	$	20.19	17,503	$	15.02	21,970
Vested		$	33.20	(14,260)	$	20.51	(15,119)	$	15.02	(19,751)
Granted		$	45.91	15,901	$	35.66	21,594	$	20.94	15,284
Phantom units outstanding
	at end of year	$	41.77	25,619	$	33.92	23,978	$	20.19	17,503

Anadarko Incentive Plans.For the years ended December 31, 2012, 2011 and 2010, the Partnership's general and administrative expenses include $3.3 million, $2.5 million and $2.3 million, respectively, of equity-based compensation expense for awards granted to the executive officers of the general partner and other employeesunder the Anadarko Incentive Plans, which wasallocated to the Partnership by Anadarko.As of December 31, 2012, the Partnership estimates that $4.4 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 1.9 years. As of December 31, 2012, the compensation cost related to performance-based awards under the Anadarko Incentive Plans that could be allocated to the Partnership during the next two years was approximately $0.1 million.

During the fourth quarter of 2011, the Partnership recorded $9.7 million to partners' capital in its consolidated financial statements for accumulated compensation expense attributable to the Anadarko Incentive Plans.

The Incentive Plan. For the years ended December 31, 2012,2011 and 2010, the Partnership's general and administrative expenses include $68.8 million,$11.4 million and $3.1 million, respectively, of compensation expense for grants of Unit Value Rights (“UVRs”), Unit Appreciation Rights (“UARs”) and Distribution Equivalent Rights (“DERs”) under the Incentive Plan to certain executive officers of the general partner as a component of their compensation, which was allocated to the Partnership by Anadarko.

Under the terms of the Incentive Plan, the value of a UAR wasequal to an amount calculated by dividing the “determined value” by 1,000,000, lessthe applicable UAR exercise price. Prior to WGP's IPO in December 2012, the value of awards issued under the Incentive Plan were 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.UARs outstanding under the Incentive Plan as of December 31, 2011 and 2010, were valued at $634.00 per UAR and $215.00 per UAR, respectively. Anadarko and the Incentive Plan participants entered into a Memorandum of Understanding (the “MOU”) that, among other things, confirmed the intent and the understanding that the WGP IPO resulted in the vesting of all unvested Incentive Plan awards and that the value of the Partnership's common units held by WGP prior to its IPO would not be considered in the valuation of the Incentive Plan awards.

The WGP IPO and concurrent execution of the MOUtriggered the exercise of all outstanding UARs and lump-sum cash payments (less any applicable withholding taxes) to plan participants equal to the value of each award, less its exercise price, if applicable. Pursuant to the MOU, the “determined value” was defined as equal to the aggregate WGP equity value, as determined using the market price of WGP based on the IPO price of WGP's common units, reduced by the market value of the Partnership's common units owned by WGP prior to its IPO (based on the closing price of the Partnership's common units on the day of the pricing of the IPO). Awards outstanding under the Incentive Plan at the time of the WGP IPO (and the effective termination of the Incentive Plan) were valued at $2,745.00 per UAR and $12.00 per DER. Outstanding UVRs that vested concurrent with the WGP IPO were cash-settled at their grant-date fair value.

In addition to the execution of the MOU, WGP, the Partnership's general partner and Anadarko entered into a contribution agreement whereby cash, in an amount equal to the aggregate cash payment required to settle all outstanding awards, was contributed to the Partnership's general partner by Anadarko. The cash payments made in connection with WGP's IPO and the vesting, exercise and settlement of all outstanding awards under the Incentive Plan as described above, impacted the Partnership's cash flows to the extent compensation expense was allocated to the Partnership since the inception of the Incentive Plan.The compensation expense allocated to the Partnership since the inception of the Incentive Plan, and subsequently contributed by Anadarko during the fourth quarter of 2012, was recorded to partners' capital in the consolidated financial statements.

Equipment purchase and sale.The following table summarizes the Partnership's purchases from and sales to Anadarko of pipe and equipment:

	Purchases						Sales
	Year Ended December 31,
thousands	2012		2011		2010		2012		2011		2010
Net carrying value	$	8,009	$	1,998	$	429	$	393	$	316	$	2,576
Cash consideration		24,705		3,837		361		760		382		2,805
Partners’ capital adjustment	$	16,696	$	1,839	$	(68)	$	367	$	66	$	229

Capital expenditures transfer.As described in Note receivable from and amounts payable to Anadarko above, Anadarko incurred certain expenditures related to the construction of the Brasada and Lancaster gas processing facilities during 2011. These amounts, along with related capitalized interest,were transferred to the Partnershipin the first quarter of 2012, and are included in property, plant and equipment as of December 31, 2012.

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		2012		2011		2010
Revenues (1)		$	704,137	$	658,680	$	571,628
Cost of product (1)			145,250		83,722		95,667
Operation and maintenance (2)			51,237		51,339		46,379
General and administrative (3)			92,847		33,305		24,137
	Operating expenses		289,334		168,366		166,183
Interest income, net (4)			16,900		24,106		20,243
Interest expense (5)			2,766		4,935		6,924
Distributions to unitholders (6)			98,280		68,039		52,337
Contributions from noncontrolling interest owners (7)			12,588		16,476		2,019
Distributions to noncontrolling interest owners (7)			6,528		9,437		6,476

____________________________________________________________

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

(2)Represents expenses incurred during periods including and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.

(3)Represents general and administrative expense incurred during periods including and subsequent to the date of the Partnership's acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership.These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see Anadarko Incentive Plans and Incentive Plan within this Note 5).

(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 Wattenbergassets 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 aforementioned assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.

(5)Represents interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputedon the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of theBrasada and Lancaster plants. During 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. SeeNote receivable from and amounts payable to Anadarko within thisNote 5.

(6)Represents distributions paid under the partnership agreement.

(7)As described in Note 1and Note 2, the Partnership acquired Anadarko's then remaining 24% membership interest in Chipeta on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.

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 consolidated statements of income.

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Income Taxes

12 Months Ended

Dec. 31, 2012

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		2012		2011		2010
Current income tax expense (benefit)
	Federal income tax expense (benefit)	$	(7,555)	$	15,248	$	10,476
	State income tax expense (benefit)		(1,843)		322		1,502
	Total current income tax expense (benefit)		(9,398)		15,570		11,978
Deferred income tax expense (benefit)
	Federal income tax expense		22,328		13,075		9,673
	State income tax expense (benefit)		7,785		3,505		(134)
	Total deferred income tax expense		30,113		16,580		9,539
Total income tax expense		$	20,715	$	32,150	$	21,517

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		2012		2011		2010
Income before income taxes		$	170,026	$	239,011	$	178,450
Statutory tax rate			0%		0%		0%
Tax computed at statutory rate		$	—	$	—	$	—
Adjustments resulting from:
	Federal taxes on income attributable to Partnership assets pre-acquisition		17,251		29,502		20,534
	State taxes on income attributable to Partnership assets pre-acquisition
	(net of federal benefit)		2,206		1,984		683
	Texas margin tax expense (benefit)		1,258		664		300
Income tax expense		$	20,715	$	32,150	$	21,517
Effective tax rate			12%		13%		12%

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

	December 31,
thousands	2012		2011
Credit carryforwards	$	14	$	14
Net current deferred income tax assets		14		14
Depreciable property		(47,558)		(99,733)
Partnership basis		—		(24,481)
Credit carryforwards		541		556
Other		(136)		114
Net long-term deferred income tax liabilities		(47,153)		(123,544)
Total net deferred income tax liabilities	$	(47,139)	$	(123,530)

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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Accrued Liabilities

12 Months Ended

Dec. 31, 2012

Accrued Liabilities Current Abstract

Accrued Liabilities

A summary of accrued liabilities is as follows:

	December 31,
thousands	2012		2011
Accrued capital expenditures	$	112,311	$	60,391
Accrued plant purchases		16,350		19,607
Accrued interest expense		15,868		2,251
Accrued charges under COO Agreement (see Note 2)		—		5,299
Short-term asset retirement obligations		1,711		875
Short-term remediation and reclamation obligations		799		1,679
Other		612		1,935
Total accrued liabilities	$	147,651	$	92,037

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Commitment and Contingencies - Additional Information (details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitments and Contingencies Line Items
Long-term liability for remediation and reclamation obligations	$ 1.9	$ 1.6
Term Of Payments On Environmental Obligations In Years	5 years
Committed capital	55.9
Term of instrument or obligation	1 year
Rent expense associated with office and equipment leases	3.0	4.1	7.7
Anadarko [Member]
Commitments and Contingencies Line Items
Purchase of previously leased compression equipment			$ 44.5
Chipeta Processing LLC
Commitments and Contingencies Line Items
Percentage included	100.00%
Ownership interest	75.00%

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Commitments and Contingencies - Operating Lease Obligations Table (detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Commitments And Contingencies [Abstract]
2013	$ 235
2014	169
2015	169
2016	169
2017	169
Thereafter	42
Total	$ 953

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Summary of Significant Accounting Policies - Additional Information (details) (USD $)	1 Months Ended						12 Months Ended						12 Months Ended			1 Months Ended	12 Months Ended							1 Months Ended	12 Months Ended
	Jun. 30, 2012	Sep. 30, 2011	Mar. 31, 2011	Nov. 30, 2010	May 31, 2010		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010	Dec. 31, 2012 Long Term Incentive Plan [Member]	Dec. 31, 2012 Fort Union [Member]	Dec. 31, 2012 Rendezvous [Member]	Dec. 31, 2012 White Cliffs [Member]	Jul. 31, 2009 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Non-Operated Marcellus Interest [Member]	Dec. 31, 2012 Newcastle [Member]	Dec. 31, 2012 Affiliated Entity Member White Cliffs [Member]	Dec. 31, 2012 Affiliated Entity Member Chipeta Processing Limited Liability Company [Member]	Jul. 31, 2009 Affiliated Entity Member Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Third Parties [Member] Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Western Gas Equity Partners [Member]	Dec. 31, 2012 Western Gas Equity Partners [Member]	Dec. 31, 2012 Western Gas Equity Partners [Member] Underwriter Over-Allotment Option	Dec. 31, 2012 Gathering System [Member] Operated [Member]	Dec. 31, 2012 Gathering System [Member] Non Operated Interest [Member]	Dec. 31, 2012 Gathering System [Member] Operated Interest [Member]	Dec. 31, 2012 Natural Gas Treating Facilities [Member] Operated [Member]	Dec. 31, 2012 Natural Gas Processing Facilities [Member] Operated [Member]	Dec. 31, 2012 Natural Gas Processing Facilities [Member] Operated Interest [Member]	Dec. 31, 2012 Natural Gas Liquids Pipeline [Member] Operated [Member]	Dec. 31, 2012 Interstate Gas Pipeline [Member] Operated [Member]	Dec. 31, 2012 Intrastate Gas Pipeline [Member] Operated [Member]
Assets, number of units																											12	2	1	7	7	2	2	1	1
Ownership interest													14.81%	22.00%		51.00%		33.75%	50.00%	0.40%					100.00%
Ownership interest by noncontrolling owners																					24.00%	24.00%	25.00%
Bad-debt reserve							$ 0		$ 17,000
Natural gas imbalance receivables							1,700,000		2,300,000
Natural gas imbalance payables							3,100,000		3,100,000
Goodwill							105,336,000	[1]	99,536,000	[1]	82,136,000
Straight-line basis of amortization							50 years										10 years
Customer relationship intangible assets							55,500,000		52,900,000								3,700,000
Accumulated amortization of customer relationship intangible assets							2,000,000		900,000
Equity method investment difference between carrying and underlying value													2,600,000	45,900,000	9,800,000
Capital lease receivable							400,000		700,000
Unguaranteed residual value							4,600,000
Units available under LTIP												2,144,947
Units authorized under LTIP												2,250,000
Percentage ownership of general partner																									2.00%
Common units issued																								19,758,150	19,758,150	2,577,150
Price per unit	$ 43.88	$ 35.86	$ 35.15	$ 29.92	$ 22.25	[2]																		$ 22.00
Proceeds From Issuance Of Private Placement																								409,400,000
Estimated future amortization							1,400,000
Outstanding checks in excess of bank account balances							$ 11,600,000		$ 9,800,000

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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

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Income Taxes - Components of Income Tax Expense Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Current Income Tax Expense Benefit Abstract
Federal income tax expense (benefit)	$ (7,555)		$ 15,248		$ 10,476
State income tax expense (benefit)	(1,843)		322		1,502
Total current income tax expense (benefit)	(9,398)		15,570		11,978
Deferred Income Tax Expense Benefit Abstract
Federal income tax expense	22,328		13,075		9,673
State income tax expense (benefit)	7,785		3,505		(134)
Total deferred income tax expense	30,113	[1]	16,580	[1]	9,539	[1]
Total income tax expense	$ 20,715	[1]	$ 32,150	[1]	$ 21,517	[1]

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Organization Consolidation And Presentation Of Financial Statements [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, 2012. Because Anadarko controls the Partnership through its control of WGP, which owns the Partnership's general partner, each of the Partnership's acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko's historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such assets as of the date of common control. See Note 2.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership's acquisition of Partnership assets from Anadarko, including the Non-Operated Marcellus Interest,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 reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other methods considered reasonable under the particular 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 business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

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 reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments.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 debts on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. As of December 31, 2012, there was no reserve for bad debts. The third-party accounts receivable balance at December 31, 2011, was 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' pipelines. 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, 2012, natural gas imbalance receivables and payables were approximately $1.7 million and $3.1 million, respectively. As of December 31, 2011, natural gas imbalance receivables and payables were approximately $2.3 million and $3.1 million, respectively. Changes in natural gas imbalances are reported in equity income and other, net for imbalance receivablesor in cost of productfor imbalance payables.

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 assets acquired 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. All construction-related direct labor and material costs are capitalized. 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 using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. 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.

Management 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. Refer toNote 7 for a description of impairments recorded during the years ended December 31, 2012, 2011 and 2010.

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. 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 a third-party entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership's goodwill balance does not represent, and in some cases is significantly different from, 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. During 2011, the carrying amount of goodwill increased from $82.1 million to $99.5 million, due to the acquisition of the Non-Operated Marcellus Interest. The carrying amount of goodwill is not deductible for tax purposes. During 2012, the carrying amount of goodwill increased from $99.5 million to $105.3 million, attributable to allocated goodwill related to the acquisition of the additional 24% interest in Chipeta (see Note 2), 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 Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. For years 2011 and prior, the first step in the goodwill impairment test was to compare the fair value of each reporting unit to which goodwill had been assigned to the carrying amount of net assets, including goodwill, of the respective reporting unit. For years 2012 and forward, an initial qualitative assessment may be performed prior to proceeding to the first step performed in previous years (described above). If the Partnership concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value through a charge to operating expense based on a hypothetical purchase price allocation. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement. Estimating the fair value of the Partnership's reporting units was not necessary based on the evaluation as of October 1, 2012, and no goodwill impairment has been recognized in these consolidated financial statements.

Intangible assets policy

Other intangible assets.The intangible asset balance in the consolidated balance sheets includes 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. Customer contract intangible assets 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.

In November 2012, Chipeta entered into interconnect agreements with a third party, whereby the third party will construct, own and operate an inlet interconnect to the Chipeta plant and a redelivery interconnect from the Chipeta plant. Chipeta will pay the third party $3.7 million and will be granted access rights to the third-party infrastructure, thereby providing the Partnership with the ability to enter into processing agreements with additional third-party producers. The Partnership's intangible asset balance as of December 31, 2012, includes this payment, which will be amortized on a straight-line basis over the 10-year life of the agreements.

The Partnership assesses intangible assetsfor 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. See Property, plant and equipment within this Note 1 for further discussion of management's process to evaluate potential impairment of long-lived assets. No intangible asset impairment has been recognized in these consolidated financial statements. As of December 31, 2012, the carrying value of the Partnership's intangible assets was $55.5 million, net of $2.0million of accumulated amortization. The Partnership estimates that it will record $1.4 million of intangible asset amortization for each of the next five years. As of December 31, 2011, the carrying value of the Partnership's intangible assets was $52.9 million, net of $0.9 million of accumulated amortization.

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 adjustedto its expected settlement value through accretion expense, which is reported within depreciation, amortization and impairments in the consolidated statements of income. 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 obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations 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 gather, process, compress, treat and transport Anadarko and third-party natural gas, condensate, NGLs and crude oil in the United States.

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 cost-of-service gathering agreements, the Partnership earns fees for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate are sold.The percentage of the product sale paid to the produceris recorded as a related cost of product expense.

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 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. 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 than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price uncertainty that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. See Note 5. 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.

Proceeds from the sale of residue, 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 2,144,947 units remain available for future issuance as of December 31, 2012. 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) the 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 and 2012 Omnibus Incentive Compensation Plans (Anadarko's plans are referred to collectively as the “Anadarko Incentive Plans”). Equity-based compensation granted under the Anadarko Incentive Plans does not impact the Partnership's cash flows from operating activities and is recorded as an adjustment to partners' capital in the consolidated financial statements at the time of contribution. 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. 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. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership's acquisition of these assets from Anadarko.

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 satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2012 or 2011.

With respect to assets acquired from Anadarko, the Partnership recorded Anadarko's historic current and deferred income taxes for the periods prior to the Partnership's ownership of the assets. For periods subsequent to the Partnership's acquisition, the Partnership is not subject to tax except for the Texas margin tax and accordingly, does not record current and deferred federal income taxes related to the assets acquired from Anadarko.

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 partner units and 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.

Capital lease, lessor income policy

Other assets.For the years ended December 31, 2012 and 2011, other assets on the consolidated balance sheets include $0.4 million and $0.7 million, respectively, for a receivable recognized in conjunction with the capital lease component of a processing agreement assumed in connection with the acquisition of Mountain Gas Resources, LLC (“MGR”). See Note 2. The agreement, in which WES 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 consolidated statements of income.

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Transactions With Affiliates (tables)

12 Months Ended

Dec. 31, 2012

Transactions With Affiliates [Abstract]

Commodity Price Swap Agreements Table

	Year Ended December 31,
per barrel except natural gas	2013				2014				2015				2016
Ethane	$	18.32	−	30.10	$	18.36	−	30.53	$	18.41	−	23.41	$	23.11
Propane	$	45.90	−	55.84	$	46.47	−	53.78	$	47.08	−	52.99	$	52.90
Isobutane	$	60.44	−	77.66	$	61.24	−	75.13	$	62.09	−	74.02	$	73.89
Normal butane	$	53.20	−	68.24	$	53.89	−	66.01	$	54.62	−	65.04	$	64.93
Natural gasoline	$	70.89	−	92.23	$	71.85	−	83.04	$	72.88	−	81.82	$	81.68
Condensate	$	74.04	−	85.84	$	75.22	−	83.04	$	76.47	−	81.82	$	81.68
Natural gas (per MMbtu)	$	3.75	−	6.09	$	4.45	−	6.20	$	4.66	−	5.96	$	4.87

Gains (Losses) on Commodity Price Swap Agreements Table

			Year Ended December 31,
thousands			2012		2011		2010
Gains (losses) on commodity price swap agreements
	related to sales: (1)
	Natural gas sales		$	37,665	$	33,845	$	20,200
	Natural gas liquids sales			66,260		(36,802)		2,953
		Total		103,925		(2,957)		23,153
Losses on commodity price swap agreements
	related to purchases (2)			(89,710)		(27,234)		(23,344)
Net gains (losses) on commodity price swap agreements			$	14,215	$	(30,191)	$	(191)

___________________________________________________________________

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

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

LTIP Award Activity Table

		2012			2011			2010
		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	$	33.92	23,978	$	20.19	17,503	$	15.02	21,970
Vested		$	33.20	(14,260)	$	20.51	(15,119)	$	15.02	(19,751)
Granted		$	45.91	15,901	$	35.66	21,594	$	20.94	15,284
Phantom units outstanding
	at end of year	$	41.77	25,619	$	33.92	23,978	$	20.19	17,503

Equipment Purchase and Sale

	Purchases						Sales
	Year Ended December 31,
thousands	2012		2011		2010		2012		2011		2010
Net carrying value	$	8,009	$	1,998	$	429	$	393	$	316	$	2,576
Cash consideration		24,705		3,837		361		760		382		2,805
Partners’ capital adjustment	$	16,696	$	1,839	$	(68)	$	367	$	66	$	229

Summary of Affiliate Transactions Table

		Year Ended December 31,
thousands		2012		2011		2010
Revenues (1)		$	704,137	$	658,680	$	571,628
Cost of product (1)			145,250		83,722		95,667
Operation and maintenance (2)			51,237		51,339		46,379
General and administrative (3)			92,847		33,305		24,137
	Operating expenses		289,334		168,366		166,183
Interest income, net (4)			16,900		24,106		20,243
Interest expense (5)			2,766		4,935		6,924
Distributions to unitholders (6)			98,280		68,039		52,337
Contributions from noncontrolling interest owners (7)			12,588		16,476		2,019
Distributions to noncontrolling interest owners (7)			6,528		9,437		6,476

____________________________________________________________

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

(2)Represents expenses incurred during periods including and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.

(3)Represents general and administrative expense incurred during periods including and subsequent to the date of the Partnership's acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership.These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see Anadarko Incentive Plans and Incentive Plan within this Note 5).

(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 Wattenbergassets 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 aforementioned assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.

(5)Represents interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputedon the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of theBrasada and Lancaster plants. During 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. SeeNote receivable from and amounts payable to Anadarko within thisNote 5.

(6)Represents distributions paid under the partnership agreement.

(7)As described in Note 1and Note 2, the Partnership acquired Anadarko's then remaining 24% membership interest in Chipeta on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.

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Transactions With Affiliates - Summary Table (details) (USD $) In Thousands, unless otherwise specified	3 Months Ended													12 Months Ended
	Dec. 31, 2012		Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	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, 2012		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2012 Affiliated Entity Member		Dec. 31, 2011 Affiliated Entity Member		Dec. 31, 2010 Affiliated Entity Member		Dec. 31, 2012 Affiliated Entity Member Chipeta Processing Limited Liability Company [Member]	Jul. 31, 2009 Affiliated Entity Member Chipeta Processing Limited Liability Company [Member]
Related Party Transaction Line Items
Revenues														$ 910,587	[1]	$ 869,405	[1]	$ 663,274	[1]	$ 704,137	[1],[2]	$ 658,680	[1],[2]	$ 571,628	[1],[2]
Cost of product														336,079	[1],[3]	327,371	[1],[3]	246,476	[1],[3]	145,250	[2]	83,722	[2]	95,667	[2]
Operation and maintenance														140,106	[1],[3]	126,464	[1],[3]	103,887	[1],[3]	51,237	[4]	51,339	[4]	46,379	[4]
General and administrative														99,212	[1],[3]	40,564	[1],[3]	29,970	[1],[3]	92,847	[5]	33,305	[5]	24,137	[5]
Operating expenses														715,693	[1]	624,111	[1]	485,735	[1]	289,334		168,366		166,183
Interest income, net														16,900	[1],[6]	24,106	[1],[6]	20,243	[1],[6]
Interest expense														42,060	[1],[7]	30,345	[1],[7]	18,794	[1],[7]	2,766	[8]	4,935	[8]	6,924	[8]
Distributions to unitholders	65,657	[9]	56,346	52,425	46,053	43,027	40,323	36,063	33,168	30,564	26,381	24,378	22,042							98,280	[10]	68,039	[10]	52,337	[10]
Contributions from noncontrolling interest owners														29,108		33,637		2,053		12,588	[11]	16,476	[11]	2,019	[11]
Distributions to noncontrolling interest owners														$ 17,303		$ 17,478		$ 13,222		$ 6,528	[11]	$ 9,437	[11]	$ 6,476	[11]
Table Text Block Supplement Abstract
Ownership interest by noncontrolling owners																										24.00%	24.00%

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

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

[3] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $145.3 million, $83.7 million and $95.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Operation and maintenance includes charges from Anadarko of $51.2 million, $51.3 million and $46.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. General and administrative includes charges from Anadarko of $92.8 million, $33.3 million and $24.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 5.

[4] Represents expenses incurred during periods including and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.

[5] Represents general and administrative expense incurred during periods including and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see Anadarko Incentive Plans and Incentive Plan within this Note 5).

[6] 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 aforementioned assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.

[7] Includes affiliate (as defined in Note 1) interest expense of $2.8 million, $4.9 million and $6.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 10.

[8] Represents interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. During 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note receivable from and amounts payable to Anadarko within this Note 5.

[9] On January 21, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

[10] Represents distributions paid under the partnership agreement.

[11] As described in Note 1 and Note 2, the Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.

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Equity and Partners' Capital - Equity Offerings Table (details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended										12 Months Ended
	Jun. 30, 2012		Sep. 30, 2011		Mar. 31, 2011		Nov. 30, 2010		May 31, 2010		Dec. 31, 2012
Capital Unit [Line Items]
Price per unit	43.88		35.86		35.15		29.92		22.25	[1]
Underwriting discount and other offering expenses	7,468		7,655		5,621		10,325		4,427	[1]
Net proceeds	216,409		202,748		132,569		246,729		99,074	[1]
Common [Member]
Capital Unit [Line Items]
Units Issued	5,000,000	[2]	5,750,000	[2]	3,852,813	[2]	8,415,000	[2]	4,558,700	[1],[2]
Common [Member] | Option On Securities Member
Capital Unit [Line Items]
Units Issued			750,000		302,813		915,000		558,700
General Partner Member
Capital Unit [Line Items]
Units Issued	102,041	[3]	117,347	[3]	78,629	[3]	171,734	[3]	93,035	[1],[3]
Table Text Block Supplement Abstract
General partner's interest											2.00%

[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 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 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% general partner interest

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Consolidated Balance Sheet (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
GP units issued	2,135,930		1,839,613
General partner units outstanding	2,135,930		1,839,613
Accounts receivable, net	$ 50,233	[1],[2]	$ 90,328	[1],[2]
Other current assets	6,998	[1],[3]	7,186	[1],[3]
Accounts and natural gas imbalance payables	25,154	[1],[4]	26,600	[1],[4]
Accrued liabilities	147,651	[1],[5]	92,037	[1],[5]
Affiliated Entity Member
Accounts receivable, net	19,100
Other current assets	400		500
Accounts and natural gas imbalance payables	2,500		5,900
Accrued liabilities	$ 100		$ 300
Common [Member]
Common units issued	104,660,553		90,140,999
Units outstanding	104,660,553		90,140,999

[1] Financial information has been recast to include the financial position and results attributable to the Non-Operated Marcellus Interest. See Note 2.

[2] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $19.1 million and zero as of December 31, 2012 and 2011, respectively.

[3] Other current assets includes natural gas imbalance receivables from affiliates of $0.4 million and $0.5 million as of December 31, 2012 and 2011, respectively.

[4] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.5 million and $5.9 million as of December 31, 2012 and 2011, respectively.

[5] Accrued liabilities include amounts payable to affiliates of $0.1 million and $0.3 million as of December 31, 2012 and 2011, respectively.

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Acquisitions

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Acquisitions

The following table presents the acquisitions completed by the Partnership during the years endedDecember 31, 2012, 2011 and 2010, andidentifies the funding sources for such acquisitions:

thousands except unit and		Acquisition	Percentage			Cash		Common	GP Units
	percent amounts	Date	Acquired	Borrowings		On Hand		Units Issued	Issued
Granger (1)		01/29/10	100%	$	210,000	$	31,680	620,689	12,667
Wattenberg (2)		08/02/10	100%		450,000		23,100	1,048,196	21,392
White Cliffs (3)		09/28/10	10%		—		38,047	—	—
Platte Valley (4)		02/28/11	100%		303,000		602	—	—
Bison (5)		07/08/11	100%		—		25,000	2,950,284	60,210
MGR (6)		01/13/12	100%		299,000		159,587	632,783	12,914
Chipeta (7)		08/01/12	24%		—		128,250	151,235	3,086

____________________________________________________________

(1)       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.”

(2)       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.”

(3)       White Cliffs owns a crude oil pipeline thatoriginates in Platteville, Colorado and terminates in Cushing, Oklahoma. 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.”

(4)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.”

(5)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.The Bison assets were placed in service in June 2010.

(6)The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a 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.”

(7)The Partnership acquired Anadarko's then remaining 24% membership interest in Chipeta (as described in Note 1), with the Partnership receiving distributions related to the additional interest beginning July 1, 2012. This transaction brought the Partnership's total membership interest in Chipeta to 75%. The remaining 25% membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented.

Non-Operated Marcellus Interest acquisition. On March 1, 2013, the Partnership acquired a 33.75% interest in both the Liberty and Rome gas gathering systems from Anadarko Marcellus Midstream, L.L.C. (“AMM”), a wholly owned subsidiary of Anadarko. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” Consideration paid includes $465.5 million in cash and 449,129 common units of the Partnership. The Partnership funded the cash consideration through $250.0 million in borrowings under its revolving credit facility and $215.5 million of cash on hand.

Anadarko and a third party entered into a 50/50 Joint Exploration Agreement, dated September 1, 2006, covering counties in north-central Pennsylvania within an Area of Mutual Interest that the parties designated as “Area A.” Initial construction of the midstream assets within Area A began in May 2008, and in December 2011, following various sales of interests, AMM and three third-party owners (the “system owners”) entered into a Construction, Ownership and Operation agreement (the “COO Agreement”) to jointly own and develop the midstream assets in Area A (the “AMI Assets”). As of December 31, 2012, four parties, including AMM, were owners of the AMI Assets.

The AMI Assets consist of the Liberty Gas Gathering System (the “Liberty GGS”) and the Rome Gas Gathering System (the “Rome GGS”). Both systems gather gas from the third-party system owners, Anadarko, and other third parties producing in the area.

The gas gathering agreements for the AMI Assets provide for gathering and compression rates (either fixed or based on a cost-of-service model, depending on the agreement) and have various expiration dates through 2027. The gathering and compression rates for the anchor shippers (as defined in the COO Agreement) are based on a cost-of-service model, which is reviewed on an annual basis, and the gathering fee is adjusted accordingly.

Due to Anadarko's control of the Partnership through its ownership and control of WGP, the acquisition of the Non-Operated Marcellus Interest is considered a transfer of net assets under common control. As such, the Partnership's historical financial statements previously filed with the SEC have been recast in this Current Report on Form 8-K to include the results attributable to the Non-Operated Marcellus Interest as of May 2008, when construction began on the Liberty GGS and Rome GGS. The consolidated financial statements for periods prior to the Partnership's acquisition of the Partnership assets from Anadarko 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 Non-Operated Marcellus Interest during the periods reported.

The following tables present the impact to the historical consolidated statements of income attributable to the Non-Operated Marcellus Interest:

	Year Ended December 31, 2012
	Partnership		Non-Operated
thousands	Historical		Marcellus Interest		Combined
Revenues	$	849,440	$	61,147	$	910,587
Net income		121,876		27,435		149,311
	Year Ended December 31, 2011
	Partnership		Non-Operated
thousands	Historical		Marcellus Interest		Combined
Revenues	$	823,265	$	46,140	$	869,405
Net income		188,346		18,515		206,861
	Year Ended December 31, 2010
	Partnership		Non-Operated
thousands	Historical		Marcellus Interest		Combined
Revenues	$	663,274	$	-	$	663,274
Net income (loss)		157,197		(264)		156,933

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Asset Retirement Obligations (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Roll Forward Analysis [Roll Forward]
Carrying amount of asset retirement obligations at beginning of year	$ 64,345	$ 45,269
Liabilities incurred	9,414	15,462
Liabilities settled	(786)	(133)
Accretion expense	4,270	3,791
Revisions in estimated liabilities	(10,520)	(44)
Carrying amount of asset retirement obligations at end of year	$ 66,723	$ 64,345

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Income Taxes (tables)

12 Months Ended

Dec. 31, 2012

Income Tax Expense Benefit Abstract

ScheduleOfComponentsOfIncomeTaxExpenseBenefitTableTextBlock

		Year Ended December 31,
thousands		2012		2011		2010
Current income tax expense (benefit)
	Federal income tax expense (benefit)	$	(7,555)	$	15,248	$	10,476
	State income tax expense (benefit)		(1,843)		322		1,502
	Total current income tax expense (benefit)		(9,398)		15,570		11,978
Deferred income tax expense (benefit)
	Federal income tax expense		22,328		13,075		9,673
	State income tax expense (benefit)		7,785		3,505		(134)
	Total deferred income tax expense		30,113		16,580		9,539
Total income tax expense		$	20,715	$	32,150	$	21,517

ScheduleOfEffectiveIncomeTaxRateReconciliationTableTextBlock

		Year Ended December 31,
thousands except percentages		2012		2011		2010
Income before income taxes		$	170,026	$	239,011	$	178,450
Statutory tax rate			0%		0%		0%
Tax computed at statutory rate		$	—	$	—	$	—
Adjustments resulting from:
	Federal taxes on income attributable to Partnership assets pre-acquisition		17,251		29,502		20,534
	State taxes on income attributable to Partnership assets pre-acquisition
	(net of federal benefit)		2,206		1,984		683
	Texas margin tax expense (benefit)		1,258		664		300
Income tax expense		$	20,715	$	32,150	$	21,517
Effective tax rate			12%		13%		12%

ScheduleOfDeferredTaxAssetsAndLiabilitiesTableTextBlock

	December 31,
thousands	2012		2011
Credit carryforwards	$	14	$	14
Net current deferred income tax assets		14		14
Depreciable property		(47,558)		(99,733)
Partnership basis		—		(24,481)
Credit carryforwards		541		556
Other		(136)		114
Net long-term deferred income tax liabilities		(47,153)		(123,544)
Total net deferred income tax liabilities	$	(47,139)	$	(123,530)

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Partnership Distributions - Cash Distributions Table (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	1 Months Ended	3 Months Ended
	May 31, 2008	Dec. 31, 2012		Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010
Distributions Made to Members or Limited Partners [Abstract]
Total Quarterly Distribution per Unit	$ 0.300	$ 0.520	[1]	$ 0.500	$ 0.480	$ 0.460	$ 0.440	$ 0.420	$ 0.405	$ 0.390	$ 0.380	$ 0.370	$ 0.350	$ 0.340
Total Cash Distribution		$ 65,657	[1]	$ 56,346	$ 52,425	$ 46,053	$ 43,027	$ 40,323	$ 36,063	$ 33,168	$ 30,564	$ 26,381	$ 24,378	$ 22,042

[1] On January 21, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

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Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

Refer to Note 2 for a description of the Non-Operated Marcellus Interest acquisition on March 1, 2013. In addition, on March 8, 2013, the Partnership acquired a 33.75% (Anadarko-operated) interest in each of the Larry's Creek, Seely and Warrensville gas gathering systems from a third party for total consideration of $134.9 million, of which $133.5 million was financed with borrowings on the Partnership's RCF. The assets in both the aforementioned acquisitions serve production from the Marcellus shale in north-central Pennsylvania.