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): August 27, 2014

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 3, 2014, Western Gas Partners, LP (the “Partnership”) acquired a 20% interest in Texas Express Pipeline LLC and Texas Express Gathering LLC, and a 33.33% interest in Front Range Pipeline LLC, pursuant to the terms and conditions of a Contribution Agreement, dated February 27, 2014, among WGR Asset Holding Company, LLC and APC Midstream Holdings, LLC, and the Partnership, Western Gas Operating, LLC and WGR Operating, LP and, for certain limited purposes, Anadarko Petroleum Corporation (“Anadarko”). The interests acquired are referred to as the “TEFR Interests” and the acquisition as the “TEFR Interests acquisition.” The consideration paid by the Partnership for the TEFR Interests consisted of $356.3 million in cash and 308,490 common units of the Partnership.

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 TEFR Interests 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 TEFR Interests 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 TEFR Interests as if the Partnership owned the TEFR Interests from 2011 when Anadarko made its initial investment in the respective businesses.

The Partnership’s Form 10-K for the year ended December 31, 2013 (the “2013 Form 10-K”), as filed with the U.S. Securities and Exchange Commission (the “SEC”) on February 28, 2014, 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 2013 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 2013 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 2013 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 2013 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 107 and 108 of the 2013 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 2013 Form 10-K other than the revisions noted above. This Current Report on Form 8-K should be read in conjunction with the 2013 Form 10-K, and any references herein to Items 6, 7 and 8 under Part II of the 2013 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 Forms 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:	August 27, 2014	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

EX-12.1

EXHIBIT 12.1

WESTERN GAS PARTNERS, LP

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
thousands	2013		2012		2011		2010		2009
Earnings:
Income before income taxes	$	287,798	$	169,957	$	239,011	$	178,450	$	148,520
Add:
Fixed charges	63,903		48,422		30,993		19,292		10,992
Distributions from equity investees	22,136		20,660		15,999		10,973		11,206
Amortization of capitalized interest	814		479		294		256		182
Less:
Equity income	22,948		16,042		11,261		7,628		7,923
Capitalized interest	11,945		6,196		420		—		—
Net income before taxes attributable to noncontrolling interests	10,816		14,890		14,103		11,005		10,260
Earnings	$	328,942	$	202,390	$	260,513	$	190,338	$	152,717
Fixed charges:
Interest expense, including capitalized interest	$	63,742	$	48,256	$	30,765	$	18,794	$	9,955
Interest component of rent expense	161		166		228		498		1,037
Fixed charges	$	63,903	$	48,422	$	30,993	$	19,292	$	10,992
Ratio of earnings to fixed charges	5.1x		4.2x		8.4x		9.9x		13.9x

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. 333-193828) and Form S-8 (No. 333-151317) of Western Gas Partners, LP of our report dated August 27, 2014, with respect to the consolidated balance sheets of Western Gas Partners, LP and subsidiaries as of December 31, 2013 and 2012, 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, 2013, which report appears in the Current Report on Form 8-K of Western Gas Partners, LP and subsidiaries dated August 27, 2014.

/s/ KPMG LLP

Houston, Texas

August 27, 2014

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 subsidiaries, excluding us and our general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding us, and includes equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “Equity investment throughput” refers to our 14.81% share of average Fort Union throughput and our 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEP and TEG throughput and our 33.33% share of average FRP throughput.

References to the “Partnership assets” refer collectively to the assets we owned and our interests accounted for under the equity method as of December 31, 2013, including the TEFR Interests. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of Partnership 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 Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of the Partnership assets as of the date of common control. For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of Partnership assets from Anadarko, including the TEFR Interests, 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 Partnership 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, concurrently with the closing of our initial public offering (“IPO”), 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. In July 2009, we closed on the acquisition of a 51% membership interest in Chipeta Processing LLC (“Chipeta”) from Anadarko. We closed 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, which consisted of a 9.6% third-party interest, and a 0.4% interest from Anadarko. 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 Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities (collectively, 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 a wholly owned subsidiary of Anadarko, Anadarko Marcellus Midstream, L.L.C. (the “Non-Operated Marcellus Interest”). Also in March 2013, we completed the acquisition of a 33.75% interest in the Larry’s Creek, Seely and Warrensville gas gathering systems from a third party (the “Anadarko-Operated Marcellus Interest”). In June 2013, we acquired a 25% interest in the Mont Belvieu JV from a third party, and in September 2013 we acquired Overland Trail Transmission, LLC, (“OTTCO”) from a third party. In March 2014, we acquired the TEFR Interests from Anadarko.

Dates of common control

In connection with its August 23, 2006, acquisition of Western Gas Resources, Inc., 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. 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 for all periods presented, (ii) the consolidated financial results and operations of Western Gas Partners, LP and its subsidiaries combined with the financial results and operations of MIGC, the Powder River assets, the Granger assets, the MGR assets, the Chipeta assets, the Wattenberg assets, the 0.4% interest in White Cliffs, and the Non-Operated Marcellus Interest, for all periods presented, (iii) 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 (iv) the financial results and operations of the TEFR Interests from 2011 when Anadarko made its initial investment in the respective businesses. Effective August 1, 2012, noncontrolling interests exclude the financial results and operations of the additional Chipeta interest.

2

The information in the following table should be read together with the information in the captions How we Evaluate our Operations, Items Affecting the Comparability of our Financial Results, Results of Operations, and Key Performance Metrics under Item 7 of Exhibit 99.2 to this Current Report on Form 8-K:

thousands except per-unit data, throughput, Adjusted	Summary Financial Information
gross margin per Mcf and Adjusted gross margin per Bbl	2013(1)			2012 (1)			2011 (1)			2010			2009
Statement of Income Data (for the year ended):
Total revenues	$	1,029,763		$	894,476		$	858,144		$	655,646		$	611,841
Operating income	320,858			194,825			245,294			177,539			136,130
Net income	285,443			149,267			206,861			156,933			126,417
Net income attributable to noncontrolling interests	10,816			14,890			14,103			11,005			10,260
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758		$	145,928		$	116,157
General partner interest in net income (2)	69,633			28,089			8,599			3,067			1,428
Limited partners’ interest in net income (2)	200,866			78,897			131,560			111,064			69,980
Net income per common unit (basic and diluted) (2)	$	1.83		$	0.84		$	1.64		$	1.66		$	1.25
Net income per subordinated unit (basic and diluted) (2)	$	—		$	—		$	1.28		$	1.61		$	1.24
Distributions per unit	$	2.280		$	1.960		$	1.655		$	1.440		$	1.260
Balance Sheet Data (at period end):
Total assets	$	4,617,808		$	3,863,558		$	2,997,689		$	2,345,255		$	2,278,512
Total long-term liabilities	1,535,312			1,284,176			860,092			649,414			568,331
Total equity and partners’ capital	$	2,892,036		$	2,394,076		$	2,010,279		$	1,613,311		$	1,627,818
Cash Flow Data (for the year ended):
Net cash flows provided by (used in):
Operating activities	$	448,201		$	338,047		$	312,838		$	252,898		$	209,345
Investing activities	(1,652,995		)	(1,357,537		)	(485,832		)	(921,398		)	(223,128		)
Financing activities	885,541			1,212,912			372,479			625,590			47,694
Capital expenditures	$	(645,854	)	$	(638,121	)	$	(149,717	)	$	(173,891	)	$	(121,295	)
Throughput (MMcf/d except throughput measured in barrels):
Total throughput for natural gas assets	3,368			3,023			2,715			2,224			2,262
Throughput attributable to noncontrolling interests for natural gas assets	168			228			242			197			180
Throughput attributable to Western Gas Partners, LP for natural gas assets (3)	3,200			2,795			2,473			2,027			2,082
Throughput (MBbls/d) for crude/NGL assets (4)	40			31			28			17			11
Key Performance Metrics (for the year ended):
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (5)	$	654,924		$	544,853		$	516,038		$	398,676		$	365,930
Adjusted gross margin for crude/NGL assets (6)	15,274			13,221			9,497			3,503			1,245
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets (7)	0.56			0.53			0.57			0.54			0.48
Adjusted gross margin per Bbl for crude/NGL assets (8)	1.05			1.17			0.94			0.57			0.31
Adjusted EBITDA attributable to Western Gas Partners, LP (9)	457,773			377,929			361,653			264,694			223,635
Distributable cash flow (9)	$	380,529		$	309,945		$	319,294		$	237,372		$	203,245

3

⁽¹⁾  Information has been recast to include the financial position, results and throughput attributable to the TEFR Interests. 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.

⁽²⁾  Net income earned on and subsequent to the date of our acquisitions of 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.

⁽³⁾  Includes affiliate, third-party and equity investment throughput (defined as our 14.81% share of average Fort Union and our 22% share of average Rendezvous throughput), excluding the noncontrolling interest owners’ proportionate share of throughput.

⁽⁴⁾  Represents total throughput measured in barrels consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput.

⁽⁵⁾  Calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product.

⁽⁶⁾  Calculated as total revenues for crude/NGL assets less cost of product for crude/NGL assets plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, TEG, TEP, and FRP, which are measured in barrels.

⁽⁷⁾  Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets divided by total throughput attributable to Western Gas Partners, LP for natural gas assets.

⁽⁸⁾  Average for period. Calculated as Adjusted gross margin for crude/NGL assets, divided by total throughput (MBbls/d) for crude/NGL assets.

⁽⁹⁾  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

EX-99.2

EXHIBIT 99.2

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

Western Gas Partners, LP is a growth-oriented master limited partnership (“MLP”) formed by Anadarko Petroleum Corporation in 2007. For purposes of this report, “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 subsidiaries, excluding us and our general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding us, and includes equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “Equity investment throughput” refers to our 14.81% share of average Fort Union throughput and our 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEP and TEG throughput and our 33.33% share of average FRP throughput.

References to the “Partnership assets” refer collectively to the assets we owned and our interests accounted for under the equity method as of December 31, 2013, including the TEFR Interests. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of Partnership 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 Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Further, after an acquisition of Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of the Partnership 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 TEFR Interests, 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 Partnership 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.

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and notes to consolidated financial statements, which are included in Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

EXECUTIVE SUMMARY

We are a growth-oriented MLP formed by Anadarko to own, operate, acquire and develop midstream energy assets. We currently have investments in or own assets located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), north-central Pennsylvania, and Texas, 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, 2013, our assets and investments accounted for under the equity method, including the TEFR Interests, consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	13	1	5	2
NGL gathering systems	—	—	—	2
Natural gas treating facilities	8	—	—	1
Natural gas processing facilities	8	3	—	2
NGL pipelines	3	—	—	2
Natural gas pipelines	3	—	—	—
Oil pipeline	—	—	—	1

See alsoNote 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 and operational highlights during the year ended December 31, 2013 included the following:

• We issued $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018. Net proceeds were used to repay amounts then outstanding under our revolving credit facility. See Liquidity and Capital Resources within this Item 7 for additional information.

• We completed construction and commenced operations in June 2013 of the 200 MMcf/d Brasada processing and stabilization facility in the Eagleford shale area of South Texas.

• We announced a project to expand the processing capacity at our Lancaster plant by another 300 MMcf/d with a second cryogenic processing train. The expansion project is currently under construction.

• We completed the following acquisitions: (i) Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems in north-central Pennsylvania, (ii) a third party’s 33.75% interest (operated by Anadarko) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, also in north-central Pennsylvania, (iii) a 25% interest in the Mont Belvieu JV, an entity formed to design, construct and own two NGL fractionation trains located in Mont Belvieu, Texas, and (iv) Overland Trail Transmission, LLC, which owns and operates a natural gas pipeline connecting our Red Desert and Granger complexes in southwestern Wyoming. See Acquisitions under Items 1 and 2 of our 2013 Form 10-K for additional information.

• We issued 12,200,735 common units to the public, generating net proceeds of $740.3 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds were used to repay a portion of the amount outstanding under our revolving credit facility, with the remaining net proceeds used for general partnership purposes, including the funding of capital expenditures.

• We raised our distribution to $0.60 per unit for the fourth quarter of 2013, representing a 3%increase over the distribution for the third quarter of 2013, a 15%increase over the distribution for the fourth quarter of 2012, and our nineteenth consecutive quarterly increase.

Significant operational highlights during the year ended December 31, 2013 included the following:

• Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,200 MMcf/d for the year ended December 31, 2013, representing a 14%increase compared to the year ended December 31, 2012.

• Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $0.56 per Mcf for the year ended December 31, 2013, representing a 6%increase compared to the year ended December 31, 2012.

2

OUR OPERATIONS

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, 2013, 78% of our total revenues and 57% of our throughput (excluding equity investment throughput and throughput measured in barrels) 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, 2013, 74% of our gross margin was attributable 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, Rendezvous, the Mont Belvieu JV and the TEFR Interests.

For the year ended December 31, 2013, 26% 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, 2013, 99% 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 2013 Form 10-K.

As a result of our initial public offering (“IPO”) and subsequent acquisitions from Anadarko and third parties, our results of operations, financial position and cash flows may vary significantly for 2013, 2012 and 2011 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) operating and maintenance expenses, (3) general and administrative expenses, (4) Adjusted gross margin (as defined below), (5) Adjusted EBITDA (as defined below) and (6) Distributable cash flow (as defined below).

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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, 2013, excluding the acquisition of the TEFR Interests, we added 273 receipt points to our systems.

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. Operating 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 the date of and subsequent to our acquisition of the Partnership assets, certain of these expenses are incurred under and governed by our services and secondment agreement with Anadarko.

General and administrative expenses. To help ensure the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses through comparison to prior periods, to the annual budget approved by our general partner’s board of directors, as well as to general and administrative expenses incurred by similar midstream companies. General and administrative expenses for periods prior to our acquisition of the Partnership assets include 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 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.

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Non-GAAP financial measures

Adjusted gross margin attributable to Western Gas Partners, LP.We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues less cost of product, plus distributions from equity investees and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product. We believe Adjusted gross margin is an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in our industry. 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.

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets and Adjusted gross margin per Bbl for crude/NGL assets. See Key Performance Metrics within this Item 7.

Adjusted EBITDA attributable to Western Gas Partners, LP. We define Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) as net income attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, 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.

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.

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.

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Reconciliation to GAAP measures. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in generally accepted accounting principles in the United States (“GAAP”). The GAAP measure used by us that is most directly comparable to Adjusted gross margin is operating income, while net income attributable to Western Gas Partners, LP and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA. The GAAP measure used by us that is most directly comparable to Distributable cash flow is net income attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow should not be considered as alternatives to the GAAP measures of operating income, net income attributable to Western Gas Partners, LP, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income, net income and net cash provided by operating activities. Adjusted gross margin, 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 gross margin, 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 gross margin, Adjusted EBITDA and Distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA and Distributable cash flow compared to (as applicable) operating income, net income and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.

The following tables present (a) a reconciliation of the non-GAAP financial measure of Adjusted gross margin to the GAAP financial measure of operating income, (b) 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 (c) 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	2013		2012		2011
Reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to Operating income
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets	$	654,924	$	544,853	$	516,038
Adjusted gross margin for crude/NGL assets	15,274		13,221		9,497
Adjusted gross margin attributable to Western Gas Partners, LP	$	670,198	$	558,074	$	525,535
Adjusted gross margin attributable to noncontrolling interest	17,416		20,983		21,237
Equity income, net	22,948		16,042		11,261
Less:
Distributions from equity investees	22,136		20,660		15,999
Operation and maintenance	168,657		140,106		126,464
General and administrative	29,751		99,212		40,564
Property and other taxes	23,244		19,688		16,579
Depreciation, amortization and impairments	145,916		120,608		113,133
Operating income	$	320,858	$	194,825	$	245,294

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	Year Ended December 31,
thousands	2013			2012			2011
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	457,773		$	377,929		$	361,653
Less:
Distributions from equity investees	22,136			20,660			15,999
Non-cash equity-based compensation expense (1)	3,575			73,508			13,754
Interest expense	51,797			42,060			30,345
Income tax expense	4,219			20,690			32,150
Depreciation, amortization and impairments (2)	143,375			118,279			110,380
Other expense (2)	175			1,665			3,683
Add:
Equity income, net	22,948			16,042			11,261
Interest income, net – affiliates	16,900			16,900			24,106
Other income (2) (3)	419			368			2,049
Income tax benefit	1,864			—			—
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	457,773		$	377,929		$	361,653
Adjusted EBITDA attributable to noncontrolling interests	13,348			17,214			16,850
Interest income (expense), net	(34,897		)	(25,160		)	(6,239		)
Non-cash equity-based compensation expense (1)	(54		)	(69,791		)	(10,264		)
Debt-related amortization and other items, net	2,449			2,319			3,110
Current income tax benefit (expense)	29,536			9,419			(15,570		)
Other income (expense), net (3)	253			(1,292		)	(1,628		)
Distributions from equity investments in excess of cumulative earnings	(4,438		)	—			—
Changes in operating working capital:
Accounts receivable, net	(34,019		)	22,916			(44,725		)
Accounts and natural gas imbalance payables and accrued liabilities, net	21,952			5,045			30,884
Other	(3,702		)	(552		)	(21,233		)
Net cash provided by operating activities	$	448,201		$	338,047		$	312,838
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	448,201		$	338,047		$	312,838
Net cash used in investing activities	$	(1,652,995	)	$	(1,357,537	)	$	(485,832	)
Net cash provided by financing activities	$	885,541		$	1,212,912		$	372,479

⁽¹⁾  For the year ended December 31, 2012, includes $69.8 million of equity-based compensation associated with the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (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.

⁽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. 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.

⁽³⁾  Excludes income of $1.6 million for each of the years ended December 31, 2013, 2012 and 2011, related to a component of a gas processing agreement accounted for as a capital lease.

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	Year Ended December 31,
thousands except Coverage ratio	2013			2012		2011
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	380,529		$	309,945	$	319,294
Less:
Distributions from equity investees	22,136			20,660		15,999
Non-cash equity-based compensation expense (1)	3,575			73,508		13,754
Interest expense, net (non-cash settled)	—			326		—
Income tax expense	2,355			20,690		32,150
Depreciation, amortization and impairments (2)	143,375			118,279		110,380
Other expense (2)	175			1,665		3,683
Add:
Equity income, net	22,948			16,042		11,261
Cash paid for maintenance capital expenditures (2) (3)	29,850			36,459		28,304
Capitalized interest	11,945			6,196		420
Cash paid for income taxes	552			495		190
Other income (2) (4)	419			368		2,049
Interest income, net (non-cash settled)	—			—		7,206
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377	$	192,758
Distributions declared (5)
Limited partners	$	255,308
General partner	70,745
Total	$	326,053
Coverage ratio	1.17		x

⁽¹⁾  For the year ended December 31, 2012, 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.

⁽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. 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.

⁽³⁾  Net of a prior period adjustment reclassifying $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, 2013, 2012 and 2011, 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 $2.28 per unit declared for the year ended December 31, 2013.

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ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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

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.

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 2013, we extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2014. 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, on 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. The amounts reimbursed under the omnibus agreement are greater than amounts allocated to us by Anadarko for the aggregate management services fees, and are reflected in our historical consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko. Public company expenses include expenses such as external audit and consulting fees.

The following table summarizes the amounts the Partnership reimbursed to Anadarko:

	Year Ended December 31,
thousands	2013		2012		2011
General and administrative expenses	$	16,882	$	14,904	$	11,754
Public company expenses	7,152		6,830		7,735
Total reimbursement	$	24,034	$	21,734	$	19,489

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.

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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 from Anadarko, 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.

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 $800.0 million senior unsecured revolving credit facility (“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. On August 1, 2012, we acquired Anadarko’s then-remaining 24% membership interest in Chipeta (the “additional Chipeta interest”), 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 the additional Chipeta interest was accounted for on a prospective basis. As such, effective on the date of acquisition, 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 interest 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 Construction, Ownership and Operation 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 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.

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GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends and uncertainties. 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.

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.

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Impact of interest rates. Interest rates were at or near historic lows at certain times during 2013. 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, 2013, Anadarko’s total domestic midstream asset portfolio, excluding the assets we own, consisted of 16 gathering systems, 6,259 miles of pipeline and 10 processing and/or treating facilities. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time.

As of December 31, 2013, WGP held a 41.2% limited partner interest in us, and through its ownership of our general partner, WGP indirectly held a 2.0% general partner interest in us and 100% of our incentive distribution rights. As of December 31, 2013, Anadarko Marcellus Midstream, L.L.C. (“AMM”), a subsidiary of Anadarko, separately held a 0.4% limited partner interest in us. 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.

Other. There is uncertainty related to the ultimate outcome of the Tronox Adversary Proceeding (as defined and described in Note 17—Contingencies—Tronox Litigation in the Notes to the Consolidated Financial Statements under Item 8 of Anadarko’s Form 10-K for the year ended December 31, 2013, which is not, and shall not be deemed to be, incorporated by reference herein), and such outcome’s ultimate impact on Anadarko and us.

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RESULTS OF OPERATIONS

OPERATING RESULTS

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

	Year Ended December 31,
thousands	2013			2012			2011
Gathering, processing and transportation of natural gas and natural gas liquids	$	482,542		$	382,330		$	347,469
Natural gas, natural gas liquids and condensate sales	541,244			508,339			502,383
Other, net	5,977			3,807			8,292
Total revenues(1)	1,029,763			894,476			858,144
Equity income, net	22,948			16,042			11,261
Total operating expenses(1)	731,853			715,693			624,111
Operating income	320,858			194,825			245,294
Interest income, net – affiliates	16,900			16,900			24,106
Interest expense	(51,797		)	(42,060		)	(30,345		)
Other income (expense), net	1,837			292			(44		)
Income before income taxes	287,798			169,957			239,011
Income tax expense	2,355			20,690			32,150
Net income	285,443			149,267			206,861
Net income attributable to noncontrolling interests	10,816			14,890			14,103
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Key performance metrics(2)
Adjusted gross margin attributable to Western Gas Partners, LP	$	670,198		$	558,074		$	525,535
Adjusted EBITDA attributable to Western Gas Partners, LP	$	457,773		$	377,929		$	361,653
Distributable cash flow	$	380,529		$	309,945		$	319,294

⁽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⁾  Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are defined under the caption How We Evaluate Our Operations—Non-GAAP financial measures within this Item 7. For reconciliations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation to GAAP Measures within this Item 7.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2013” refer to the comparison of the year ended December 31, 2013, to the year ended December 31, 2012, and 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.

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Throughput

	Year Ended December 31,
MMcf/d (except throughput measured in barrels)	2013	2012	Inc/ (Dec)		2011	Inc/ (Dec)
Throughput for natural gas assets
Gathering, treating and transportation	1,803	1,601	13	%	1,555	3	%
Processing	1,359	1,187	14	%	962	23	%
Equity investment (1)	206	235	(12	)%	198	19	%
Total throughput for natural gas assets	3,368	3,023	11	%	2,715	11	%
Throughput attributable to noncontrolling interests for natural gas assets	168	228	(26	)%	242	(6	)%
Total throughput attributable to Western Gas Partners, LP for natural gas assets(2)	3,200	2,795	14	%	2,473	13	%
Total throughput (MBbls/d) for crude/NGL assets(3)	40	31	29	%	28	11	%

⁽¹⁾  Represents our 14.81% share of average Fort Union and our 22% share of average Rendezvous throughput. Excludes equity investment throughput measured in barrels (captured in “Total throughput (MBbls/d) for crude/NGL assets” as noted below).

⁽²⁾  Includes affiliate, third-party and equity investment throughput (as equity investment throughput is defined in the above footnote), excluding the noncontrolling interest owners’ proportionate share of throughput.

⁽³⁾  Represents total throughput measured in barrels consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput.

Gathering, treating and transportation throughput increased by 202 MMcf/d for the year ended December 31, 2013, due to increased volumes at the Non-Operated Marcellus Interest and additional throughput from the Anadarko-Operated Marcellus Interest beginning in March 2013. These increases were partially offset by decreases at the Bison facility resulting from reduced drilling activity in the area and at MIGC due to the expiration of a firm transportation agreement effective September 2012.

Gathering, treating and transportation throughput increased by 46 MMcf/d for the year ended December 31, 2012, primarily due to increased volumes at 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.

Processing throughput increased by 172 MMcf/d for the year ended December 31, 2013, primarily due to throughput increases at Chipeta, the start-up of the Brasada facility in June 2013, and an increase in volumes at the Red Desert complex due to additional well connections during the period. In addition, increased volumes processed at a plant included in the MGR acquisition (“the Granger straddle plant”) contributed to the increase. These increases were partially offset by a decrease in throughput at the Granger complex due to natural production declines in the area.

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

Equity investment volumes decreased by 29 MMcf/d for the year ended December 31, 2013, primarily due to lower throughput at the Fort Union system due to production declines in the area. 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.

Throughput for crude/NGL assets measured in barrels increased by 9 MBbls/d for the year ended December 31, 2013, primarily due to the start-up of the Mont Belvieu JV fractionation trains, TEP and TEG in the fourth quarter of 2013. Throughput for crude/NGL assets measured in barrels increased by 3 MBbls/d for the year ended December 31, 2012, primarily due to an increase in volumes at White Cliffs.

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Natural Gas Gathering, Processing and Transportation Revenues

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Gathering, processing and transportation of natural gas and natural gas liquids	$	482,542	$	382,330	26	%	$	347,469	10	%

Revenues from gathering, processing and transportation of natural gas and natural gas liquids increased by $100.2 million for the year ended December 31, 2013, primarily due to increases of $30.5 million, $20.8 million, and $15.3 million at the Non-Operated Marcellus Interest, the Wattenberg system, and Chipeta, respectively, all due to higher throughput, an increase of $14.1 million due to the addition of the Anadarko-Operated Marcellus Interest beginning in March 2013, and an increase of $16.3 million due to the start-up of the Brasada facility in June 2013.

Revenues from gathering, processing and transportation of natural gas and natural gas liquids 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.

Natural Gas, Natural Gas Liquids and Condensate Sales

	Year Ended December 31,
thousands except percentages and per-unit amounts	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Natural gas sales	$	118,134	$	101,116	17	%	$	129,939	(22	)%
Natural gas liquids sales	391,608		377,377		4	%	345,375		9	%
Drip condensate sales	31,502		29,846		6	%	27,069		10	%
Total	$	541,244	$	508,339	6	%	$	502,383	1	%
Average price per unit:
Natural gas (per Mcf)	$	4.58	$	4.24	8	%	$	5.32	(20	)%
Natural gas liquids (per Bbl)	$	47.69	$	48.22	(1	)%	$	47.44	2	%
Drip condensate (per Bbl)	$	76.62	$	75.88	1	%	$	73.60	3	%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $32.9 million for the year ended December 31, 2013, which consisted of a $17.0 millionincrease in sales of natural gas, a $14.2 millionincrease in NGLs sales and a $1.7 millionincrease in drip condensate sales.

The growth in natural gas sales for the year ended December 31, 2013, was primarily due to an 8%increase in the overall sales price of natural gas, as well as higher sales volumes at the Wattenberg system and the Red Desert complex, partially offset by a decrease at the Platte Valley system due to a gas flow change that became effective in July 2013, whereby volumes previously processed under percentage-of-proceeds contracts are now processed under fee-based arrangements.

The growth in NGLs sales for the year ended December 31, 2013, was primarily due to increases of $22.1 million, $15.4 million, $9.0 million and $4.2 million resulting from higher volumes processed and sold at the Red Desert complex, the Hilight system, the Wattenberg system and the Granger straddle plant, respectively. These increases were partially offset by a decrease of $14.0 million at Chipeta (with a corresponding decrease in cost of product), a decrease of $12.8 million at the Platte Valley system due to the aforementioned gas flow changes, and a decrease of $9.1 million at the Granger complex due to a decrease in volumes sold as a result of decreased throughput.

The growth in drip condensate sales for the year ended December 31, 2013 was primarily due to a $2.4 million increase at the Wattenberg system due to an increase in condensate volumes sold as a result of increased throughput, partially offset by a $0.9 million decrease at Hugoton due to a decrease in condensate volumes sold as a result of decreased throughput.

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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.

The growth in NGLs sales for the year ended December 31, 2012, 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, which was offset by a decrease in volumes; and an increase of $9.6 million related to volumes processed at the Granger straddle plant 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.

The decrease in natural gas sales for the year ended December 31, 2012, was primarily due to a 20% decrease in overall natural gas sales prices and lower sales volumes, resulting in decreases of $17.0 million at the Hilight system, $3.8 million at the Red Desert complex, and $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.

For the years ended December 31, 2013 and 2012, average natural gas, NGL and drip condensate prices include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Newcastle, Hugoton and Wattenberg systems, and 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.

Equity Income, Net and Other Revenues

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Equity income, net	$	22,948	$	16,042	43	%	$	11,261	42	%
Other revenues, net	5,977		3,807		57	%	8,292		(54	)%
Total	$	28,925	$	19,849	46	%	$	19,553	2	%

For the year ended December 31, 2013, equity income, net increased by $6.9 million, primarily due to the fourth quarter 2013 start-up of the Mont Belvieu JV fractionation trains, and volume increases at White Cliffs. These increases were offset by net losses associated with the initial start-up and line-fill stage of TEP during the fourth quarter of 2013. Equity income, net increased by $4.8 million for the year ended December 31, 2012, primarily due to a $3.8 million increase in income from White Cliffs and a $0.7 million increase in income from Rendezvous as a result of increased volumes.

Other revenues, net increased by $2.2 million for the year ended December 31, 2013, primarily due to the collection of deficiency fees associated with volume commitments at Chipeta. 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.

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Cost of Product and Operation and Maintenance Expenses

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
NGL purchases	$	191,788	$	181,078	6	%	$	158,288	14	%
Residue purchases	156,170		143,962		8	%	156,555		(8	)%
Other	16,327		11,039		48	%	12,528		(12	)%
Cost of product	$	364,285	$	336,079	8	%	$	327,371	3	%
Operation and maintenance	168,657		140,106		20	%	126,464		11	%
Total cost of product and operation and maintenance expenses	$	532,942	$	476,185	12	%	$	453,835	5	%

Including the effects of commodity price swap agreements on purchases, cost of product expense for the year ended December 31, 2013, increased by $28.2 million primarily due to the volume fluctuations noted in Throughput and Natural Gas, Natural Gas Liquids and Condensate Sales within this Item 7, resulting in the following:

• an $11.6 million net increase in residue purchases primarily at the Wattenberg system and the Red Desert complex, partially offset by decreases at the Platte Valley system and the Granger complex; and

• a $10.7 million net increase in NGL purchases primarily at the Red Desert complex, the Hilight system, and the Wattenberg system, partially offset by decreases at Chipeta, the Platte Valley system, and the Granger complex.

Including the effects of commodity price swap agreements on purchases, cost of product expense for the year ended December 31, 2012, increased by $8.7 million primarily due to the following:

• a $22.8 million net increase in NGL purchases primarily at Chipeta, the Hilight system, and the Wattenberg system due to volume fluctuations noted in Throughput and Natural Gas, Natural Gas Liquids and Condensate Sales within this Item 7, and an increase for the MGR assets as a result of entering into commodity price swap agreements that became effective in January 2012, partially offset by a decrease at the Platte Valley system due to lower pricing subsequent to its acquisition in February 2011; and

• a $12.6 million net decrease in residue purchases at the Hilight system due to declines in residue purchase prices, partially offset by an increase in cost of product expense for residue purchases for the MGR assets as a result of entering into commodity price swap agreements that became effective in January 2012.

Cost of product expense for the years ended December 31, 2013 and 2012, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and 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.

Operation and maintenance expense increased by $28.6 million for the year ended December 31, 2013, primarily due to an increase of $9.7 million in property, facility and overhead expense attributable to the Non-Operated Marcellus Interest, an increase of $8.3 million for plant repairs and maintenance primarily at the Wattenberg system and Chipeta, and an increase of $7.7 million for salaries, wages and payroll tax expense primarily at the Wattenberg system, the Brasada facility and the Hilight system.

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 for the Non-Operated Marcellus Interest.

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General and Administrative, Depreciation and Other Expenses

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
General and administrative	$	29,751	$	99,212	(70	)%	$	40,564	145	%
Property and other taxes	23,244		19,688		18	%	16,579		19	%
Depreciation, amortization and impairments	145,916		120,608		21	%	113,133		7	%
Total general and administrative, depreciation and other expenses	$	198,911	$	239,508	(17	)%	$	170,276	41	%

General and administrative expenses decreased by $69.5 million for the year ended December 31, 2013, primarily due to a decrease of $69.9 million in non-cash compensation expenses attributable to the awards outstanding under the Incentive Plan, which were settled in December 2012 when the Incentive Plan terminated in conjunction with WGP’s IPO. These declines were partially offset by an increase of $2.2 million in corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement.

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.

Property and other taxes increased by $3.6 million for the year ended December 31, 2013, primarily due to ad valorem tax increases of $2.6 million associated with capital additions at the Platte Valley, Chipeta and Wattenberg systems and $0.9 million due to the completion of the Brasada facility in June 2013. 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.

Depreciation, amortization and impairments increased by $25.3 million for the year ended December 31, 2013, primarily attributable to a $12.1 million increase in depreciation expense associated with capital projects completed at the Wattenberg, Chipeta, Platte Valley and Hilight systems, a $6.2 million increase in depreciation and impairment expense associated with the Non-Operated Marcellus Interest, a $6.1 million increase in depreciation expense related to the completion of the Brasada facility in June 2013, and a $3.9 million increase in depreciation expense associated with the March 2013 acquisition of the Anadarko-Operated Marcellus Interest. Partially offsetting these increases was a decrease of $5.3 million in impairment expense, due to a $1.2 million impairment recognized in 2013 primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest, as compared to the $6.6 million impairment recognized in 2012 related to a gathering system in central Wyoming and a relocated compressor.

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.

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Interest Income, Net – Affiliates and Interest Expense

Amortization of debt issuance costs and commitment fees in the table below includes amortization of (i) the original issue discount for the June 2012 offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022, (ii) the original issue premium for the October 2012 offering of an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022, (iii) the original issue discount for the $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”), (iv) the original issue discount for the August 2013 offering of $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018 (the “2018 Notes”), and (v) underwriters’ fees. The October 2012 notes and the June 2012 notes were issued under the same indenture and are considered a single class of securities, collectively referred to as the “2022 Notes.”

	Year Ended December 31,
thousands except percentages	2013			2012			Inc/ (Dec)		2011			Inc/ (Dec)
Interest income on note receivable	$	16,900		$	16,900		—	%	$	16,900		—	%
Interest income, net on affiliate balances (1)	—			—			—	%	7,206			(100	)%
Interest income, net – affiliates	$	16,900		$	16,900		—	%	$	24,106		(30	)%
Third parties
Interest expense on long-term debt	$	(59,293	)	$	(41,171	)	44	%	$	(20,533	)	101	%
Amortization of debt issuance costs and commitment fees (2)	(4,449		)	(4,319		)	3	%	(5,297		)	(18	)%
Capitalized interest	11,945			6,196			93	%	420			NM
Affiliates
Interest expense on note payable to Anadarko (3)	—			(2,440		)	(100	)%	(4,935		)	(51	)%
Interest expense on affiliate balances (4)	—			(326		)	(100	)%	—			NM
Interest expense	$	(51,797	)	$	(42,060	)	23	%	$	(30,345	)	39	%

NM-Not meaningful

⁽¹⁾  Incurred on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets, and the Bison 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.

⁽²⁾  For the year ended December 31, 2013, includes $1.2 million of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes, the 2021 Notes, and the 2018 Notes. For the year ended December 31, 2012, includes $1.1 million of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes and the 2021 Notes.

⁽³⁾  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.

⁽⁴⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, we repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant. 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 $9.7 million for the year ended December 31, 2013, primarily due to interest expense incurred on the 2022 Notes of $15.0 million as well as interest incurred on the 2018 Notes of $2.5 million. In addition, interest expense increased on the RCF by $0.6 million primarily due to greater average outstanding borrowings in the current period, partially offset by a decrease of $2.4 million attributable to the repayment of the note payable to Anadarko in June 2012. 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.

Also partially offsetting the increases in interest expense for the year ended December 31, 2013, was an increase of capitalized interest of $5.7 million primarily associated with the expansion of the Lancaster plant and construction of the two Mont Belvieu JV fractionation trains.

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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 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.

Other Income (Expense), Net

	Year Ended December 31,
thousands	2013		2012		Inc/ (Dec)	2011			Inc/ (Dec)
Other income (expense), net	$	1,837	$	292	NM	$	(44	)	NM

For the year ended December 31, 2013 and 2012, other income (expense), net included $1.6 million of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition. In addition, for the year ended December 31, 2013, other income (expense), net included $0.5 million of interest earned on overnight investments, which was offset by $0.2 million of expense associated with a remediation project for MGR.

For the year ended December 31, 2012, other income (expense), net also included a realized loss of $1.7 million resulting from U.S. Treasury Rate lock agreements settled simultaneously with our June 2012 offering of the 2022 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.

Income Tax Expense

	Year Ended December 31,
thousands except percentages	2013			2012			Inc/ (Dec)		2011			Inc/ (Dec)
Income before income taxes	$	287,798		$	169,957		69	%	$	239,011		(29	)%
Income tax expense	2,355			20,690			(89	)%	32,150			(36	)%
Effective tax rate	1		%	12		%			13		%

We are not a taxable entity for U.S. federal income tax purposes; however, 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 TEFR Interests prior to and including February 2014, (b) the Non-Operated Marcellus Interest prior to and including March 2013, (c) the MGR assets prior to and including January 2012 and (d) the Bison assets prior to and including June 2011, was subject to federal and state income tax. Income earned on the TEFR Interests, the Non-Operated Marcellus Interest, MGR assets and Bison assets for periods subsequent to February 2014, March 2013, January 2012, and June 2011, respectively, was only subject to Texas margin tax on income apportionable to Texas.

Noncontrolling Interests

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Net income attributable to noncontrolling interests	$	10,816	$	14,890	(27	)%	$	14,103	6	%

For the year ended December 31, 2013, net income attributable to noncontrolling interests decreased by $4.1 million primarily due to our acquisition of the additional Chipeta interest in August 2012. For the year ended December 31, 2012, net income attributable to noncontrolling interests increased by $0.8 million primarily due to higher volumes at the Chipeta system, partially offset by the acquisition of the additional Chipeta interest in August 2012. 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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KEY PERFORMANCE METRICS

	Year Ended December 31,
thousands except percentages and per-unit amounts	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (1)	$	654,924	$	544,853	20	%	$	516,038	6	%
Adjusted gross margin for crude/NGL assets (2)	15,274		13,221		16	%	9,497		39	%
Adjusted gross margin attributable to Western Gas Partners, LP (3)	$	670,198	$	558,074	20	%	$	525,535	6	%
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets (4)	0.56		0.53		6	%	0.57		(7	)%
Adjusted gross margin per Bbl for crude/NGL assets (5)	1.05		1.17		(10	)%	0.94		24	%
Adjusted EBITDA attributable to Western Gas Partners, LP (6)	457,773		377,929		21	%	361,653		5	%
Distributable cash flow (6)	$	380,529	$	309,945	23	%	$	319,294	(3	)%

⁽¹⁾  Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product.

⁽²⁾  Adjusted gross margin for crude/NGL assets is calculated as total revenues for crude/NGL assets less cost of product for crude/NGL assets plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, TEG, TEP and FRP, which are measured in barrels.

⁽³⁾  For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to the most directly comparable financial measure calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.

⁽⁴⁾  Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets, divided by total throughput attributable to Western Gas Partners, LP for natural gas assets.

⁽⁵⁾  Average for period. Calculated as Adjusted gross margin for crude/NGL assets, divided by total throughput (MBbls/d) for crude/NGL assets.

⁽⁶⁾  For reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.

Adjusted gross margin attributable to Western Gas Partners, LP. Adjusted gross margin increased by $112.1 million for the year ended December 31, 2013, primarily due to higher margins on the Non-Operated Marcellus Interest, the Wattenberg system, the Anadarko-Operated Marcellus Interest, Chipeta, and the start-up of the Brasada facility in June 2013.

Adjusted gross margin increased by $32.5 million for the year ended December 31, 2012, primarily due to higher margins on the Non-Operated Marcellus Interest and on 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.

Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets increased by $0.03 for the year ended December 31, 2013, primarily due to higher margins and increases in throughput at Chipeta, the Wattenberg system, and the Non-Operated Marcellus Interest, as well as overall changes in the throughput mix of our portfolio.

Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets decreased by $0.04 for the year ended December 31, 2012, 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.

Adjusted gross margin per Bbl for crude/NGL assets decreased by $0.12 for the year ended December 31, 2013, primarily due to net losses associated with the initial start-up and line-fill stage of TEP during the fourth quarter of 2013. Adjusted gross margin per Bbl for crude/NGL assets increased by $0.23 for the year ended December 31, 2012, primarily due to an increase in volumes at White Cliffs.

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Adjusted EBITDA. Adjusted EBITDA increased by $79.8 million for the year ended December 31, 2013, primarily due to a $135.3 million increase in total revenues and a $4.1 milliondecrease in net income attributable to noncontrolling interest as a result of the acquisition of the additional Chipeta interest. These amounts were offset by a $28.6 millionincrease in operation and maintenance expenses, a $28.2 millionincrease in cost of product, and a $3.6 millionincrease in property and other tax expense.

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, 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.

Distributable cash flow. Distributable cash flow increased by $70.6 million for the year ended December 31, 2013, primarily due to a $79.8 millionincrease in Adjusted EBITDA and a $6.6 milliondecrease in maintenance capital expenditures, offset by a $15.8 millionincrease in net cash paid for interest expense.

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.

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, 2013, included cash and cash equivalents, cash flows generated from operations, 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 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 20, 2014, the board of directors of our general partner declared a cash distribution to our unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

Management continuously monitors our leverage position and coordinates our capital expenditure program, quarterly distributions and acquisition strategy with our 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 2013 Form 10-K.

Working capital. As of December 31, 2013, we had $4.4 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. As of December 31, 2013, we had $787.2 million available for borrowing under our $800.0 million RCF.

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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	2013		2012		2011
Acquisitions	$	716,985	$	611,719	$	330,794
Expansion capital expenditures	$	615,924	$	600,893	$	121,318
Maintenance capital expenditures	29,930		37,228		28,399
Total capital expenditures (1)	$	645,854	$	638,121	$	149,717
Capital incurred (2)	$	628,285	$	690,041	$	182,536

⁽¹⁾  Capital expenditures for the years ended December 31, 2013 and 2012, included $10.6 million and $6.8 million, respectively, 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 and 2011, included $178.8 million and $20.1 million, respectively, of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest, the MGR assets, and the Bison assets.

⁽²⁾  Includes the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners for all periods presented. Capital incurred for the years ended December 31, 2013 and 2012, included $10.6 million and $6.8 million, respectively, of capitalized interest. Capital incurred for the years ended December 31, 2013, 2012 and 2011, included $8.8 million, $160.9 million and $45.7 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest, the MGR assets, and the Bison assets.

Acquisitions during 2013 included OTTCO, the Mont Belvieu JV, the Anadarko-Operated Marcellus Interest and the Non-Operated Marcellus Interest. Acquisitions during 2012 included the additional Chipeta interest and the MGR assets. Acquisitions during 2011 included the Bison facility and the Platte Valley 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.

Capital expenditures, excluding acquisitions, increased by $7.7 million for the year ended December 31, 2013. Expansion capital expenditures increased by $15.0 million (including a $3.8 million increase in capitalized interest) for the year ended December 31, 2013, primarily due to an increase of $114.2 million related to the construction of the Lancaster plants and a $91.7 million increase in expenditures at the Wattenberg and Hilight systems and the Anadarko-Operated Marcellus Interest. These increases were partially offset by a $191.2 million decrease at Chipeta, the Non-Operated Marcellus Interest, the Brasada facility and the Platte Valley system. Maintenance capital expenditures decreased by $7.3 million, primarily as a result of decreased expenditures of $7.5 million at the Wattenberg, Hilight, Haley, and Platte Valley systems, the Red Desert complex and the Non-Operated Marcellus Interest, partially offset by a $1.7 million increase at the Anadarko-Operated Marcellus Interest.

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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 gas processing facility and Lancaster plant, $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.

We estimate our total capital expenditures for the year ended December 31, 2014, including our 75% share of Chipeta’s capital expenditures and excluding acquisitions, to be $614 million to $664 million and our maintenance capital expenditures to be 9% to 11% of total capital expenditures. Expected 2014 projects include the construction of a second train at our Lancaster plant and continued well connections in the Denver-Julesburg basin and the Marcellus shale. 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 present a summary of our net cash flows provided by (used in) operating activities, investing activities and financing activities:

	Year Ended December 31,
thousands	2013			2012			2011
Net cash provided by (used in):
Operating activities	$	448,201		$	338,047		$	312,838
Investing activities	(1,652,995		)	(1,357,537		)	(485,832		)
Financing activities	885,541			1,212,912			372,479
Net increase (decrease) in cash and cash equivalents	$	(319,253	)	$	193,422		$	199,485

Operating Activities. Net cash provided by operating activities during the year ended December 31, 2013, was $448.2 million, compared to $338.0 million for the year ended December 31, 2012. Operating cash flows increased primarily due to the impact of changes in working capital items, in addition to higher sales volumes and higher average natural gas prices.

Net cash provided by operating activities during the year ended December 31, 2012, was $338.0 million, compared to $312.8 million for the year ended December 31, 2011. Operating cash flows increased primarily due to the impact of changes in working capital items, in addition to higher sales volumes and increased average commodity prices pursuant to commodity price swap agreements and the addition of the Platte Valley assets in March 2011. The impact of changes in working capital items was primarily due to accruals of expected future operating cash receipts and payments.

Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2013, included the following:

• $465.5 million of cash paid for the acquisition of the Non-Operated Marcellus Interest;

• $646.5 million of capital expenditures, net of $0.6 million of contributions in aid of construction costs from affiliates;

• $221.2 million of capital contributions to TEG, TEP and FRP for construction costs;

• $134.6 million of cash paid for the acquisition of the Anadarko-Operated Marcellus Interest;

• $78.1 million of cash paid for the acquisition of the Mont Belvieu JV;

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• $37.3 million of capital contributions to the Mont Belvieu JV to fund our share of construction costs for the fractionation facilities completed in the fourth quarter of 2013;

• $27.5 million of cash paid for the acquisition of OTTCO;

• $19.1 million of cash paid related to a White Cliffs expansion project anticipated to be completed in the first half of 2014;

• $17.0 million of capitalized interest on equity investments related to the Mont Belvieu JV, TEP, TEG and FRP;

• $11.2 million of cash paid for equipment purchases from Anadarko; and

• $4.4 million of distributions from equity investments in excess of cumulative earnings.

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

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

• $638.1 million of capital expenditures;

• $128.3 million of cash paid for the additional Chipeta interest;

• $107.6 million of cash paid for the capital contributions to TEP for construction costs and the initial investments in TEG and FRP; and

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

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

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

• $149.7 million of capital expenditures;

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

• $6.1 million of cash paid for the initial investment in TEP; and

• $3.8 million for equipment purchases from Anadarko.

Financing Activities. Net cash provided by financing activities for the year ended December 31, 2013, included the following:

• $273.7 million of net proceeds from our December 2013 equity offering, including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest, $215.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;

• $424.7 million of net proceeds from our May 2013 equity offering, including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;

• $247.6 million of net proceeds from our 2018 Notes offering in August 2013, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our outstanding borrowings under our RCF, including $250.0 million of borrowings to fund the acquisition of the Non-Operated Marcellus Interest;

• $133.5 million of borrowings to fund the acquisition of the Anadarko-Operated Marcellus Interest;

• $299.0 million of borrowings to fund capital expenditures;

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• $27.5 million of borrowings to fund the acquisition of OTTCO;

• $41.8 million of net proceeds from activity under our Continuous Offering Program (as defined and discussed in Registered Securities within this Item 7), including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest; and

• $0.5 million of net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest after common units were issued in conjunction with the acquisition of the Non-Operated Marcellus Interest.

Net contributions from Anadarko attributable to intercompany balances were $209.0 million during the year ended December 31, 2013, representing intercompany transactions attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest.

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 offering in June 2012 and October 2012, respectively, after underwriting and original issue discounts, original issue premiums 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 acquisition of the MGR assets; and

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

Proceeds from our 2022 Notes offerings were used to repay amounts outstanding under our RCF and our note payable to Anadarko. Net contributions from Anadarko attributable to intercompany balances were $278.6 million during the year ended December 31, 2012, representing intercompany transactions attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest, the compensation expense allocated to us since the inception of the Incentive Plan and the settlement of intercompany transactions attributable to the MGR 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 acquisition of the Platte Valley system;

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

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

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

Proceeds from 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 $29.9 million during 2011, attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest, and the net non-cash settlement of intercompany transactions attributable to the MGR assets and the Bison facility.

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For the years ended December 31, 2013, 2012 and 2011, we paid $299.1 million, $197.9 million and $140.1 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners of Chipeta totaled $2.2 million, $29.1 million and $33.6 million during the years ended December 31, 2013, 2012 and 2011, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions to noncontrolling interest owners of Chipeta totaled $13.1 million, $17.3 million and $17.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, representing the distributions paid as of December 31 of the respective year. Decreases in contributions by and distributions to noncontrolling interest owners of Chipeta were also impacted by the August 2012 acquisition of the additional Chipeta interest.

Debt and credit facility. As of December 31, 2013, the carrying value of our outstanding debt consisted of $249.7 million of the 2018 Notes, $673.3 million of the 2022 Notes and $495.2 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 August 2013, we completed the offering of $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018 at a price to the public of 99.879% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2018 Notes is 2.806%. Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $1.5 million, original issue discount and debt issuance costs) were used to repay amounts then outstanding under our RCF.

The 2018 Notes mature on August 15, 2018, unless earlier redeemed. The Partnership may redeem the 2018 Notes in whole or in part, at any time before July 15, 2018, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2018 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2018 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 2018 Notes) plus 20 basis points, plus, in either case, accrued and unpaid interest to such redemption date, if any, on the principal amount being redeemed. On or after July 15, 2018, the 2018 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 2018 Notes to be redeemed, plus accrued interest on the 2018 Notes to be redeemed to the date of redemption.

In June 2012, we completed the offering of $520.0 million aggregate principal amount of the 2022 Notes 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 the 2022 Notes 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. 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 is 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 earlier redeemed. 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 $500.0 million aggregate principal amount 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 earlier redeemed. 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 2021 Notes, 2022 Notes, and 2018 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, 2013, we were in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes, and the 2018 Notes.

Note payable to Anadarko. In 2008, we entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 2.82% prior to June 2012 when the note payable to Anadarko was repaid in full with proceeds from the June 2012 offering of the 2022 Notes.

Revolving credit facility. As of December 31, 2013, we had no outstanding borrowings and $12.8 million in outstanding letters of credit issued under our $800.0 million RCF. 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 1.67% and 1.71% at December 31, 2013 and 2012, respectively. We are 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, 2013 and 2012. At December 31, 2013, we were in compliance with all covenants under the RCF. See 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.

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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 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. At December 31, 2013, we were in compliance with all remaining covenants under the RCF.

The 2021 Notes, the 2022 Notes, the 2018 Notes and obligations under the RCF are recourse to our general partner. Our general partner is indemnified by a wholly owned subsidiary of Anadarko, Western Gas Resources, Inc. (“WGRI”), against any claims made against our general partner under the 2022 Notes, the 2021 Notes, and/or the RCF. See 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 amendments to the RCF and borrowing activity under the new RCF in March 2014, related to acquisitions that closed after December 31, 2013.

In connection with the acquisition of the Non-Operated Marcellus Interest in March 2013, our general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary agreed to indemnify our general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. The 2013 Indemnification Agreement applies to the 2018 Notes. Our general partner and WGRI also amended and restated the existing indemnity agreement between them to reduce the amount for which WGRI would indemnify our general partner by an amount equal to any amounts payable to our general partner under the 2013 Indemnification Agreement. See 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.

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 SEC.

In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to an aggregate of $125.0 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (the “Continuous Offering Program”). 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 for a discussion of trades completed under our Continuous Offering Program.

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.

29

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.

CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual cash obligations as of December 31, 2013, including the contractual obligations of the TEFR Interests. 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 2014.

	Obligations by Period
thousands	2014		2015		2016		2017		2018		Thereafter		Total
Long-term debt
Principal	—		—		—		—		250,000		1,170,000		1,420,000
Interest	59,652		59,634		59,614		59,595		56,324		160,275		455,094
Asset retirement obligations	1,966		1,755		127		—		—		74,187		78,035
Capital expenditures	47,112		—		—		—		—		—		47,112
Credit facility fees	2,000		2,000		460		—		—		—		4,460
Environmental obligations	932		532		532		135		135		579		2,845
Operating leases	309		245		233		157		34		—		978
Total	$	111,971	$	64,166	$	60,966	$	59,887	$	306,493	$	1,405,041	$	2,008,524

Debt and credit facility fees. For additional information on 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.

30

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 to this Current Report on Form 8-K.

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

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 23 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by $18.7 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.

31

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 2013, we recognized a $1.2 million impairment primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest.

During 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 during 2012, an impairment of $0.6 million was recognized for the original installation costs on a compressor relocated within our operating assets.

During 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 $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.

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 ofDecember 31, 2013, 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 qualitative evaluation as of October 1, 2013. 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.

32

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 2014 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 our consolidated financial statements.

Impairments of intangible assets. Our intangible asset balance as of December 31, 2013 and 2012, primarily represents the fair value, net of amortization, of (i) contracts we assumed in connection with the Platte Valley acquisition in February 2011, which are amortized on a straight-line basis over 50 years, and (ii) interconnect agreements at Chipeta entered into in November 2012, amortized on a straight-line basis over 10 years.

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 an asset may not be recoverable. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount 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. 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 uses 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 uses 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.

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EX-99.3

EXHIBIT 99.3

Item 8.Financial Statements and Supplementary Data

WESTERN GAS PARTNERS, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	2
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011	3
Consolidated Balance Sheets as of December 31, 2013 and 2012	4
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2013, 2012 and 2011	5
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	6
Notes to Consolidated Financial Statements	7
Supplemental Quarterly Information	38

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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

August 27, 2014

2

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
thousands except per-unit amounts	2013 (1)			2012 (1)			2011 (1)
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	306,810		$	249,997		$	227,535
Natural gas, natural gas liquids and condensate sales	496,848			436,423			417,547
Other, net	1,868			1,606			2,337
Total revenues – affiliates	805,526			688,026			647,419
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids	175,732			132,333			119,934
Natural gas, natural gas liquids and condensate sales	44,396			71,916			84,836
Other, net	4,109			2,201			5,955
Total revenues – third parties	224,237			206,450			210,725
Total revenues	1,029,763			894,476			858,144
Equity income, net (2)	22,948			16,042			11,261
Operating expenses
Cost of product (3)	364,285			336,079			327,371
Operation and maintenance (3)	168,657			140,106			126,464
General and administrative (3)	29,751			99,212			40,564
Property and other taxes	23,244			19,688			16,579
Depreciation, amortization and impairments	145,916			120,608			113,133
Total operating expenses	731,853			715,693			624,111
Operating income	320,858			194,825			245,294
Interest income, net – affiliates	16,900			16,900			24,106
Interest expense (4)	(51,797		)	(42,060		)	(30,345		)
Other income (expense), net	1,837			292			(44		)
Income before income taxes	287,798			169,957			239,011
Income tax expense	2,355			20,690			32,150
Net income	285,443			149,267			206,861
Net income attributable to noncontrolling interests	10,816			14,890			14,103
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Pre-acquisition net (income) loss allocated to Anadarko	(4,128		)	(27,391		)	(52,599		)
General partner interest in net (income) loss (5)	(69,633		)	(28,089		)	(8,599		)
Limited partners’ interest in net income (5)	$	200,866		$	78,897		$	131,560
Net income per common unit – basic and diluted	$	1.83		$	0.84		$	1.64
Net income per subordinated unit – basic and diluted (6)	$	—		$	—		$	1.28

⁽¹⁾  Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

⁽²⁾  Income earned from equity investments is classified as affiliate. See Note 1.

⁽³⁾  Cost of product includes product purchases from Anadarko (as defined in Note 1) of $129.0 million, $145.3 million and $83.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Operation and maintenance includes charges from Anadarko of $56.4 million, $51.2 million and $51.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. General and administrative includes charges from Anadarko of $23.4 million, $92.8 million and $33.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 5.

⁽⁴⁾  Includes affiliate (as defined in Note 1) interest expense of zero, $2.8 million and $4.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 10.

⁽⁵⁾  Represents net income earned on and subsequent to the date of the acquisition of the Partnership assets (as defined in Note 1). See Note 4.

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

See accompanying Notes to Consolidated Financial Statements.

3

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
thousands except number of units	2013 (1)		2012 (1)
ASSETS
Current assets
Cash and cash equivalents	$	100,728	$	419,981
Accounts receivable, net (2)	84,060		50,233
Other current assets (3)	10,022		6,998
Total current assets	194,810		477,212
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	4,239,100		3,432,392
Less accumulated depreciation	855,845		714,436
Net property, plant and equipment	3,383,255		2,717,956
Goodwill	105,336		105,336
Other intangible assets	53,606		55,490
Equity investments	593,400		219,766
Other assets	27,401		27,798
Total assets	$	4,617,808	$	3,863,558
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables (4)	$	39,589	$	25,154
Accrued ad valorem taxes	13,860		11,949
Income taxes payable	—		552
Accrued liabilities (5)	137,011		147,651
Total current liabilities	190,460		185,306
Long-term debt	1,418,169		1,168,278
Deferred income taxes	37,998		47,149
Asset retirement obligations and other	79,145		68,749
Total long-term liabilities	1,535,312		1,284,176
Total liabilities	1,725,772		1,469,482
Equity and partners’ capital
Common units (117,322,812 and 104,660,553 units issued and outstanding at December 31, 2013 and 2012, respectively)	2,431,193		1,957,066
General partner units (2,394,345 and 2,135,930 units issued and outstanding at December 31, 2013 and 2012, respectively)	78,157		52,752
Net investment by Anadarko	312,092		313,600
Total partners’ capital	2,821,442		2,323,418
Noncontrolling interests	70,594		70,658
Total equity and partners’ capital	2,892,036		2,394,076
Total liabilities, equity and partners’ capital	$	4,617,808	$	3,863,558

⁽¹⁾  Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

⁽²⁾  Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $47.9 million and $19.1 million as of December 31, 2013 and 2012, respectively.

⁽³⁾  Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of December 31, 2013 and 2012, respectively.

⁽⁴⁾  Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.3 million and $2.5 million as of December 31, 2013 and 2012, respectively.

⁽⁵⁾  Accrued liabilities include amounts payable to affiliates of $0.1 million as of December 31, 2013 and 2012.

See accompanying Notes to Consolidated Financial Statements.

4

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL

	Partners’ Capital
thousands	Net Investment by Anadarko			Common Units			Subordinated Units			General Partner Units			Noncontrolling Interests			Total
Balance at December 31, 2010	$	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 (1)	—			272,222			(272,222		)	—			—			—
Issuance of common and general partner units, net of offering expenses	—			328,345			—			6,972			—			335,317
Contributions from noncontrolling interest owners	—			—			—			—			33,637			33,637
Distributions to noncontrolling interest owners	—			—			—			—			(17,478		)	(17,478		)
Distributions to unitholders	—			(102,091		)	(31,180		)	(6,847		)	—			(140,118		)
Acquisition from affiliates	(92,666		)	66,313			—			1,353			—			(25,000		)
Contributions of equity-based compensation from Anadarko (2)	—			9,472			—			194			—			9,666
Net pre-acquisition contributions from (distributions to) Anadarko	(27,675		)	—			—			—			—			(27,675		)
Elimination of net deferred tax liabilities	22,072			—			—			—			—			22,072
Other	—			(267		)	—			(47		)	—			(314		)
Balance at December 31, 2011 (3)	$	362,573		$	1,495,253		$	—		$	31,729		$	120,724		$	2,010,279
Net income	27,391			78,897			—			28,089			14,890			149,267
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 (2)	—			84,971			—			2,086			—			87,057
Net pre-acquisition contributions from (distributions to) Anadarko	299,833			(106,597		)	—			—			—			193,236
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 (3)	$	313,600		$	1,957,066		$	—		$	52,752		$	70,658		$	2,394,076
Net income	4,128			200,866			—			69,633			10,816			285,443
Issuance of common and general partner units, net of offering expenses	—			724,811			—			15,775			—			740,586
Contributions from noncontrolling interest owners	—			—			—			—			2,247			2,247
Distributions to noncontrolling interest owners	—			—			—			—			(13,127		)	(13,127		)
Distributions to unitholders	—			(239,157		)	—			(59,944		)	—			(299,101		)
Acquisitions from affiliates	(255,635		)	(209,865		)	—			—			—			(465,500		)
Contributions of equity-based compensation from Anadarko (2)	—			2,865			—			58			—			2,923
Net pre-acquisition contributions from (distributions to) Anadarko (5)	203,469			—			—			—			—			203,469
Net distributions of other assets to Anadarko	—			(5,738		)	—			(117		)	—			(5,855		)
Elimination of net deferred tax liabilities	46,530			—			—			—			—			46,530
Other	—			345			—			—			—			345
Balance at December 31, 2013 (3)	$	312,092		$	2,431,193		$	—		$	78,157		$	70,594		$	2,892,036

⁽¹⁾  All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

⁽²⁾  Associated with the Anadarko Incentive Plans for the years ended December 31, 2011 and 2013, 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.

⁽³⁾  Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

⁽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.

⁽⁵⁾  Includes deferred taxes on capitalized interest of $5.5 million associated with the acquisition of the TEFR Interests for the year ended December 31, 2013.

See accompanying Notes to Consolidated Financial Statements.

5

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
thousands	2013 (1)			2012 (1)			2011 (1)
Cash flows from operating activities
Net income	$	285,443		$	149,267		$	206,861
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	145,916			120,608			113,133
Non-cash equity-based compensation expense	3,521			3,717			3,490
Deferred income taxes	31,891			30,109			16,580
Debt-related amortization and other items, net	2,449			2,319			3,110
Equity income, net (2)	(22,948		)	(16,042		)	(11,261		)
Distributions from equity investment earnings (2)	17,698			20,660			15,999
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(34,019		)	22,916			(44,725		)
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	21,952			5,045			30,884
Change in other items, net	(3,702		)	(552		)	(21,233		)
Net cash provided by operating activities	448,201			338,047			312,838
Cash flows from investing activities
Capital expenditures	(646,471		)	(638,121		)	(149,717		)
Contributions in aid of construction costs from affiliates	617			—			—
Acquisitions from affiliates	(476,711		)	(611,719		)	(28,837		)
Acquisitions from third parties	(240,274		)	—			(301,957		)
Investments in equity affiliates	(294,693		)	(108,457		)	(6,203		)
Distributions from equity investments in excess of cumulative earnings (2)	4,438			—			—
Proceeds from the sale of assets to affiliates	85			760			382
Other	14			—			500
Net cash used in investing activities	(1,652,995		)	(1,357,537		)	(485,832		)
Cash flows from financing activities
Borrowings, net of debt issuance costs	957,503			1,041,648			1,055,939
Repayments of debt	(710,000		)	(549,000		)	(869,000		)
Increase (decrease) in outstanding checks	(1,763		)	1,800			4,039
Proceeds from the issuance of common and general partner units, net of offering expenses	740,825			625,877			335,317
Distributions to unitholders	(299,101		)	(197,850		)	(140,118		)
Contributions from noncontrolling interest owners	2,247			29,108			33,637
Distributions to noncontrolling interest owners	(13,127		)	(17,303		)	(17,478		)
Net contributions from (distributions to) Anadarko	208,957			278,632			(29,857		)
Net cash provided by financing activities	885,541			1,212,912			372,479
Net increase (decrease) in cash and cash equivalents	(319,253		)	193,422			199,485
Cash and cash equivalents at beginning of period	419,981			226,559			27,074
Cash and cash equivalents at end of period	$	100,728		$	419,981		$	226,559
Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets	$	5,855		$	15,296		$	(29	)
Interest paid, net of capitalized interest	$	47,098		$	28,042		$	25,828
Taxes paid	$	552		$	495		$	190

⁽¹⁾  Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

⁽²⁾  Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

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). 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 subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, and includes equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” All income earned on, distributions from and contributions to the Partnership’s equity investments are considered to be affiliate transactions. See Note 2. “Equity investment throughput” refers to the Partnership’s 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of the 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput.

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, 2013, the Partnership’s assets and investments accounted for under the equity method, including the TEFR Interests, consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	13	1	5	2
NGL gathering systems	—	—	—	2
Natural gas treating facilities	8	—	—	1
Natural gas processing facilities	8	3	—	2
NGL pipelines	3	—	—	2
Natural gas pipelines	3	—	—	—
Oil pipeline	—	—	—	1

These assets are located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), north-central Pennsylvania, and Texas. The Partnership was also constructing the Lancaster processing plant in Northeast Colorado at the end of the fourth quarter of 2013.

Western Gas Equity Partners, LP. In December 2012, WGP completed its IPO of 19,758,150 common units representing limited partner interests in WGP 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 resulting in aggregate proceeds to the Partnership of $409.4 million, which was used by the Partnership for general partnership purposes, including the funding of capital expenditures.

WGP owns the following types of interests in the Partnership: (i) the 2.0% general partner interest and all of the incentive distribution rights (“IDRs”) in the Partnership, both owned through WGP’s 100% ownership of the Partnership’s general partner and (ii) a significant limited partner interest (see Holdings of Partnership equity in Note 4). WGP has no independent operations or material assets other than its partnership interests in WES.

7

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Basis of presentation. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated. 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.

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 Anadarko-Operated Marcellus Interest (see Note 2) and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system in the accompanying consolidated financial statements.

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement (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 the additional Chipeta 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, 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 within noncontrolling interests in the consolidated financial statements for all periods presented. See Note 2.

Presentation of Partnership assets. The “Partnership assets” refer collectively to the assets owned and interests accounted for under the equity method by the Partnership as of December 31, 2013. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s general partner, each acquisition of Partnership 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 Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of the Partnership 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 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 Partnership assets during the periods reported. Net income attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income per common unit 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 condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known.

8

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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

Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities.

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

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

Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership is required to measure fair value and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the Partnership uses 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, 2013, the third-party accounts receivable balance was net of the associated bad-debt reserve of $13,000. As of December 31, 2012, there was no reserve for bad debts.

9

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2013, natural gas imbalance receivables and payables were $3.6 million and $2.5 million, respectively. As of December 31, 2012, natural gas imbalance receivables and payables were $1.7 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.

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, 2013, 2012 and 2011.

10

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 Partnership assets acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price paid to 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 such net assets on their respective acquisition dates. The consolidated balance sheets as of December 31, 2013 and 2012, include goodwill of $105.3 million, the impairment of which (if applicable) is not 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. An initial qualitative assessment may be performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. 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 qualitative evaluation as of October 1, 2013, 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, of (i) contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which are amortized on a straight-line basis over 50 years, and (ii) interconnect agreements at Chipeta entered into in November 2012, amortized on a straight-line basis over 10 years.

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, 2013, the carrying value of the Partnership’s intangible assets was $53.6 million, net of $3.4 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, 2012, the carrying value of the Partnership’s intangible assets was $55.5 million, net of $2.0 million of accumulated amortization.

11

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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

	Equity Investments
thousands	Fort  Union (1)			White  Cliffs (2)			Rendezvous (3)			Mont Belvieu JV(4)		TEG(5)			TEP (6)			FRP (7)
Balance at December 31, 2011	$	22,268		$	17,710		$	69,839		$	—	$	—		$	6,110		$	—
Initial investment	—			—			—			—		9,086			—			23,878
Investment earnings (loss), net of amortization	6,383			7,871			1,857			—		(53		)	(4		)	(12		)
Contributions	—			862			—			—		—			74,631			—
Distributions	(5,198		)	(8,876		)	(6,586		)	—		—			—			—
Balance at December 31, 2012	$	23,453		$	17,567		$	65,110		$	—	$	9,033		$	80,737		$	23,866
Initial investment	—			—			—			78,129		—			—			—
Investment earnings (loss), net of amortization	6,273			9,681			2,088			5,690		93			(776		)	(101		)
Contributions	16			19,087			—			37,309		6,732			108,969			105,547
Capitalized interest	—			—			—			1,352		791			8,801			6,089
Distributions	(4,570		)	(9,099		)	(4,029		)	—		—			—			—
Distributions in excess of cumulative earnings	—			(2,197		)	(2,241		)	—		—			—			—
Balance at December 31, 2013	$	25,172		$	35,039		$	60,928		$	122,480	$	16,649		$	197,731		$	135,401

⁽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.

⁽⁴⁾  The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.

⁽⁵⁾  The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

⁽⁶⁾  The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

⁽⁷⁾  The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

12

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The investment balance at December 31, 2013, includes $2.5 million and $44.0 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. (“WGRI”), 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 WGRI 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, 2013, is $9.3 million less than the Partnership’s underlying equity in White Cliffs’ net assets as of December 31, 2013, 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.

The following tables present the summarized combined financial information for the Partnership’s equity method investments (amounts represents 100% of investee financial information):

	Year Ended December 31,
thousands	2013		2012		2011
Consolidated Statements of Income
Revenues	$	261,705	$	199,764	$	153,131
Operating income	171,496		135,498		90,544
Net income	170,175		133,987		88,504

	December 31,
thousands	2013		2012
Consolidated Balance Sheets
Current assets	$	186,690	$	79,835
Property, plant and equipment, net	2,676,531		1,174,311
Other assets	38,258		45,100
Total assets	$	2,901,479	$	1,299,246
Current liabilities	206,602		76,862
Non-current liabilities	34,012		50,759
Equity	2,660,865		1,171,625
Total liabilities and equity	$	2,901,479	$	1,299,246

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.

13

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 ultimately 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 sales 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.

14

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 “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,139,027 units remained available for future issuance as of December 31, 2013. Upon vesting of each phantom unit awarded under the WES LTIP, 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 WES 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 WES 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 Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) for the year ended December 31, 2013, (ii) the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) for the years ended December 31, 2012 and 2011, and (iii) 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”) for all periods presented. 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. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized. However, distribution equivalent rights awarded in tandem with equity-or liability-based awards are paid in cash and reflected within financing cash flows in the consolidated statements of cash flows. 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 beginning on 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 standards 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, 2013 or 2012.

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.

15

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 earned on and subsequent to the date of the acquisition 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. Net income attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income per common unit or subordinated unit. See Note 4.

Other assets. For the years ended December 31, 2013 and 2012, other current assets on the consolidated balance sheets includes $0.4 million 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 December 2014. Other assets 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.

Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. These cash receipts are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. See Note 5.

2.  ACQUISITIONS

In May 2008, concurrently with the closing of the Partnership’s IPO, Anadarko contributed to the Partnership the assets and liabilities of Anadarko Gathering Company LLC, Pinnacle Gas Treating LLC, and MIGC LLC. In December 2008, the Partnership 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. In July 2009, the Partnership closed on the acquisition of a 51% membership interest in Chipeta from Anadarko. The Partnership closed the acquisitions of Anadarko’s Granger and Wattenberg assets in January 2010 and August 2010, respectively. In September 2010, the Partnership acquired a 10% interest in White Cliffs. See Note 12.

16

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.  ACQUISITIONS (CONTINUED)

The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2011, 2012 and 2013, 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
Platte Valley (1)	02/28/2011	100	%	$	303,000	$	602	—	—
Bison (2)	07/08/2011	100	%	—		25,000		2,950,284	60,210
MGR (3)	01/13/2012	100	%	299,000		159,587		632,783	12,914
Chipeta (4)	08/01/2012	24	%	—		128,250		151,235	3,086
Non-Operated Marcellus Interest(5)	03/01/2013	33.75	%	250,000		215,500		449,129	—
Anadarko-Operated Marcellus Interest(6)	03/08/2013	33.75	%	133,500		—		—	—
Mont Belvieu JV(7)	06/05/2013	25	%	—		78,129		—	—
OTTCO(8)	09/03/2013	100	%	27,500		—		—	—

⁽¹⁾  The Partnership acquired (i) a natural gas gathering system and related compression and other ancillary equipment and (ii) cryogenic gas processing facilities from a third party. These assets are located in the Denver-Julesburg Basin. The acquisition is referred to as the “Platte Valley acquisition.”

⁽²⁾  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.” 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.

⁽³⁾  The assets acquired from Anadarko consisted 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.”

⁽⁴⁾  The Partnership acquired Anadarko’s additional Chipeta interest (as described in Note 1). The Partnership received 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.

⁽⁵⁾  The Partnership acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in the Partnership.

⁽⁶⁾  The Partnership acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Anadarko-Operated Marcellus Interest acquisition below for further information, including the final allocation of the purchase price.

⁽⁷⁾  The Partnership acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See Mont Belvieu JV acquisition below for further information.

⁽⁸⁾  The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.

17

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.  ACQUISITIONS (CONTINUED)

Anadarko-Operated Marcellus Interest acquisition. The Anadarko-Operated Marcellus Interest acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Anadarko-Operated Marcellus Interest were included in the Partnership’s consolidated statements of income beginning on the acquisition date in the first quarter of 2013.

The following is the final allocation of the purchase price, including $1.1 million of post-closing purchase price adjustments, to the assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition as of the acquisition date:

thousands
Property, plant and equipment	$	134,819
Asset retirement obligations	(174		)
Total purchase price	$	134,645

The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition. The fair values of the interests in the land, right-of-way contracts, and gathering systems were based on the market and income approaches. 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.

The following table presents pro forma condensed financial information of the Partnership as if the Anadarko-Operated Marcellus Interest acquisition had occurred on January 1, 2012:

	Year Ended December 31,
thousands except per-unit amounts	2013		2012
Revenues	$	1,031,017	$	899,353
Net income	285,591		147,238
Net income attributable to Western Gas Partners, LP	274,775		132,348
Net income per common unit - basic and diluted	$	1.82	$	0.82

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Anadarko-Operated Marcellus Interest acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s pro forma information in the table above includes $14.1 million of revenues and $0.7 million of operating expenses, excluding depreciation, amortization and impairments, attributable to the Anadarko-Operated Marcellus Interest that are included in the Partnership’s consolidated statement of income for the year ended December 31, 2013. The pro forma adjustments reflect pre-acquisition results of the Anadarko-Operated Marcellus Interest including (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the purchase price allocated to property, plant and equipment and estimated useful lives; and (c) interest on the Partnership’s borrowings under its revolving credit facility to finance the Anadarko-Operated Marcellus Interest acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the Anadarko-Operated Marcellus Interest acquisition, nor any future acquisition related expenses.

18

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.  ACQUISITIONS (CONTINUED)

Mont Belvieu JV acquisition. The acquisition purchase price represented the Partnership’s 25% share of construction costs incurred by the joint venture partner and 25% of the capitalized interest charged to the financial statements of the Mont Belvieu JV up to the date of acquisition. The allocated capitalized interest is reflected as a component of the equity investment balance recorded upon acquisition. Based on the total estimated net project cost, the construction of the fractionation facilities owned by the Mont Belvieu JV is considered a significant project and satisfies criteria for capitalization of interest. Capitalization of interest subsequent to the acquisition is treated as a basis difference between the cost of the investment and the underlying equity in the net assets of the Mont Belvieu JV. Upon completion of construction in the fourth quarter of 2013, the Partnership began amortizing the capitalized interest recognized subsequent to the Mont Belvieu JV acquisition. This amortization is reflected as an adjustment to equity earnings from the Mont Belvieu JV.

TEFR Interests Acquisition. On March 3, 2014, the Partnership acquired Anadarko’s 20% interest in TEP and TEG, and a 33.33% interest in FRP (collectively, the “TEFR Interests acquisition”) for $375.0 million. The Partnership financed the TEFR Interests acquisition with $6.3 million of cash on hand, borrowings of $350.0 million on the 2014 WES RCF, and the issuance of 308,490 WES common units to Anadarko at an implied price of $60.78 per unit. See Note 12.

Due to Anadarko’s control of the Partnership through its ownership and control of WGP, the acquisition of the TEFR Interests 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 TEFR Interests from 2011 when Anadarko made its initial investment in the respective businesses. The consolidated financial statements for periods prior to the Partnership’s acquisition of the TEFR Interests 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 TEFR Interests during the period reported.

The following table presents the impact of the TEFR Interests on revenue, equity income (loss), net and net income (loss) as presented in the Partnership’s historical consolidated statements of income:

	Year Ended December 31, 2013
thousands	Partnership Historical		TEFR Interests			Combined
Revenues	$	1,029,763	$	—		$	1,029,763
Equity income (loss), net	23,732		(784		)	22,948
Net income (loss)	$	285,952	$	(509	)	$	285,443

	Year Ended December 31, 2012
thousands	Partnership Historical		TEFR Interests			Combined
Revenues	$	894,476	$	—		$	894,476
Equity income (loss), net	16,111		(69		)	16,042
Net income (loss)	$	149,311	$	(44	)	$	149,267

	Year Ended December 31, 2011
thousands	Partnership Historical		TEFR Interests		Combined
Revenues	$	858,144	$	—	$	858,144
Equity income (loss), net	11,261		—		11,261
Net income (loss)	$	206,861	$	—	$	206,861

19

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 board of directors of the general partner declared the following cash distributions to the Partnership’s unitholders for the periods presented:

thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
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	$	0.520	$	65,657	February 2013
2013
March 31	$	0.540	$	70,143	May 2013
June 30	$	0.560	$	79,315	August 2013
September 30	$	0.580	$	83,986	November 2013
December 31 (1)	$	0.600	$	92,609	February 2014

⁽¹⁾  On January 20, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

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.

20

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.  PARTNERSHIP DISTRIBUTIONS (CONTINUED)

General partner interest and incentive distribution rights. The general partner is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. The Partnership’s general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

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

The table above assumes that the Partnership’s general partner maintains its 2.0% general partner interest and that 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 2011, 2012 and 2013:

thousands except unit    and per-unit amounts	Common Units Issued (1)	GP Units Issued(2)	Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
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
May 2013 equity offering	7,015,000	143,163	61.18		13,203		424,733
December 2013 equity offering (3)	4,500,000	91,837	61.51		8,716		273,728

⁽¹⁾  Includes the issuance of 302,813 common units, 750,000 common units and 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.

⁽²⁾  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.

⁽³⁾  Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

21

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

In addition, pursuant to the Partnership’s registration statement filed with the U.S. Securities and Exchange Commission (“SEC”) in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”), during the three months ended December 31, 2013, the Partnership completed trades totaling 642,385 common units at an average price per unit of $60.83, generating gross proceeds of $39.9 million (including the general partner’s proportionate capital contribution and before $0.9 million of associated offering expenses). During the year ended December 31, 2013, the Partnership completed trades totaling 685,735 common units at an average price per unit of $60.84, generating gross proceeds of $42.6 million (including the general partner’s proportionate capital contribution and before $1.0 million of associated offering expenses).

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

The following table summarizes common and general partner units issued during the years ended December 31, 2012 and 2013:

	Common Units	General Partner Units	Total
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
Non-Operated Marcellus Interest acquisition	449,129	9,166	458,295
Long-Term Incentive Plan awards	12,395	253	12,648
May 2013 equity offering	7,015,000	143,163	7,158,163
Continuous Offering Program	685,735	13,996	699,731
December 2013 equity offering	4,500,000	91,837	4,591,837
Balance at December 31, 2013	117,322,812	2,394,345	119,717,157

Holdings of Partnership equity. As of December 31, 2013, WGP held 49,296,205 common units, representing a 41.2% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,394,345 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the Partnership’s IDRs. As of December 31, 2013, Anadarko Marcellus Midstream, L.L.C. (“AMM”), a subsidiary of Anadarko, separately held 449,129 common units, representing a 0.4% limited partner interest in the Partnership. As of December 31, 2013, the public held 67,577,478 common units, representing a 56.4% limited partner interest in the Partnership.

The Partnership’s net income earned on and subsequent to the date of the acquisition of the Partnership assets (as defined in Note 1) 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.

Net income per unit for common and subordinated units. 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.

22

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	2013			2012			2011
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Pre-acquisition net (income) loss allocated to Anadarko	(4,128		)	(27,391		)	(52,599		)
General partner interest in net (income) loss	(69,633		)	(28,089		)	(8,599		)
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Net income allocable to common units	$	200,866		$	78,897		$	110,542
Net income allocable to subordinated units	—			—			21,018
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Net income per unit – basic and diluted
Common units	$	1.83		$	0.84		$	1.64
Subordinated units	$	—		$	—		$	1.28
Weighted average units outstanding – basic and diluted
Common units	109,872			93,936			67,333
Subordinated units	—			—			16,431

Supplemental net income per unit for common and subordinated units. The following table sets forth the calculation of net income per common unit, if net income attributable to the Partnership’s assets (as defined in Note 1) acquired from Anadarko had been allocated to the limited partners for purposes of calculating net income per common and subordinated unit.

	Year Ended December 31,
thousands except per-unit amounts	2013			2012			2011
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Add: Pre-acquisition net income (loss) allocated to Anadarko	4,128			27,391			52,599
Add: General partner interest in net income (loss)	69,633			28,089			8,599
Less: Reallocation of general partner interest in net (income) loss	(69,717		)	(28,636		)	(9,650		)
Supplemental limited partners’ interest in net income	$	204,910		$	105,741		$	183,108
Net income allocable to common units	$	204,910		$	105,741		$	156,132
Net income allocable to subordinated units	—			—			26,976
Limited partners’ interest in net income	$	204,910		$	105,741		$	183,108
Supplemental net income per unit - basic and diluted
Common units	$	1.86		$	1.13		$	2.32
Subordinated units	$	—		$	—		$	1.64
Weighted average units outstanding - basic and diluted
Common units	109,872			93,936			67,333
Subordinated units	—			—			16,431

23

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES

Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue, 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’ separate bank accounts is generally swept to centralized accounts. Prior to the Partnership’s acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged or credited the Partnership interest at a variable rate on outstanding affiliate balances for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to 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. Concurrently 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 $296.7 million and $334.8 million at December 31, 2013 and 2012, 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 4.000% Senior Notes due 2022. See Note 10.

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the 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 2013, the Partnership extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2014. 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.

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of December 31, 2013 excluding the Hilight and Newcastle assets:

per barrel except natural gas	2014					2015					2016
Ethane	$	18.36	−	$	30.53	$	18.41	−	$	23.41	$	23.11
Propane	$	46.47	−	$	53.78	$	47.08	−	$	52.99	$	52.90
Isobutane	$	61.24	−	$	75.13	$	62.09	−	$	74.02	$	73.89
Normal butane	$	53.89	−	$	66.01	$	54.62	−	$	65.04	$	64.93
Natural gasoline	$	71.85	−	$	83.04	$	72.88	−	$	81.82	$	81.68
Condensate	$	75.22	−	$	83.04	$	76.47	−	$	81.82	$	81.68
Natural gas (per MMBtu)	$	4.45	−	$	6.20	$	4.66	−	$	5.96	$	4.87

24

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Below is a summary of the fixed prices or ranges on the Partnership’s outstanding commodity price swap agreements for the Hilight and Newcastle assets as of December 31, 2013:

per barrel except natural gas	2014
Propane				$	40.38
Normal butane	$	64.73	−	$	66.83
Natural gasoline				$	90.89
Condensate				$	87.30
Natural gas (per MMBtu)				$	3.45

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

	Year Ended December 31,
thousands	2013			2012			2011
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	21,382		$	37,665		$	33,845
Natural gas liquids sales	102,076			66,260			(36,802		)
Total	123,458			103,925			(2,957		)
Losses on commodity price swap agreements related to purchases (2)	(85,294		)	(89,710		)	(27,234		)
Net gains (losses) on commodity price swap agreements	$	38,164		$	14,215		$	(30,191	)

⁽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. For the years ended December 31, 2013, 2012 and 2011, 57%, 64% and 67%, respectively, of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) was attributable to natural gas production owned or controlled by Anadarko. For the years ended December 31, 2013, 2012 and 2011, 56%, 59% and 64%, respectively, of the Partnership’s processing throughput (excluding equity investment throughput and volumes measured in barrels) was attributable to natural gas production owned or controlled by Anadarko.

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

Omnibus agreement. Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing; and midstream administration. Anadarko, in accordance with the partnership and omnibus agreements, determines, in its reasonable discretion, amounts to be reimbursed by the Partnership in exchange for services provided under the omnibus agreement. See Summary of affiliate transactions below.

25

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

The following table summarizes the amounts the Partnership reimbursed to Anadarko:

	Year Ended December 31,
thousands	2013		2012		2011
General and administrative expenses	$	16,882	$	14,904	$	11,754
Public company expenses	7,152		6,830		7,735
Total reimbursement	$	24,034	$	21,734	$	19,489

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 beginning on 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.

26

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

WES LTIP. The general partner awards phantom units under the WES LTIP primarily to its independent directors and its Chief Executive Officer. 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 $0.6 million, $0.4 million and $0.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, there was $0.6 million of unrecognized compensation expense attributable to the outstanding awards under the WES LTIP, of which $0.5 million will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 1.4 years.

The following table summarizes WES LTIP award activity for the years ended December 31, 2013, 2012 and 2011:

	2013				2012				2011
	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	$	41.77	25,619		$	33.92	23,978		$	20.19	17,503
Vested	$	41.28	(14,695	)	$	33.20	(14,260	)	$	20.51	(15,119	)
Granted	$	62.49	5,920		$	45.91	15,901		$	35.66	21,594
Phantom units outstanding at end of year	$	49.47	16,844		$	41.77	25,619		$	33.92	23,978

WGP LTIP and Anadarko Incentive Plans. For the years ended December 31, 2013, 2012 and 2011, the Partnership’s general and administrative expenses included $3.0 million, $3.3 million and $2.5 million, respectively, of equity-based compensation expense, allocated to the Partnership by WGP and Anadarko, for awards granted to the executive officers of the general partner and other employees under the WGP LTIP and Anadarko Incentive Plans. Of these amounts, $2.9 million, $3.2 million and $1.0 million are reflected as a contribution to partners’ capital in the Partnership’s consolidated statements of equity and partners’ capital for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, the Partnership estimated that $5.5 million of unrecognized compensation expense attributable to the WGP LTIP and the Anadarko Incentive Plans (excluding performance-based awards) will be allocated to the Partnership over a weighted-average period of 2.1 years.

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

27

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

The Incentive Plan. For the years ended December 31, 2012 and 2011, the Partnership’s general and administrative expenses included $68.8 million and $11.4 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” (defined below) 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 were valued at $634.00 per UAR.

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

	Year Ended December 31,
	2013		2012		2011		2013		2012		2011
thousands	Purchases						Sales
Cash consideration	$	11,211	$	24,705	$	3,837	$	85	$	760	$	382
Net carrying value	5,309		8,009		1,998		38		393		316
Partners’ capital adjustment	$	5,902	$	16,696	$	1,839	$	47	$	367	$	66

Contributions in aid of construction costs from affiliates. During the fourth quarter of 2013, a subsidiary of Anadarko entered into an aid in construction agreement with the Partnership, whereby the Partnership will construct five receipt-point facilities at the Brasada facility that will serve the Anadarko subsidiary. Such subsidiary will reimburse the Partnership for costs associated with construction of the receipt points. These reimbursements are presented within the investing section of the Partnership’s consolidated statements of cash flows as “Contributions in aid of construction costs from affiliates.”

28

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes affiliate transactions, which include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas:

	Year ended December 31,
thousands	2013		2012		2011
Revenues (1)	$	805,526	$	688,026	$	647,419
Equity income, net	22,948		16,042		11,261
Cost of product (1)	129,045		145,250		83,722
Operation and maintenance (2)	56,435		51,237		51,339
General and administrative (3)	23,354		92,847		33,305
Operating expenses	208,834		289,334		168,366
Interest income, net (4)	16,900		16,900		24,106
Interest expense (5)	—		2,766		4,935
Distributions to unitholders (6)	169,150		98,280		68,039
Contributions from noncontrolling interest owners (7)	—		12,588		16,476
Distributions to noncontrolling interest owners (7)	—		6,528		9,437

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

⁽²⁾  Represents expenses incurred on 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 on 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 The Incentive Plan and WGP LTIP and Anadarko Incentive Plans within this Note 5).

⁽⁴⁾  Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets and the Bison 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⁾  For the year ended December 31, 2012, includes 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 facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

⁽⁶⁾  Represents distributions paid under the partnership agreement.

⁽⁷⁾  As described in Note 2, the Partnership acquired the additional Chipeta interest 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.

29

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	2013			2012			2011
Current income tax expense (benefit)
Federal income tax expense (benefit)	$	(30,176	)	$	(7,576	)	$	15,248
State income tax expense (benefit)	640			(1,843		)	322
Total current income tax expense (benefit)	(29,536		)	(9,419		)	15,570
Deferred income tax expense (benefit)
Federal income tax expense	32,930			22,324			13,075
State income tax expense (benefit)	(1,039		)	7,785			3,505
Total deferred income tax expense	31,891			30,109			16,580
Total income tax expense	$	2,355		$	20,690		$	32,150

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	2013			2012			2011
Income before income taxes	$	287,798		$	169,957		$	239,011
Statutory tax rate	—		%	—		%	—		%
Tax computed at statutory rate	$	—		$	—		$	—
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition	3,090			17,226			29,502
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)	624			2,206			1,984
Texas margin tax expense (benefit)	(1,359		)	1,258			664
Income tax expense	$	2,355		$	20,690		$	32,150
Effective tax rate	1		%	12		%	13		%

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

	December 31,
thousands	2013			2012
Credit carryforwards	$	14		$	14
Net current deferred income tax assets	14			14
Depreciable property	(38,528		)	(47,554		)
Credit carryforwards	527			541
Other	3			(136		)
Net long-term deferred income tax liabilities	(37,998		)	(47,149		)
Total net deferred income tax liabilities	$	(37,984	)	$	(47,135	)

Credit carryforwards, which are available for use on future income tax returns, consist of $0.5 million of state income tax credits that expire in 2026.

30

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:

		December 31,
thousands	Estimated Useful Life	2013		2012
Land	n/a	$	2,584	$	501
Gathering systems	3 to 47 years	3,673,008		2,911,572
Pipelines and equipment	15 to 45 years	146,008		91,126
Assets under construction	n/a	405,633		422,002
Other	3 to 40 years	11,867		7,191
Total property, plant and equipment		4,239,100		3,432,392
Accumulated depreciation		855,845		714,436
Net property, plant and equipment		$	3,383,255	$	2,717,956

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 2013, the Partnership recognized a $1.2 million impairment primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest.

During 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 and an impairment of $0.6 million for the original installation costs on a compressor relocated within the Partnership’s operating assets.

During 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. Also during 2011, following an evaluation of estimated 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.

8.  COMPONENTS OF WORKING CAPITAL

A summary of other current assets is as follows:

	December 31,
thousands	2013		2012
Natural gas liquids inventory	$	2,584	$	1,678
Natural gas imbalance receivables	3,605		1,663
Prepaid insurance	2,123		1,897
Other	1,710		1,760
Total other current assets	$	10,022	$	6,998

31

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8.  COMPONENTS OF WORKING CAPITAL (CONTINUED)

A summary of accrued liabilities is as follows:

	December 31,
thousands	2013		2012
Accrued capital expenditures	$	94,750	$	112,311
Accrued plant purchases	21,396		16,350
Accrued interest expense	18,119		15,868
Short-term asset retirement obligations	1,966		1,711
Short-term remediation and reclamation obligations	562		799
Other	218		612
Total accrued liabilities	$	137,011	$	147,651

9.  ASSET RETIREMENT OBLIGATIONS

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

	Year Ended December 31,
thousands	2013			2012
Carrying amount of asset retirement obligations at beginning of year	$	66,723		$	64,345
Liabilities incurred	14,143			9,414
Liabilities settled	(1,943		)	(786		)
Accretion expense	4,326			4,270
Revisions in estimated liabilities	(5,214		)	(10,520		)
Carrying amount of asset retirement obligations at end of year	$	78,035		$	66,723

Revisions in estimated liabilities for the year ended December 31, 2013, 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, 2013, represented the increase in the capital expansion at the Wattenberg and Hilight systems and the June 2013 completion of the Brasada facility.

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.

32

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt as of December 31, 2013 and 2012:

	December 31, 2013						December 31, 2012
thousands	Principal		Carrying Value		Fair Value(1)		Principal		Carrying Value		Fair Value (1)
4.000% Senior Notes due 2022	$	670,000	$	673,278	$	641,237	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021	500,000		495,173		533,615		500,000		494,661		499,946
2.600% Senior Notes due 2018	250,000		249,718		247,988		—		—		—
Total debt outstanding	$	1,420,000	$	1,418,169	$	1,422,840	$	1,170,000	$	1,168,278	$	1,169,874

⁽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, 2013 and 2012:

thousands	Carrying Value
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	4,100
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings	710,000
Repayments of revolving credit facility	(710,000		)
Issuance of 2.600% Senior Notes due 2018	250,000
Other	(109		)
Balance as of December 31, 2013	$	1,418,169

Senior Notes. In August 2013, the Partnership completed the offering of $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018 (the “2018 Notes”) at a price to the public of 99.879% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2018 Notes is 2.806%. Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $1.5 million, original issue discount and debt issuance costs) were used to repay amounts then outstanding under the Partnership’s $800.0 million senior unsecured revolving credit facility (“RCF”).

The 2018 Notes mature on August 15, 2018, unless earlier redeemed. The Partnership may redeem the 2018 Notes in whole or in part, at any time before July 15, 2018, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2018 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2018 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 2018 Notes) plus 20 basis points, plus, in either case, accrued and unpaid interest to such redemption date, if any, on the principal amount being redeemed. On or after July 15, 2018, the 2018 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 2018 Notes to be redeemed, plus accrued interest on the 2018 Notes to be redeemed to the date of redemption.

33

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022. In October 2012, the Partnership issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022. The October 2012 notes and the June 2012 notes were issued under the same indenture and are considered a single class of securities, collectively referred to as the “2022 Notes.”

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”). The indentures governing the 2021 Notes, the 2022 Notes, and the 2018 Notes contain customary events of default. At December 31, 2013, the Partnership was in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes, and the 2018 Notes.

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.

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 2.82% prior to June 2012 when the note payable to Anadarko was repaid in full with proceeds from the June 2012 offering 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. At December 31, 2013 and 2012, the interest rate on the RCF was 1.67% and 1.71%, 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, 2013 and 2012. See Note 12.

As of December 31, 2013, the Partnership had no outstanding borrowings, $12.8 million in outstanding letters of credit issued and $787.2 million available for borrowing under the RCF. At December 31, 2013, the Partnership was in compliance with all covenants under the RCF.

The 2021 Notes, the 2022 Notes, the 2018 Notes and obligations under the RCF are recourse to the Partnership’s general partner. The Partnership’s general partner is indemnified by a wholly owned subsidiary of Anadarko, WGRI, against any claims made against the general partner under the 2022 Notes, the 2021 Notes, and/or the RCF. See Note 2 and Note 12 for a discussion of amendments to the RCF and borrowing activity under the new RCF in March 2014, related to acquisitions which closed after December 31, 2013.

34

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

In connection with the acquisition of the Non-Operated Marcellus Interest in March 2013, the general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary agreed to indemnify the Partnership’s general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. The 2013 Indemnification Agreement applies to the 2018 Notes. The Partnership’s general partner and WGRI also amended and restated the existing indemnity agreement between them to reduce the amount for which WGRI would indemnify the Partnership’s general partner by an amount equal to any amounts payable to the Partnership’s general partner under the 2013 Indemnification Agreement. See Note 12.

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 London Interbank Offered Rate (“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 expense. The following table summarizes the amounts included in interest expense:

	Year Ended December 31,
thousands	2013			2012			2011
Third parties
Interest expense on long-term debt	$	59,293		$	41,171		$	20,533
Amortization of debt issuance costs and commitment fees (1)	4,449			4,319			5,297
Capitalized interest	(11,945		)	(6,196		)	(420		)
Total interest expense – third parties	51,797			39,294			25,410
Affiliates
Interest expense on note payable to Anadarko (2)	—			2,440			4,935
Interest expense on affiliate balances (3)	—			326			—
Total interest expense – affiliates	—			2,766			4,935
Interest expense	$	51,797		$	42,060		$	30,345

⁽¹⁾  For the years ended December 31, 2013 and 2012, includes $1.0 million and $1.1 million, respectively, of amortization of (i) the original issue discount for the June 2012 offering of the 2022 Notes, 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. In addition, for the year ended December 31, 2013, includes the amortization of the original issue discount and underwriters’ fees for the 2018 Notes of $0.2 million. 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⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

⁽³⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant.

35

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2013 and 2012, asset retirement obligations and other on the consolidated balance sheets included a $1.9 million long-term liability for remediation and reclamation obligations. The recorded obligations do not include any anticipated insurance recoveries. The majority of 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 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, 2013, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of $47.1 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 Lancaster plant and an expansion project at the Fort Lupton compressor station in the Wattenberg system.

36

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.  COMMITMENTS AND CONTINGENCIES (CONTINUED)

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.

Rent expense associated with the office, warehouse and equipment leases was $2.8 million, $3.0 million and $4.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2013, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:

thousands	Operating Leases
2014	$	309
2015	245
2016	233
2017	157
2018	34
Thereafter	—
Total	$	978

12.  SUBSEQUENT EVENTS

Effective February 12, 2014, Anthony R. Chase resigned as a director of the Partnership’s general partner due to his appointment to the board of directors of Anadarko. In connection with his resignation and in recognition of his service, the board of directors of the Partnership’s general partner accelerated the vesting of 1,280 phantom units held by Mr. Chase. Also effective February 12, 2014, Steven D. Arnold was appointed to the board of directors as an independent director and member of the audit committee and special committee of the board of directors.

On February 26, 2014, the Partnership entered into a five-year senior unsecured revolving credit agreement (the “2014 RCF”), amending and restating the RCF, which was originally entered into in March 2011 and had an outstanding balance of $60.0 million immediately prior to closing on the 2014 RCF. The aggregate initial commitments of the 2014 RCF lenders are $1.2 billion and are expandable to a maximum of $1.5 billion. The 2014 RCF matures on February 26, 2019, and bears interest at LIBOR, plus applicable margins ranging from 0.975% to 1.45%, 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 zero to 0.45%, based upon the Partnership’s senior unsecured debt rating. The Partnership is required to pay a quarterly facility fee ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), also based upon its senior unsecured debt rating. As of February 26, 2014, there was $60.0 million outstanding on the 2014 RCF, drawn to repay amounts that were outstanding on the RCF upon entering into the 2014 RCF.

Refer to Note 2 for a description of the TEFR Interests acquisition on March 3, 2014. In connection with the TEFR Interests acquisition, the Partnership’s general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “TEFR Indemnification Agreement”) whereby such subsidiary will indemnify the Partnership’s general partner for any recourse liability it may have for 2014 RCF borrowings, or other debt financing, attributable to the TEFR Interests acquisition. The Partnership’s general partner and WGRI also amended and restated the existing indemnity agreement between them (as discussed in Note 10) to reduce the amount for which WGRI would indemnify the Partnership’s general partner by an amount equal to any amounts payable to the Partnership’s general partner under the TEFR Indemnification Agreement. The Partnership’s general partner and another wholly owned subsidiary of Anadarko also amended and restated the 2013 Indemnification Agreement (as discussed in Note 10) primarily to conform language among all the indemnity agreements with the Partnership’s general partner.

37

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, 2013 and 2012. The Partnership’s operating results reflect the operations of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies) from the dates of common control, unless otherwise noted, and have been recast to include results attributable to the TEFR Interests, as applicable. See Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitionsin 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
2013
Revenues	$	225,766	$	251,402	$	273,502	$	279,093
Equity income	$	3,968	$	3,456	$	4,520	$	11,004
Operating income	$	64,023	$	69,859	$	90,209	$	96,767
Net income	$	52,945	$	61,876	$	81,882	$	88,740
Net income attributable to Western Gas Partners, LP	$	50,714	$	60,016	$	78,506	$	85,391
Net income per common unit – basic and diluted (1)	$	0.31	$	0.41	$	0.53	$	0.56
2012
Revenues	$	221,063	$	216,975	$	230,931	$	225,507
Equity income	$	3,617	$	3,331	$	3,758	$	5,336
Operating income (2)	$	67,225	$	59,276	$	61,267	$	7,057
Net income (loss) (2)	$	57,897	$	47,596	$	49,958	$	(6,184	)
Net income (loss) attributable to Western Gas Partners, LP (2)	$	53,655	$	43,307	$	46,533	$	(9,118	)
Net income (loss) per common unit – basic and diluted (1) (2)	$	0.48	$	0.33	$	0.33	$	(0.27	)

⁽¹⁾  Represents net income earned on and subsequent to the acquisition of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K).

⁽²⁾  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 Affiliatesin the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K).

38

XML

Acquisitions - Purchase Price Allocation Table (details) (Anadarko-Operated Marcellus Interest [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Anadarko-Operated Marcellus Interest [Member]
Business Acquisition [Line Items]
Property, plant and equipment	$ 134,819
Asset retirement obligations	(174)
Total purchase price	$ 134,645

XML

Transactions With Affiliates - LTIP Award Activity Table (details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Phantom units outstanding at beginning of year	25,619	23,978	17,503
Vested	(14,695)	(14,260)	(15,119)
Granted	5,920	15,901	21,594
Phantom units outstanding at end of year	16,844	25,619	23,978
Value Per Unit of Phantom Units Oustanding	$ 49.47	$ 41.77	$ 33.92	$ 20.19
Value Per Unit of Phantom Units Vested during the Period	$ 41.28	$ 33.20	$ 20.51
Value Per Unit of Phantom Units Granted during the Period	$ 62.49	$ 45.91	$ 35.66

XML

Equity and Partners' Capital - Calculation of Net Income Per Unit Table (details) (USD $) Share data in Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Earnings Per Unit [Line Items]
Net income attributable to Western Gas Partners, LP	$ 274,627,000	[1]	$ 134,377,000	[1]	$ 192,758,000	[1]
Pre-acquisition net (income) loss allocated to Anadarko	(4,128,000)	[1]	(27,391,000)	[1]	(52,599,000)	[1]
General partner interest in net (income) loss	69,633,000	[1],[2]	28,089,000	[1],[2]	8,599,000	[1],[2]
Limited partners' interest in net income	200,866,000	[1],[2]	78,897,000	[1],[2]	131,560,000	[1],[2]
Common Units [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	200,866,000		78,897,000		110,542,000
Common Units [Member] | Limited Partner [Member]
Earnings Per Unit [Line Items]
Net income per common unit - basic and diluted	$ 1.83	[1]	$ 0.84	[1]	$ 1.64	[1]
Weighted average units outstanding - basic and diluted	109,872		93,936		67,333
Subordinated [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	$ 0		$ 0		$ 21,018,000
Subordinated [Member] | Limited Partner [Member]
Earnings Per Unit [Line Items]
Net income per common unit - basic and diluted	$ 0	[1],[3]	$ 0	[1],[3]	$ 1.28	[1],[3]
Weighted average units outstanding - basic and diluted	0		0		16,431

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Represents net income earned on and subsequent to the date of 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.

XML

Debt and Interest Expense - Additional Information (details) (USD $)			1 Months Ended	12 Months Ended		1 Months Ended			12 Months Ended		12 Months Ended				1 Months Ended	12 Months Ended			12 Months Ended			1 Months Ended	12 Months Ended		1 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012 Revolving Credit Facility [Member]	Dec. 31, 2013 Revolving Credit Facility [Member]	Oct. 31, 2009 Revolving Credit Facility [Member]	Mar. 31, 2011 Minimum [Member] Revolving Credit Facility [Member]	Mar. 31, 2011 Maximum [Member] Revolving Credit Facility [Member]	Aug. 31, 2013 Senior Notes 2 Point 6 Percent Due 2018 [Member]	Dec. 31, 2013 Senior Notes 2 Point 6 Percent Due 2018 [Member]	Dec. 31, 2012 Senior Notes 2 Point 6 Percent Due 2018 [Member]	Dec. 31, 2013 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]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member] Interest Rate Swap [Member]	Dec. 31, 2013 Senior Notes 5 Point 375 Percent Due 2021 [Member]	Dec. 31, 2012 Senior Notes 5 Point 375 Percent Due 2021 [Member]	May 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member]	Dec. 31, 2013 Note Payable To Anadarko [Member]	Dec. 31, 2010 Note Payable To Anadarko [Member]	Dec. 31, 2008 Note Payable To Anadarko [Member]	Mar. 31, 2011 Wattenberg Term Loan [Member]	Dec. 31, 2013 Wattenberg Term Loan [Member]	Aug. 31, 2010 Wattenberg Term Loan [Member]	Aug. 31, 2010 Wattenberg Term Loan [Member] Minimum [Member]	Aug. 31, 2010 Wattenberg Term Loan [Member] Maximum [Member]	May 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member] Interest Rate Swap [Member]	Dec. 31, 2013 US Treasury Securities [Member] Senior Notes 2 Point 6 Percent Due 2018 [Member]
Debt Instrument [Line Items]
Principal	$ 1,420,000,000	$ 1,170,000,000						$ 250,000,000	$ 250,000,000	$ 0	$ 670,000,000	$ 670,000,000	$ 150,000,000	$ 520,000,000		$ 500,000,000	$ 500,000,000	$ 500,000,000			$ 175,000,000			$ 250,000,000
Fixed interest rate								2.60%					4.00%	4.00%				5.375%		2.82%
Offering percent								99.879%
Effective interest rate								2.806%
Underwriting discount								1,500,000
Debt instrument, maturity date									Aug. 15, 2018		Jul. 01, 2022					Jun. 01, 2021			Aug. 02, 2013				Aug. 02, 2013
Debt instrument, redemption price, percentage									100.00%
Line of credit, expiration date				Mar. 24, 2016
Revolving Credit Facility, maximum borrowing capacity				800,000,000	450,000,000
Interest rate percent above LIBOR																									2.50%	3.50%		20.00%
Revolving Credit Facility, interest rate at period end			1.71%	1.67%
Facility fee			0.25%	0.25%		0.20%	0.35%
Outstanding borrowings				0
Outstanding letters of credit				12,800,000
Available borrowing capacity				787,200,000
Accelerated amortization expense																						1,300,000
Realized loss on terminated swap agreement															$ 1,700,000												$ 1,900,000

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Transactions With Affiliates - Equipment Purchase and Sale Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Partners' capital adjustment	$ 345	$ 3,065	$ (314)
Purchases [Member]
Related Party Transaction [Line Items]
Partners' capital adjustment	5,902	16,696	1,839
Sales [Member]
Related Party Transaction [Line Items]
Partners' capital adjustment	47	367	66
Affiliated Entity [Member] | Purchases [Member]
Related Party Transaction [Line Items]
Consideration given for equipment	11,211	24,705	3,837
Net carrying value	5,309	8,009	1,998
Affiliated Entity [Member] | Sales [Member]
Related Party Transaction [Line Items]
Consideration received for equipment	85	760	382
Net carrying value	$ 38	$ 393	$ 316

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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		1 Months Ended
	Dec. 31, 2013		May 31, 2013	Jun. 30, 2012	Sep. 30, 2011	Mar. 31, 2011	Dec. 31, 2013		Dec. 31, 2013 Common Units [Member]		May 31, 2013 Common Units [Member]		Jun. 30, 2012 Common Units [Member]		Sep. 30, 2011 Common Units [Member]		Mar. 31, 2011 Common Units [Member]		May 31, 2013 Common Units [Member] Option On Securities [Member]	Sep. 30, 2011 Common Units [Member] Option On Securities [Member]	Mar. 31, 2011 Common Units [Member] Option On Securities [Member]	Dec. 31, 2013 General Partner [Member]		May 31, 2013 General Partner [Member]		Jun. 30, 2012 General Partner [Member]		Sep. 30, 2011 General Partner [Member]		Mar. 31, 2011 General Partner [Member]		Jan. 31, 2014 Subsequent Event [Member]	Jan. 31, 2014 Subsequent Event [Member] Common Units [Member] Option On Securities [Member]	Jan. 31, 2014 Subsequent Event [Member] General Partner [Member]
Capital Unit [Line Items]
Common units issued									4,500,000	[1],[2]	7,015,000	[1]	5,000,000	[1]	5,750,000	[1]	3,852,813	[1]	915,000	750,000	302,813												300,000
General partner units issued																						91,837	[2],[3]	143,163	[3]	102,041	[3]	117,347	[3]	78,629	[3]			6,122
Price per unit	$ 61.51	[2]	$ 61.18	$ 43.88	$ 35.86	$ 35.15	$ 61.51	[2]
Underwriting discount and other offering expenses	$ 8,716	[2]	$ 13,203	$ 7,468	$ 7,655	$ 5,621	$ 8,716	[2]
Net proceeds	$ 273,728	[2]	$ 424,733	$ 216,409	$ 202,748	$ 132,569																										$ 18,300
Table Text Block Supplement [Abstract]
General partner's interest							2.00%

[1] Includes the issuance of 302,813 common units, 750,000 common units and 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.

[2] Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

[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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Summary of Significant Accounting Policies - Asset Table (details)	Dec. 31, 2013
Gathering System [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	13
Gathering System [Member] | Operated Interest [Member]
Assets [Line Items]
Assets, number of units	1
Gathering System [Member] | Non Operated Interest [Member]
Assets [Line Items]
Assets, number of units	5
Gathering System [Member] | Equity Investments [Member]
Assets [Line Items]
Assets, number of units	2
Natural Gas Liquids Gathering System [Member] | Equity Investments [Member]
Assets [Line Items]
Assets, number of units	2
Natural Gas Treating Facilities [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	8
Natural Gas Treating Facilities [Member] | Equity Investments [Member]
Assets [Line Items]
Assets, number of units	1
Natural Gas Processing Plant [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	8
Natural Gas Processing Plant [Member] | Operated Interest [Member]
Assets [Line Items]
Assets, number of units	3
Natural Gas Processing Plant [Member] | Equity Investments [Member]
Assets [Line Items]
Assets, number of units	2
Natural Gas Liquids Pipeline [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	3
Natural Gas Liquids Pipeline [Member] | Equity Investments [Member]
Assets [Line Items]
Assets, number of units	2
Natural Gas Pipelines [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	3
Oil Pipeline [Member] | Equity Investments [Member]
Assets [Line Items]
Assets, number of units	1

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Subsequent Events (details) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended		1 Months Ended				1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Revolving Credit Facility [Member]	Dec. 31, 2013 Revolving Credit Facility [Member]	Oct. 31, 2009 Revolving Credit Facility [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Minimum [Member]	Mar. 31, 2011 Revolving Credit Facility [Member] Maximum [Member]	Feb. 28, 2014 Subsequent Event [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility 2014 [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility 2014 [Member] Minimum [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility 2014 [Member] Maximum [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility 2014 [Member] Alternate Base Rate [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility 2014 [Member] Alternate Base Rate [Member] Minimum [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility 2014 [Member] Alternate Base Rate [Member] Maximum [Member]	Feb. 28, 2014 Subsequent Event [Member] Revolving Credit Facility 2014 [Member] Alternate Base Rate [Member] Percentage Above Federal Funds Effective Rate [Member]
Subsequent Event [Line Items]
Vested	14,695	14,260	15,119						1,280
Outstanding borrowings					$ 0					$ 60,000,000	$ 60,000,000
Revolving Credit Facility, maximum borrowing capacity					800,000,000	450,000,000					1,200,000,000
Revolving Credit Facility, expandable maximum borrowing capacity											$ 1,500,000,000
Interest rate percent above LIBOR												0.975%	1.45%	1.00%	0.00%	0.45%	0.50%
Facility fee				0.25%	0.25%		0.20%	0.35%				0.15%	0.30%
Line of credit, expiration date					Mar. 24, 2016						Feb. 26, 2019

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Transactions With Affiliates - Additional Information (details) (USD $)	12 Months Ended					1 Months Ended	12 Months Ended		12 Months Ended			12 Months Ended																	12 Months Ended		12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	May 31, 2008 Note Receivable From Anadarko [Member]	Dec. 31, 2013 Note Receivable From Anadarko [Member]	Dec. 31, 2012 Note Receivable From Anadarko [Member]	Dec. 31, 2013 Note Payable To Anadarko [Member]	Dec. 31, 2008 Note Payable To Anadarko [Member]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Dec. 31, 2013 Gathering Transportation And Treating [Member]	Dec. 31, 2012 Gathering Transportation And Treating [Member]	Dec. 31, 2011 Gathering Transportation And Treating [Member]	Dec. 31, 2013 Processing [Member]	Dec. 31, 2012 Processing [Member]	Dec. 31, 2011 Processing [Member]	Dec. 31, 2013 Western Gas Partners Long Term Incentive Plan [Member]	Dec. 31, 2012 Western Gas Partners Long Term Incentive Plan [Member]	Dec. 31, 2011 Western Gas Partners Long Term Incentive Plan [Member]	Dec. 31, 2013 Anadarko Incentive Plans [Member] Western Gas Equity Partners Long Term Incentive Plan [Member]	Dec. 31, 2012 Anadarko Incentive Plans [Member] Western Gas Equity Partners Long Term Incentive Plan [Member]	Dec. 31, 2011 Anadarko Incentive Plans [Member] Western Gas Equity Partners Long Term Incentive Plan [Member]	Dec. 31, 2012 Incentive Plan [Member]	Dec. 31, 2011 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, 2012 Incentive Plan [Member] Distribution Equivalent Right [Member]	Dec. 31, 2013 Independent Director [Member] Western Gas Partners Long Term Incentive Plan [Member]	Dec. 31, 2013 Anadarko [Member] Western Gas Partners Long Term Incentive Plan [Member]	Dec. 31, 2011 Year-End Adjustment [Member] Anadarko Incentive Plans [Member]
Related Party Transaction [Line Items]
Note receivable, due date							May 14, 2038
Note receivable - Anadarko	$ 260,000,000	[1]	$ 260,000,000	[1]		$ 260,000,000
Fixed annual rate for note receivable bearing interest						6.50%
The fair value of the note receivable							296,700,000	334,800,000
Debt instrument, maturity date									Aug. 02, 2013
Principal	1,420,000,000		1,170,000,000							175,000,000
Fixed interest rate											4.00%
Affiliate throughput percent												57.00%	64.00%	67.00%	56.00%	59.00%	64.00%
Phantom units vesting term																		3 years											1 year
Equity based compensation expense																		600,000	400,000	300,000	3,000,000	3,300,000	2,500,000	68,800,000	11,400,000
Unvested equity based compensation																		500,000			5,500,000									600,000
Weighted average term of unvested awards																		1 year 4 months 24 days			2 years 1 month 6 days
Partners' capital adjustment	$ 345,000		$ 3,065,000		$ (314,000)																$ 2,900,000	$ 3,200,000	$ 1,000,000								$ 9,700,000
UVR, UAR and DER Valuation																										$ 2,745.00	$ 634.00	$ 12.00

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Commitments and Contingencies - Operating Lease Obligations Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Commitments and Contingencies [Abstract]
2014	$ 309
2015	245
2016	233
2017	157
2018	34
Thereafter	0
Total	$ 978

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Equity and Partners' Capital (tables)

12 Months Ended

Dec. 31, 2013

Partners' Capital Notes [Abstract]

Equity Offerings Table

The Partnership completed the following public offerings of its common units during 2011, 2012 and 2013:

thousands except unit    and per-unit amounts	Common Units Issued (1)	GP Units Issued(2)	Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
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
May 2013 equity offering	7,015,000	143,163	61.18		13,203		424,733
December 2013 equity offering (3)	4,500,000	91,837	61.51		8,716		273,728

⁽¹⁾  Includes the issuance of 302,813 common units, 750,000 common units and 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.

⁽²⁾  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.

Limited Partner and General Partner Units Table

The following table summarizes common and general partner units issued during the years ended December 31, 2012 and 2013:

	Common Units	General Partner Units	Total
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
Non-Operated Marcellus Interest acquisition	449,129	9,166	458,295
Long-Term Incentive Plan awards	12,395	253	12,648
May 2013 equity offering	7,015,000	143,163	7,158,163
Continuous Offering Program	685,735	13,996	699,731
December 2013 equity offering	4,500,000	91,837	4,591,837
Balance at December 31, 2013	117,322,812	2,394,345	119,717,157

Calculation of Net Income Per Unit Table

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	2013			2012			2011
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Pre-acquisition net (income) loss allocated to Anadarko	(4,128		)	(27,391		)	(52,599		)
General partner interest in net (income) loss	(69,633		)	(28,089		)	(8,599		)
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Net income allocable to common units	$	200,866		$	78,897		$	110,542
Net income allocable to subordinated units	—			—			21,018
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Net income per unit – basic and diluted
Common units	$	1.83		$	0.84		$	1.64
Subordinated units	$	—		$	—		$	1.28
Weighted average units outstanding – basic and diluted
Common units	109,872			93,936			67,333
Subordinated units	—			—			16,431

Supplemental net income per unit for common and subordinated units. The following table sets forth the calculation of net income per common unit, if net income attributable to the Partnership’s assets (as defined in Note 1) acquired from Anadarko had been allocated to the limited partners for purposes of calculating net income per common and subordinated unit.

	Year Ended December 31,
thousands except per-unit amounts	2013			2012			2011
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Add: Pre-acquisition net income (loss) allocated to Anadarko	4,128			27,391			52,599
Add: General partner interest in net income (loss)	69,633			28,089			8,599
Less: Reallocation of general partner interest in net (income) loss	(69,717		)	(28,636		)	(9,650		)
Supplemental limited partners’ interest in net income	$	204,910		$	105,741		$	183,108
Net income allocable to common units	$	204,910		$	105,741		$	156,132
Net income allocable to subordinated units	—			—			26,976
Limited partners’ interest in net income	$	204,910		$	105,741		$	183,108
Supplemental net income per unit - basic and diluted
Common units	$	1.86		$	1.13		$	2.32
Subordinated units	$	—		$	—		$	1.64
Weighted average units outstanding - basic and diluted
Common units	109,872			93,936			67,333
Subordinated units	—			—			16,431

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Equity and Partners' Capital - Additional Information (details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended		12 Months Ended	1 Months Ended											12 Months Ended				3 Months Ended	12 Months Ended		3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Western Gas Equity Partners [Member]	Dec. 31, 2013 Common Units [Member]		May 31, 2013 Common Units [Member]		Jun. 30, 2012 Common Units [Member]		Sep. 30, 2011 Common Units [Member]		Mar. 31, 2011 Common Units [Member]		Dec. 31, 2012 Common Units [Member]	Dec. 31, 2013 Common Units [Member] Western Gas Equity Partners [Member]	Dec. 31, 2013 Common Units [Member] Anadarko Marcellus Midstream [Member]	Dec. 31, 2013 Common Units [Member] Public [Member]	Dec. 31, 2013 Incentive Distribution Rights [Member] Western Gas Equity Partners [Member]	Dec. 31, 2013 Continuous Offering Program [Member]	Dec. 31, 2013 Continuous Offering Program [Member]	Aug. 31, 2012 Continuous Offering Program [Member]	Dec. 31, 2013 Continuous Offering Program [Member] Common Units [Member]	Dec. 31, 2013 Continuous Offering Program [Member] Common Units [Member]
Schedule Of Investments [Line Items]
Maximum aggregate principal of common stock																					$ 125.0
Common units issued				4,500,000	[1],[2]	7,015,000	[1]	5,000,000	[1]	5,750,000	[1]	3,852,813	[1]									642,385	685,735
Average price per unit																			$ 60.83	$ 60.84
Gross proceeds																			39.9	42.6
Offering expenses																			$ 0.9	$ 1.0
Units owned				117,322,812										104,660,553	49,296,205	449,129	67,577,478
Ownership interest															41.20%	0.40%	56.40%
General partner units owned	2,394,345	2,135,930	2,394,345
General partner's interest	2.00%		2.00%															100.00%

[1] Includes the issuance of 302,813 common units, 750,000 common units and 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.

[2] Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

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Acquisitions - Additional Information (details) (USD $)	12 Months Ended						1 Months Ended		12 Months Ended		1 Months Ended	12 Months Ended						1 Months Ended		12 Months Ended						12 Months Ended															3 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Mar. 31, 2013 Anadarko-Operated Marcellus Interest [Member]		Dec. 31, 2013 Anadarko-Operated Marcellus Interest [Member]	Dec. 31, 2013 Anadarko-Operated Marcellus Interest [Member] Purchase Price Allocation Adjustments [Member]	Dec. 31, 2008 Newcastle [Member]	Dec. 31, 2013 Newcastle [Member]	Dec. 31, 2013 Fort Union [Member]		Dec. 31, 2012 Fort Union [Member]		Dec. 31, 2008 Fort Union [Member]	Aug. 31, 2012 Chipeta Processing Limited Liability Company [Member]	Jul. 31, 2009 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2013 White Cliffs [Member]		Dec. 31, 2012 White Cliffs [Member]		Sep. 30, 2010 White Cliffs [Member]	Dec. 31, 2013 Texas Express Pipeline Limited Liability Company [Member]		Dec. 31, 2012 Texas Express Pipeline Limited Liability Company [Member]		Dec. 31, 2013 Texas Express Gathering Limited Liability Company [Member]		Dec. 31, 2012 Texas Express Gathering Limited Liability Company [Member]		Dec. 31, 2013 Front Range Pipeline Limited Liability Company [Member]		Dec. 31, 2012 Front Range Pipeline Limited Liability Company [Member]		Mar. 31, 2014 Subsequent Event [Member] Texas Express Pipeline Limited Liability Company [Member]	Mar. 31, 2014 Subsequent Event [Member] Texas Express Gathering Limited Liability Company [Member]	Mar. 31, 2014 Subsequent Event [Member] Front Range Pipeline Limited Liability Company [Member]	Mar. 31, 2014 Subsequent Event [Member] Texas Express And Front Range [Member]
Business Acquisition [Line Items]
Equity method investment ownership													14.81%				14.81%				10.00%				10.00%	20.00%				20.00%				33.33%				20.00%	20.00%	33.33%
Percentage acquired							33.75%	[1]			50.00%	50.00%						24.00%	51.00%
Revenues	$ 1,029,763,000	[2]	$ 894,476,000	[2]	$ 858,144,000	[2]			$ 14,100,000
Operating expenses	731,853,000	[2]	715,693,000	[2]	624,111,000	[2]			700,000
Purchase price adjustment									134,645,000	1,100,000
Equity method investment cost																																									375,000,000
Cash on hand													0	[3]	0	[3]					0	[4]	0	[4]		0	[5]	0	[5]	0	[6]	9,086,000	[6]	0	[7]	23,878,000	[7]				6,300,000
Borrowings	$ 957,503,000	[2]	$ 1,041,648,000	[2]	$ 1,055,939,000	[2]	$ 133,500,000	[1]																																	$ 350,000,000
Units issued																				154,321																					308,490
Implied price per unit																																									$ 60.78

[1] The Partnership acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Anadarko-Operated Marcellus Interest acquisition below for further information, including the final allocation of the purchase price.

[2] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[3] The Partnership has a 14.81% interest in Fort Union, a joint venture which owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners.

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

[5] The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

[6] The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

[7] The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

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Summary of Significant Accounting Policies - Additional Information (details) (USD $)	12 Months Ended								1 Months Ended	12 Months Ended								12 Months Ended					12 Months Ended		1 Months Ended	12 Months Ended	1 Months Ended		12 Months Ended
	Dec. 31, 2013		May 31, 2013	Dec. 31, 2012		Jun. 30, 2012	Sep. 30, 2011	Mar. 31, 2011	Dec. 31, 2012 Western Gas Equity Partners [Member]	Dec. 31, 2013 Western Gas Equity Partners [Member]	Dec. 31, 2013 Western Gas Equity Partners [Member] Incentive Distribution Rights [Member]	Dec. 31, 2013 Western Gas Partners Long Term Incentive Plan [Member]	Dec. 31, 2013 Fort Union [Member]	Dec. 31, 2008 Fort Union [Member]	Dec. 31, 2013 Rendezvous [Member]	Dec. 31, 2013 White Cliffs [Member]	Sep. 30, 2010 White Cliffs [Member]	Dec. 31, 2013 White Cliffs [Member] Affiliated Entity [Member]	Dec. 31, 2013 MontBelvieuJointVenture [Member]	Dec. 31, 2013 Texas Express Pipeline Limited Liability Company [Member]	Dec. 31, 2013 Texas Express Gathering Limited Liability Company [Member]	Dec. 31, 2013 Front Range Pipeline Limited Liability Company [Member]	Dec. 31, 2013 Non-Operated Marcellus Interest [Member]	Dec. 31, 2013 Anadarko-Operated Marcellus Interest [Member]	Dec. 31, 2008 Newcastle [Member]	Dec. 31, 2013 Newcastle [Member]	Aug. 31, 2012 Chipeta Processing Limited Liability Company [Member]	Jul. 31, 2009 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2013 Chipeta Processing Limited Liability Company [Member]
Equity method investment ownership													14.81%	14.81%	22.00%	10.00%	10.00%		25.00%	20.00%	20.00%	33.33%
Common units issued									19,758,150
Price per unit	$ 61.51	[1]	$ 61.18			$ 43.88	$ 35.86	$ 35.15	$ 22.00
Proceeds From Issuance of Private Placement									$ 409,400,000
General partner's interest	2.00%									2.00%	100.00%
Ownership interest										100.00%								0.40%					33.75%	33.75%	50.00%	50.00%	24.00%	51.00%
Ownership interest by noncontrolling owners																													25.00%
Bad-debt reserve	13,000			0
Natural gas imbalance receivable	3,600,000			1,700,000
Natural gas imbalance payable	2,500,000			3,100,000
Goodwill	105,336,000	[2]		105,336,000	[2]
Goodwill, Impairment Loss	0
Straight-line basis of amortization	50 years																												10 years
Carrying value of intangible assets	53,606,000	[2]		55,490,000	[2]
Accumulated amortization of customer relationship intangible assets	3,400,000			2,000,000
Estimated future amortization	1,400,000
Equity method investment difference between carrying and underlying value													2,500,000		44,000,000	(9,300,000)
Units authorized under LTIP												2,250,000
Units available under LTIP												2,139,027
Capital lease receivable	400,000			400,000
Unguaranteed residual value	$ 4,600,000

[1] Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

[2] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Transactions With Affiliates - Gains Losses Commodity Price Swap Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ 38,164		$ 14,215		$ (30,191)
Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	123,458	[1]	103,925	[1]	(2,957)	[1]
Cost Of Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	(85,294)	[2]	(89,710)	[2]	(27,234)	[2]
Natural Gas Per Thousand Cubic Feet [Member] | Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	21,382	[1]	37,665	[1]	33,845	[1]
Natural Gas Liquids [Member] | Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ 102,076	[1]	$ 66,260	[1]	$ (36,802)	[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.

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Debt and Interest Expense - Debt Outstanding Table (details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2013 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]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Dec. 31, 2013 Senior Notes 5 Point 375 Percent Due 2021 [Member]		Dec. 31, 2012 Senior Notes 5 Point 375 Percent Due 2021 [Member]		May 31, 2011 Senior Notes 5 Point 375 Percent Due 2021 [Member]	Dec. 31, 2013 Senior Notes 2 Point 6 Percent Due 2018 [Member]		Aug. 31, 2013 Senior Notes 2 Point 6 Percent Due 2018 [Member]	Dec. 31, 2012 Senior Notes 2 Point 6 Percent Due 2018 [Member]
Debt Instrument [Line Items]
Principal	$ 1,420,000,000		$ 1,170,000,000			$ 670,000,000		$ 670,000,000		$ 150,000,000	$ 520,000,000	$ 500,000,000		$ 500,000,000		$ 500,000,000	$ 250,000,000		$ 250,000,000	$ 0
Carrying Value	1,418,169,000	[1]	1,168,278,000	[1]	669,178,000	673,278,000		673,617,000				495,173,000		494,661,000			249,718,000			0
Fair Value	$ 1,422,840,000	[2]	$ 1,169,874,000	[2]		$ 641,237,000	[2]	$ 669,928,000	[2]			$ 533,615,000	[2]	$ 499,946,000	[2]		$ 247,988,000	[2]		$ 0	[2]

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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

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Income Taxes - Additional Information (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Credit carryforwards	$ 527	$ 541
Tax credit carryforward, expiration date	Dec. 31, 2026

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Equity and Partners' Capital - Limited Partner and General Partner Units (details)	12 Months Ended										1 Months Ended										12 Months Ended								3 Months Ended	12 Months Ended		1 Months Ended										12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012 Mountain Gas Resources [Member]	Dec. 31, 2012 June 2012 Equity Offering [Member]	Dec. 31, 2012 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Western Gas Equity Partners [Member]	Dec. 31, 2013 Non-Operated Marcellus Interest [Member]	Dec. 31, 2013 May 2013 Equity Offering [Member]	Dec. 31, 2013 Continuous Offering Program [Member]	Dec. 31, 2013 December 2013 Equity Offering [Member]	Dec. 31, 2013 Common Units [Member]		May 31, 2013 Common Units [Member]		Jun. 30, 2012 Common Units [Member]		Sep. 30, 2011 Common Units [Member]		Mar. 31, 2011 Common Units [Member]		Dec. 31, 2013 Common Units [Member]	Dec. 31, 2012 Common Units [Member]	Dec. 31, 2012 Common Units [Member] Mountain Gas Resources [Member]	Dec. 31, 2012 Common Units [Member] June 2012 Equity Offering [Member]	Dec. 31, 2012 Common Units [Member] Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Common Units [Member] Western Gas Equity Partners [Member]	Dec. 31, 2013 Common Units [Member] Non-Operated Marcellus Interest [Member]	Dec. 31, 2013 Common Units [Member] May 2013 Equity Offering [Member]	Dec. 31, 2013 Common Units [Member] Continuous Offering Program [Member]	Dec. 31, 2013 Common Units [Member] Continuous Offering Program [Member]	Dec. 31, 2013 Common Units [Member] December 2013 Equity Offering [Member]	Dec. 31, 2013 General Partner [Member]		May 31, 2013 General Partner [Member]		Jun. 30, 2012 General Partner [Member]		Sep. 30, 2011 General Partner [Member]		Mar. 31, 2011 General Partner [Member]		Dec. 31, 2013 General Partner [Member]	Dec. 31, 2012 General Partner [Member]	Dec. 31, 2012 General Partner [Member] Mountain Gas Resources [Member]	Dec. 31, 2012 General Partner [Member] June 2012 Equity Offering [Member]	Dec. 31, 2012 General Partner [Member] Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 General Partner [Member] Western Gas Equity Partners [Member]	Dec. 31, 2013 General Partner [Member] Non-Operated Marcellus Interest [Member]	Dec. 31, 2013 General Partner [Member] May 2013 Equity Offering [Member]	Dec. 31, 2013 General Partner [Member] Continuous Offering Program [Member]	Dec. 31, 2013 General Partner [Member] December 2013 Equity Offering [Member]
Capital Unit [Line Items]
Balance	106,796,483	91,980,612																			104,660,553	90,140,999																				2,135,930	1,839,613
Acquisition			645,697		154,321		458,295																632,783		151,235		449,129																	12,914		3,086		9,166
Long-Term Incentive Plan Awards	12,648	12,827																			12,395	12,570																				253	257
Common units issued											4,500,000	[1],[2]	7,015,000	[1]	5,000,000	[1]	5,750,000	[1]	3,852,813	[1]				5,000,000				7,015,000	642,385	685,735	4,500,000
Offering				5,102,041				7,158,163	699,731	4,591,837																						91,837	[2],[3]	143,163	[3]	102,041	[3]	117,347	[3]	78,629	[3]				102,041				143,163	13,996	91,837
WGP unit purchase agreement						8,900,985																				8,722,966																					178,019
Balance	119,717,157	106,796,483									117,322,812										117,322,812	104,660,553										2,394,345										2,394,345	2,135,930

[1] Includes the issuance of 302,813 common units, 750,000 common units and 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.

[2] Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

[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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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Basis of Presentation

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). 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 subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, and includes equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” All income earned on, distributions from and contributions to the Partnership’s equity investments are considered to be affiliate transactions. See Note 2. “Equity investment throughput” refers to the Partnership’s 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of the 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput.

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, 2013, the Partnership’s assets and investments accounted for under the equity method, including the TEFR Interests, consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	13	1	5	2
NGL gathering systems	—	—	—	2
Natural gas treating facilities	8	—	—	1
Natural gas processing facilities	8	3	—	2
NGL pipelines	3	—	—	2
Natural gas pipelines	3	—	—	—
Oil pipeline	—	—	—	1

These assets are located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), north-central Pennsylvania, and Texas. The Partnership was also constructing the Lancaster processing plant in Northeast Colorado at the end of the fourth quarter of 2013.

Western Gas Equity Partners, LP. In December 2012, WGP completed its IPO of 19,758,150 common units representing limited partner interests in WGP 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 resulting in aggregate proceeds to the Partnership of $409.4 million, which was used by the Partnership for general partnership purposes, including the funding of capital expenditures.

WGP owns the following types of interests in the Partnership: (i) the 2.0% general partner interest and all of the incentive distribution rights (“IDRs”) in the Partnership, both owned through WGP’s 100% ownership of the Partnership’s general partner and (ii) a significant limited partner interest (see Holdings of Partnership equity in Note 4). WGP has no independent operations or material assets other than its partnership interests in WES.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Basis of presentation. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated. 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.

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 Anadarko-Operated Marcellus Interest (see Note 2) and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system in the accompanying consolidated financial statements.

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement (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 the additional Chipeta 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, 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 within noncontrolling interests in the consolidated financial statements for all periods presented. See Note 2.

Presentation of Partnership assets. The “Partnership assets” refer collectively to the assets owned and interests accounted for under the equity method by the Partnership as of December 31, 2013. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s general partner, each acquisition of Partnership 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 Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of the Partnership 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 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 Partnership assets during the periods reported. Net income attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income per common unit 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 condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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

Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities.

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

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

Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership is required to measure fair value and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the Partnership uses 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, 2013, the third-party accounts receivable balance was net of the associated bad-debt reserve of $13,000. As of December 31, 2012, there was no reserve for bad debts.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2013, natural gas imbalance receivables and payables were $3.6 million and $2.5 million, respectively. As of December 31, 2012, natural gas imbalance receivables and payables were $1.7 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.

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, 2013, 2012 and 2011.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 Partnership assets acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price paid to 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 such net assets on their respective acquisition dates. The consolidated balance sheets as of December 31, 2013 and 2012, include goodwill of $105.3 million, the impairment of which (if applicable) is not 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. An initial qualitative assessment may be performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. 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 qualitative evaluation as of October 1, 2013, 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, of (i) contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which are amortized on a straight-line basis over 50 years, and (ii) interconnect agreements at Chipeta entered into in November 2012, amortized on a straight-line basis over 10 years.

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, 2013, the carrying value of the Partnership’s intangible assets was $53.6 million, net of $3.4 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, 2012, the carrying value of the Partnership’s intangible assets was $55.5 million, net of $2.0 million of accumulated amortization.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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

	Equity Investments
thousands	Fort  Union (1)			White  Cliffs (2)			Rendezvous (3)			Mont Belvieu JV(4)		TEG(5)			TEP (6)			FRP (7)
Balance at December 31, 2011	$	22,268		$	17,710		$	69,839		$	—	$	—		$	6,110		$	—
Initial investment	—			—			—			—		9,086			—			23,878
Investment earnings (loss), net of amortization	6,383			7,871			1,857			—		(53		)	(4		)	(12		)
Contributions	—			862			—			—		—			74,631			—
Distributions	(5,198		)	(8,876		)	(6,586		)	—		—			—			—
Balance at December 31, 2012	$	23,453		$	17,567		$	65,110		$	—	$	9,033		$	80,737		$	23,866
Initial investment	—			—			—			78,129		—			—			—
Investment earnings (loss), net of amortization	6,273			9,681			2,088			5,690		93			(776		)	(101		)
Contributions	16			19,087			—			37,309		6,732			108,969			105,547
Capitalized interest	—			—			—			1,352		791			8,801			6,089
Distributions	(4,570		)	(9,099		)	(4,029		)	—		—			—			—
Distributions in excess of cumulative earnings	—			(2,197		)	(2,241		)	—		—			—			—
Balance at December 31, 2013	$	25,172		$	35,039		$	60,928		$	122,480	$	16,649		$	197,731		$	135,401

⁽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.

⁽⁴⁾  The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.

⁽⁵⁾  The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

⁽⁶⁾  The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

⁽⁷⁾  The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The investment balance at December 31, 2013, includes $2.5 million and $44.0 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. (“WGRI”), 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 WGRI 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, 2013, is $9.3 million less than the Partnership’s underlying equity in White Cliffs’ net assets as of December 31, 2013, 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.

The following tables present the summarized combined financial information for the Partnership’s equity method investments (amounts represents 100% of investee financial information):

	Year Ended December 31,
thousands	2013		2012		2011
Consolidated Statements of Income
Revenues	$	261,705	$	199,764	$	153,131
Operating income	171,496		135,498		90,544
Net income	170,175		133,987		88,504

	December 31,
thousands	2013		2012
Consolidated Balance Sheets
Current assets	$	186,690	$	79,835
Property, plant and equipment, net	2,676,531		1,174,311
Other assets	38,258		45,100
Total assets	$	2,901,479	$	1,299,246
Current liabilities	206,602		76,862
Non-current liabilities	34,012		50,759
Equity	2,660,865		1,171,625
Total liabilities and equity	$	2,901,479	$	1,299,246

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.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 ultimately 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 sales 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.

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 “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,139,027 units remained available for future issuance as of December 31, 2013. Upon vesting of each phantom unit awarded under the WES LTIP, 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 WES 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 WES 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 Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) for the year ended December 31, 2013, (ii) the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) for the years ended December 31, 2012 and 2011, and (iii) 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”) for all periods presented. 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. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized. However, distribution equivalent rights awarded in tandem with equity-or liability-based awards are paid in cash and reflected within financing cash flows in the consolidated statements of cash flows. 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 beginning on 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 standards 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, 2013 or 2012.

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.

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 earned on and subsequent to the date of the acquisition 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. Net income attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income per common unit or subordinated unit. See Note 4.

Other assets. For the years ended December 31, 2013 and 2012, other current assets on the consolidated balance sheets includes $0.4 million 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 December 2014. Other assets 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.

Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. These cash receipts are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. See Note 5.

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Property, Plant and Equipment Table (details) (USD $) In Thousands, unless otherwise specified									12 Months Ended				12 Months Ended						12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2013 Land [Member]	Dec. 31, 2012 Land [Member]	Dec. 31, 2013 Gathering systems [Member]	Dec. 31, 2012 Gathering systems [Member]	Dec. 31, 2013 Gathering systems [Member] Minimum [Member]	Dec. 31, 2013 Gathering systems [Member] Maximum [Member]	Dec. 31, 2013 Pipelines And Equipment [Member]	Dec. 31, 2012 Pipelines And Equipment [Member]	Dec. 31, 2013 Pipelines And Equipment [Member] Minimum [Member]	Dec. 31, 2013 Pipelines And Equipment [Member] Maximum [Member]	Dec. 31, 2013 Asset Under Construction [Member]	Dec. 31, 2012 Asset Under Construction [Member]	Dec. 31, 2013 Other [Member]	Dec. 31, 2012 Other [Member]	Dec. 31, 2013 Other [Member] Minimum [Member]	Dec. 31, 2013 Other [Member] Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 4,239,100	[1]	$ 3,432,392	[1]	$ 2,584	$ 501	$ 3,673,008	$ 2,911,572			$ 146,008	$ 91,126			$ 405,633	$ 422,002	$ 11,867	$ 7,191
Accumulated depreciation	855,845	[1]	714,436	[1]
Net property, plant and equipment	$ 3,383,255	[1]	$ 2,717,956	[1]
Estimated useful life									3 years	47 years			15 years	45 years					3 years	40 years

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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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, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011
Distributions Made to Members or Limited Partners [Abstract]
Total Quarterly Distribution per Unit	$ 0.300	$ 0.600	[1]	$ 0.580	$ 0.560	$ 0.540	$ 0.520	$ 0.500	$ 0.480	$ 0.460	$ 0.440	$ 0.420	$ 0.405	$ 0.390
Total Quarterly Cash Distribution		$ 92,609	[1]	$ 83,986	$ 79,315	$ 70,143	$ 65,657	$ 56,346	$ 52,425	$ 46,053	$ 43,027	$ 40,323	$ 36,063	$ 33,168

[1] On January 20, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

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Components of Working Capital (tables)

12 Months Ended

Dec. 31, 2013

Components Of Working Capital [Abstract]

Other Current Assets Table

A summary of other current assets is as follows:

	December 31,
thousands	2013		2012
Natural gas liquids inventory	$	2,584	$	1,678
Natural gas imbalance receivables	3,605		1,663
Prepaid insurance	2,123		1,897
Other	1,710		1,760
Total other current assets	$	10,022	$	6,998

Accrued Liabilities Table

A summary of accrued liabilities is as follows:

	December 31,
thousands	2013		2012
Accrued capital expenditures	$	94,750	$	112,311
Accrued plant purchases	21,396		16,350
Accrued interest expense	18,119		15,868
Short-term asset retirement obligations	1,966		1,711
Short-term remediation and reclamation obligations	562		799
Other	218		612
Total accrued liabilities	$	137,011	$	147,651

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Property, Plant and Equipment (table)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Table

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

		December 31,
thousands	Estimated Useful Life	2013		2012
Land	n/a	$	2,584	$	501
Gathering systems	3 to 47 years	3,673,008		2,911,572
Pipelines and equipment	15 to 45 years	146,008		91,126
Assets under construction	n/a	405,633		422,002
Other	3 to 40 years	11,867		7,191
Total property, plant and equipment		4,239,100		3,432,392
Accumulated depreciation		855,845		714,436
Net property, plant and equipment		$	3,383,255	$	2,717,956

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Transactions With Affiliates - Summary Table (details) (USD $)	3 Months Ended													12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	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, 2013		Dec. 31, 2012		Dec. 31, 2011
Related Party Transaction [Line Items]
Revenues														$ 1,029,763,000	[1]	$ 894,476,000	[1]	$ 858,144,000	[1]
Equity income, net														22,948,000	[1],[2],[3]	16,042,000	[1],[2],[3]	11,261,000	[1],[2],[3]
Cost of product														364,285,000	[1],[4]	336,079,000	[1],[4]	327,371,000	[1],[4]
Operation and maintenance														168,657,000	[1],[4]	140,106,000	[1],[4]	126,464,000	[1],[4]
General and administrative														29,751,000	[1],[4]	99,212,000	[1],[4]	40,564,000	[1],[4]
Operating expenses														731,853,000	[1]	715,693,000	[1]	624,111,000	[1]
Interest income, net														16,900,000	[5]	16,900,000	[5]	24,106,000	[5]
Interest expense														51,797,000	[1]	42,060,000	[1]	30,345,000	[1]
Distributions to unitholders	92,609,000	[6]	83,986,000	79,315,000	70,143,000	65,657,000	56,346,000	52,425,000	46,053,000	43,027,000	40,323,000	36,063,000	33,168,000
Contributions from noncontrolling interest owners														2,247,000		29,108,000		33,637,000
Distributions to noncontrolling interest owners														13,127,000		17,303,000		17,478,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues														805,526,000	[1],[7]	688,026,000	[1],[7]	647,419,000	[1],[7]
Cost of product														129,045,000	[7]	145,250,000	[7]	83,722,000	[7]
Operation and maintenance														56,435,000	[8]	51,237,000	[8]	51,339,000	[8]
General and administrative														23,354,000	[9]	92,847,000	[9]	33,305,000	[9]
Operating expenses														208,834,000		289,334,000		168,366,000
Interest expense														0	[10]	2,766,000	[10]	4,935,000	[10]
Distributions to unitholders														169,150,000	[11]	98,280,000	[11]	68,039,000	[11]
Contributions from noncontrolling interest owners														0	[12]	12,588,000	[12]	16,476,000	[12]
Distributions to noncontrolling interest owners														$ 0	[12]	$ 6,528,000	[12]	$ 9,437,000	[12]

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Income earned from equity investments is classified as affiliate. See Note 1.

[3] Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

[4] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $129.0 million, $145.3 million and $83.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Operation and maintenance includes charges from Anadarko of $56.4 million, $51.2 million and $51.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. General and administrative includes charges from Anadarko of $23.4 million, $92.8 million and $33.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 5.

[5] Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets and the Bison 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.

[6] On January 20, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

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

[8] Represents expenses incurred on 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.

[9] Represents general and administrative expense incurred on 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 The Incentive Plan and WGP LTIP and Anadarko Incentive Plans within this Note 5).

[10] For the year ended December 31, 2012, includes 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 facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

[11] Represents distributions paid under the partnership agreement.

[12] As described in Note 2, the Partnership acquired the additional Chipeta interest 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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Partnership Distributions - Incentive Distribution Rights Table (details) (USD $)	1 Months Ended	3 Months Ended
	May 31, 2008	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.300	$ 0.600	[1]	$ 0.580	$ 0.560	$ 0.540	$ 0.520	$ 0.500	$ 0.480	$ 0.460	$ 0.440	$ 0.420	$ 0.405	$ 0.390
Thereafter [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.450
Unitholders [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest In Distributions	98.00%
Unitholders [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest In Distributions	98.00%
Unitholders [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest In Distributions	85.00%
Unitholders [Member] | Third Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest In Distributions	75.00%
Unitholders [Member] | Thereafter [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest In Distributions	50.00%
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 Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest In Distributions	2.00%
General Partner [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal Percentage Interest In Distributions	15.00%
General Partner [Member] | Third Target Distribution [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%
Minimum [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.300
Minimum [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.345
Minimum [Member] | Third Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.375
Maximum [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.345
Maximum [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.375
Maximum [Member] | Third Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total Quarterly Distribution Target Amount	$ 0.450

[1] On January 20, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

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Asset Retirement Obligations (table)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations Table

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

	Year Ended December 31,
thousands	2013			2012
Carrying amount of asset retirement obligations at beginning of year	$	66,723		$	64,345
Liabilities incurred	14,143			9,414
Liabilities settled	(1,943		)	(786		)
Accretion expense	4,326			4,270
Revisions in estimated liabilities	(5,214		)	(10,520		)
Carrying amount of asset retirement obligations at end of year	$	78,035		$	66,723

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Debt and Interest Expense (tables)

12 Months Ended

Dec. 31, 2013

Debt Instruments [Abstract]

Debt Outstanding and Debt Activity Tables

The following table presents the Partnership’s outstanding debt as of December 31, 2013 and 2012:

	December 31, 2013						December 31, 2012
thousands	Principal		Carrying Value		Fair Value(1)		Principal		Carrying Value		Fair Value (1)
4.000% Senior Notes due 2022	$	670,000	$	673,278	$	641,237	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021	500,000		495,173		533,615		500,000		494,661		499,946
2.600% Senior Notes due 2018	250,000		249,718		247,988		—		—		—
Total debt outstanding	$	1,420,000	$	1,418,169	$	1,422,840	$	1,170,000	$	1,168,278	$	1,169,874

⁽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, 2013 and 2012:

thousands	Carrying Value
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	4,100
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings	710,000
Repayments of revolving credit facility	(710,000		)
Issuance of 2.600% Senior Notes due 2018	250,000
Other	(109		)
Balance as of December 31, 2013	$	1,418,169

Interest Expense Table

he following table summarizes the amounts included in interest expense:

	Year Ended December 31,
thousands	2013			2012			2011
Third parties
Interest expense on long-term debt	$	59,293		$	41,171		$	20,533
Amortization of debt issuance costs and commitment fees (1)	4,449			4,319			5,297
Capitalized interest	(11,945		)	(6,196		)	(420		)
Total interest expense – third parties	51,797			39,294			25,410
Affiliates
Interest expense on note payable to Anadarko (2)	—			2,440			4,935
Interest expense on affiliate balances (3)	—			326			—
Total interest expense – affiliates	—			2,766			4,935
Interest expense	$	51,797		$	42,060		$	30,345

⁽¹⁾  For the years ended December 31, 2013 and 2012, includes $1.0 million and $1.1 million, respectively, of amortization of (i) the original issue discount for the June 2012 offering of the 2022 Notes, 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. In addition, for the year ended December 31, 2013, includes the amortization of the original issue discount and underwriters’ fees for the 2018 Notes of $0.2 million. 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⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

⁽³⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant.

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Cash flows from operating activities
Net income	$ 285,443	[1]	$ 149,267	[1]	$ 206,861	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	145,916	[1]	120,608	[1]	113,133	[1]
Non-cash equity-based compensation expense	3,521	[1]	3,717	[1]	3,490	[1]
Deferred income taxes	31,891	[1]	30,109	[1]	16,580	[1]
Debt-related amortization and other items, net	2,449	[1]	2,319	[1]	3,110	[1]
Equity income, net	(22,948)	[1],[2],[3]	(16,042)	[1],[2],[3]	(11,261)	[1],[2],[3]
Distributions from equity investment earnings	17,698	[1],[3]	20,660	[1],[3]	15,999	[1],[3]
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(34,019)	[1]	22,916	[1]	(44,725)	[1]
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	21,952	[1]	5,045	[1]	30,884	[1]
Change in other items, net	(3,702)	[1]	(552)	[1]	(21,233)	[1]
Net cash provided by operating activities	448,201	[1]	338,047	[1]	312,838	[1]
Cash flows from investing activities
Capital expenditures	(646,471)	[1]	(638,121)	[1]	(149,717)	[1]
Investments in equity affiliates	(294,693)	[1]	(108,457)	[1]	(6,203)	[1]
Distributions in excess of cumulative earnings	4,438	[1],[3]	0	[1],[3]	0	[1],[3]
Other	14	[1]	0	[1]	500	[1]
Net cash used in investing activities	(1,652,995)	[1]	(1,357,537)	[1]	(485,832)	[1]
Cash flows from financing activities
Borrowings, net of debt issuance costs	957,503	[1]	1,041,648	[1]	1,055,939	[1]
Repayments of debt	(710,000)	[1]	(549,000)	[1]	(869,000)	[1]
Increase (decrease) in outstanding checks	(1,763)	[1]	1,800	[1]	4,039	[1]
Proceeds from issuance of common and general partner units, net of offering expenses	740,825	[1]	625,877	[1]	335,317	[1]
Distributions to unitholders	(299,101)	[1]	(197,850)	[1]	(140,118)	[1]
Contributions from noncontrolling interest owners	2,247	[1]	29,108	[1]	33,637	[1]
Distributions to noncontrolling interest owners	(13,127)	[1]	(17,303)	[1]	(17,478)	[1]
Net contributions from Anadarko	208,957	[1]	278,632	[1]
Net distributions to Anadarko					(29,857)	[1]
Net cash provided by financing activities	885,541	[1]	1,212,912	[1]	372,479	[1]
Net increase (decrease) in cash and cash equivalents	(319,253)	[1]	193,422	[1]	199,485	[1]
Cash and cash equivalents at beginning of period	419,981	[1]	226,559	[1]	27,074	[1]
Cash and cash equivalents at end of period	100,728	[1]	419,981	[1]	226,559	[1]
Supplemental disclosures
Net distributions to Anadarko of other assets	5,855	[1]	15,296	[1]
Net contributions from Anadarko of other assets					(29)	[1]
Interest paid, net of capitalized interest	47,098	[1]	28,042	[1]	25,828	[1]
Taxes paid	552	[1]	495	[1]	190	[1]
Affiliated Entity [Member]
Cash flows from investing activities
Contributions in aid of constructions costs from affiliates	617	[1]	0	[1]	0	[1]
Acquisitions	(476,711)	[1]	(611,719)	[1]	(28,837)	[1]
Proceeds from sale of assets	85	[1]	760	[1]	382	[1]
Third Parties [Member]
Cash flows from investing activities
Acquisitions	$ (240,274)	[1]	$ 0	[1]	$ (301,957)	[1]

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Income earned from equity investments is classified as affiliate. See Note 1.

[3] Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

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Commitments and Contingencies (table)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2013, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:

thousands	Operating Leases
2014	$	309
2015	245
2016	233
2017	157
2018	34
Thereafter	—
Total	$	978

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Acquisitions - Pro Forma Condensed Financial Information Table (details) (Anadarko-Operated Marcellus Interest [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Anadarko-Operated Marcellus Interest [Member]
Business Acquisition [Line Items]
Revenues	$ 1,031,017	$ 899,353
Net income	285,591	147,238
Net income attributable to Western Gas Partners, LP	$ 274,775	$ 132,348
Net income per common unit - basic and diluted	$ 1.82	$ 0.82

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Transactions With Affiliates - Omnibus Agreement Table (details) (Omnibus Agreement [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Allocated costs from Anadarko	$ 24,034	$ 21,734	$ 19,489
General and Administrative Expense [Member]
Related Party Transaction [Line Items]
Allocated costs from Anadarko	16,882	14,904	11,754
Public Company Expenses [Member]
Related Party Transaction [Line Items]
Allocated costs from Anadarko	$ 7,152	$ 6,830	$ 7,735

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Commitments and Contingencies - Additional Information (details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies [Line Items]
Long-term liability for remediation and reclamation obligations	$ 1.9	$ 1.9
Committed capital	47.1
Term of instrument or obligation	5 years
Rent expense associated with office and equipment leases	$ 2.8	$ 3.0	$ 4.1
Purchase Commitment [Member]
Commitments and Contingencies [Line Items]
Term of instrument or obligation	12 months

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Consolidated Statements of Income (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues
Total revenues	$ 1,029,763,000	[1]	$ 894,476,000	[1]	$ 858,144,000	[1]
Equity income, net	22,948,000	[1],[2],[3]	16,042,000	[1],[2],[3]	11,261,000	[1],[2],[3]
Operating expenses
Cost of product	364,285,000	[1],[4]	336,079,000	[1],[4]	327,371,000	[1],[4]
Operation and maintenance	168,657,000	[1],[4]	140,106,000	[1],[4]	126,464,000	[1],[4]
General and administrative	29,751,000	[1],[4]	99,212,000	[1],[4]	40,564,000	[1],[4]
Property and other taxes	23,244,000	[1]	19,688,000	[1]	16,579,000	[1]
Depreciation, amortization and impairments	145,916,000	[1]	120,608,000	[1]	113,133,000	[1]
Total operating expenses	731,853,000	[1]	715,693,000	[1]	624,111,000	[1]
Operating income	320,858,000	[1]	194,825,000	[1]	245,294,000	[1]
Interest income, net - affiliates	16,900,000	[1]	16,900,000	[1]	24,106,000	[1]
Interest expense	(51,797,000)	[1]	(42,060,000)	[1]	(30,345,000)	[1]
Other income (expense), net	1,837,000	[1]	292,000	[1]	(44,000)	[1]
Income before income taxes	287,798,000	[1]	169,957,000	[1]	239,011,000	[1]
Income tax expense	2,355,000	[1]	20,690,000	[1]	32,150,000	[1]
Net income	285,443,000	[1]	149,267,000	[1]	206,861,000	[1]
Net income attributable to noncontrolling interests	10,816,000	[1]	14,890,000	[1]	14,103,000	[1]
Net income attributable to Western Gas Partners, LP	274,627,000	[1]	134,377,000	[1]	192,758,000	[1]
Limited partners' interest in net income:
Pre-acquisition net (income) loss allocated to Anadarko	(4,128,000)	[1]	(27,391,000)	[1]	(52,599,000)	[1]
General partner interest in net (income) loss	(69,633,000)	[1],[5]	(28,089,000)	[1],[5]	(8,599,000)	[1],[5]
Limited partners' interest in net income	200,866,000	[1],[5]	78,897,000	[1],[5]	131,560,000	[1],[5]
Common Units [Member]
Limited partners' interest in net income:
Limited partners' interest in net income	200,866,000		78,897,000		110,542,000
Subordinated [Member]
Limited partners' interest in net income:
Limited partners' interest in net income	0		0		21,018,000
Affiliated Entity [Member]
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	306,810,000	[1]	249,997,000	[1]	227,535,000	[1]
Natural gas, natural gas liquids and condensate sales	496,848,000	[1]	436,423,000	[1]	417,547,000	[1]
Other, net	1,868,000	[1]	1,606,000	[1]	2,337,000	[1]
Total revenues	805,526,000	[1],[6]	688,026,000	[1],[6]	647,419,000	[1],[6]
Operating expenses
Cost of product	129,045,000	[6]	145,250,000	[6]	83,722,000	[6]
Operation and maintenance	56,435,000	[7]	51,237,000	[7]	51,339,000	[7]
General and administrative	23,354,000	[8]	92,847,000	[8]	33,305,000	[8]
Total operating expenses	208,834,000		289,334,000		168,366,000
Interest expense	0	[9]	(2,766,000)	[9]	(4,935,000)	[9]
Third Parties [Member]
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	175,732,000	[1]	132,333,000	[1]	119,934,000	[1]
Natural gas, natural gas liquids and condensate sales	44,396,000	[1]	71,916,000	[1]	84,836,000	[1]
Other, net	4,109,000	[1]	2,201,000	[1]	5,955,000	[1]
Total revenues	224,237,000	[1]	206,450,000	[1]	210,725,000	[1]
Operating expenses
Interest expense	$ (51,797,000)		$ (39,294,000)		$ (25,410,000)
Limited Partner [Member] | Common Units [Member]
Limited partners' interest in net income:
Net income per common unit - basic and diluted	$ 1.83	[1]	$ 0.84	[1]	$ 1.64	[1]
Limited Partner [Member] | Subordinated [Member]
Limited partners' interest in net income:
Net income per common unit - basic and diluted	$ 0	[1],[10]	$ 0	[1],[10]	$ 1.28	[1],[10]

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Income earned from equity investments is classified as affiliate. See Note 1.

[3] Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

[4] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $129.0 million, $145.3 million and $83.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Operation and maintenance includes charges from Anadarko of $56.4 million, $51.2 million and $51.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. General and administrative includes charges from Anadarko of $23.4 million, $92.8 million and $33.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 5.

[5] Represents net income earned on and subsequent to the date of 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 on 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 on 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 The Incentive Plan and WGP LTIP and Anadarko Incentive Plans within this Note 5).

[9] For the year ended December 31, 2012, includes 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 facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

[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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Partnership Distributions - Additional Information (details)	12 Months Ended
	Dec. 31, 2013
Distributions Made to Members or Limited Partners [Abstract]
Partnership agreement day requirement of distribution of available cash	45 days

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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 [Member]	Common Units [Member]	Common Units [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, 2010		$ 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)
Acquisitions 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		(27,675)				(27,675)
Elimination of net deferred tax liabilities		22,072				22,072
Other		(314)					(267)				(47)
Balance at Dec. 31, 2011	[1]	2,010,279				362,573	1,495,253				31,729			120,724
Net income		149,267	[1]			27,391	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)
Acquisitions 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		193,236				299,833	(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]	2,394,076				313,600	1,957,066				52,752			70,658
Net income		285,443	[1]			4,128	200,866				69,633			10,816
Issuance of common and general partner units, net of offering expenses		740,586					724,811				15,775
Contributions from noncontrolling interest owners		2,247												2,247
Distributions to noncontrolling interest owners		(13,127)												(13,127)
Distributions to unitholders		(299,101)					(239,157)				(59,944)
Acquisitions from affiliates		(465,500)				(255,635)	(209,865)
Contributions of equity-based compensation from Anadarko	[3]	2,923					2,865				58
Net pre-acquisition contributions from (distributions to) Anadarko	[5]	203,469				203,469
Net distributions of other assets to Anadarko		(5,855)	[1]				(5,738)				(117)
Elimination of net deferred tax liabilities		46,530				46,530
Other		345					345
Balance at Dec. 31, 2013	[1]	$ 2,892,036				$ 312,092	$ 2,431,193				$ 78,157			$ 70,594

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and 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 years ended December 31, 2011 and 2013, 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.

[5] Includes deferred taxes on capitalized interest of $5.5 million associated with the acquisition of the TEFR Interests for the year ended December 31, 2013.

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Income Taxes - Tax Rate Reconciliation Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Related Party Transaction [Line Items]
Income before income taxes	$ 287,798	[1]	$ 169,957	[1]	$ 239,011	[1]
Statutory tax rate	0.00%		0.00%		0.00%
Adjustments Resulting From [Abstract]
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) Texas margin tax expense (benefit)	(1,359)		1,258		664
Total income tax expense	2,355	[1]	20,690	[1]	32,150	[1]
Effective tax rate	1.00%		12.00%		13.00%
Pre Acquisition From Parent [Member]
Adjustments Resulting From [Abstract]
Federal taxes on income attributable to Partnership assets pre-acquisition	3,090		17,226		29,502
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) Texas margin tax expense (benefit)	$ 624		$ 2,206		$ 1,984

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Summary of Significant Accounting Policies - Summarized Combined Financial Data For Equity Method Investments - Income Statement (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Investment in affiliates [Abstract]
Revenues	$ 261,705	$ 199,764	$ 153,131
Operating income	171,496	135,498	90,544
Net income	$ 170,175	$ 133,987	$ 88,504

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Components of Working Capital - Accrued Liabilities Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Accrued Liabilities [Line Items]
Other accrued liabilities	$ 218		$ 612
Accrued interest expense	18,119		15,868
Short-term asset retirement obligations	1,966		1,711
Short-term remediation and reclamation obligations	562		799
Accrued liabilities	137,011	[1],[2]	147,651	[1],[2]
Accrued Capital Expenditures [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	94,750		112,311
Accrued Plant Purchases [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	$ 21,396		$ 16,350

[1] Accrued liabilities include amounts payable to affiliates of $0.1 million as of December 31, 2013 and 2012.

[2] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Summary of Significant Accounting Policies (tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Assets Table

As of December 31, 2013, the Partnership’s assets and investments accounted for under the equity method, including the TEFR Interests, consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	13	1	5	2
NGL gathering systems	—	—	—	2
Natural gas treating facilities	8	—	—	1
Natural gas processing facilities	8	3	—	2
NGL pipelines	3	—	—	2
Natural gas pipelines	3	—	—	—
Oil pipeline	—	—	—	1

Equity-Method Investments Table

The following table presents the activity in the Partnership’s investments in equity of Fort Union, White Cliffs, Rendezvous, Mont Belvieu JV, TEG, TEP and FRP:

	Equity Investments
thousands	Fort  Union (1)			White  Cliffs (2)			Rendezvous (3)			Mont Belvieu JV(4)		TEG(5)			TEP (6)			FRP (7)
Balance at December 31, 2011	$	22,268		$	17,710		$	69,839		$	—	$	—		$	6,110		$	—
Initial investment	—			—			—			—		9,086			—			23,878
Investment earnings (loss), net of amortization	6,383			7,871			1,857			—		(53		)	(4		)	(12		)
Contributions	—			862			—			—		—			74,631			—
Distributions	(5,198		)	(8,876		)	(6,586		)	—		—			—			—
Balance at December 31, 2012	$	23,453		$	17,567		$	65,110		$	—	$	9,033		$	80,737		$	23,866
Initial investment	—			—			—			78,129		—			—			—
Investment earnings (loss), net of amortization	6,273			9,681			2,088			5,690		93			(776		)	(101		)
Contributions	16			19,087			—			37,309		6,732			108,969			105,547
Capitalized interest	—			—			—			1,352		791			8,801			6,089
Distributions	(4,570		)	(9,099		)	(4,029		)	—		—			—			—
Distributions in excess of cumulative earnings	—			(2,197		)	(2,241		)	—		—			—			—
Balance at December 31, 2013	$	25,172		$	35,039		$	60,928		$	122,480	$	16,649		$	197,731		$	135,401

⁽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.

⁽⁴⁾  The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.

⁽⁵⁾  The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

⁽⁶⁾  The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

⁽⁷⁾  The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

Summarized Statements Of Equity Method Investment Affiliates Presented at 100 Percent

The following tables present the summarized combined financial information for the Partnership’s equity method investments (amounts represents 100% of investee financial information):

	Year Ended December 31,
thousands	2013		2012		2011
Consolidated Statements of Income
Revenues	$	261,705	$	199,764	$	153,131
Operating income	171,496		135,498		90,544
Net income	170,175		133,987		88,504

	December 31,
thousands	2013		2012
Consolidated Balance Sheets
Current assets	$	186,690	$	79,835
Property, plant and equipment, net	2,676,531		1,174,311
Other assets	38,258		45,100
Total assets	$	2,901,479	$	1,299,246
Current liabilities	206,602		76,862
Non-current liabilities	34,012		50,759
Equity	2,660,865		1,171,625
Total liabilities and equity	$	2,901,479	$	1,299,246

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Summary of Significant Accounting Policies - Summarized Combined Financial Data For Equity Method Investments - Balance Sheet (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Investment in affiliates [Abstract]
Current assets	$ 186,690	$ 79,835
Property, plant and equipment, net	2,676,531	1,174,311
Other assets	38,258	45,100
Total assets	2,901,479	1,299,246
Current liabilities	206,602	76,862
Non-current liabilities	34,012	50,759
Equity	2,660,865	1,171,625
Total liabilities and equity	$ 2,901,479	$ 1,299,246

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Partnership Distributions (tables)

12 Months Ended

Dec. 31, 2013

Distributions Made to Members or Limited Partners [Abstract]

Cash Distributions Table

The board of directors of the general partner declared the following cash distributions to the Partnership’s unitholders for the periods presented:

thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
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	$	0.520	$	65,657	February 2013
2013
March 31	$	0.540	$	70,143	May 2013
June 30	$	0.560	$	79,315	August 2013
September 30	$	0.580	$	83,986	November 2013
December 31 (1)	$	0.600	$	92,609	February 2014

⁽¹⁾  On January 20, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

Incentive Distribution Rights Table

The Partnership’s general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

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

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Debt and Interest Expense - Debt Activity Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Debt Instrument [Line Items]
Beginning Balance	$ 1,168,278	[1]	$ 669,178
Other	(109)		4,100
Ending Balance	1,418,169	[1]	1,168,278	[1]
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings	710,000		374,000
Repayments	(710,000)		(374,000)
Swingline [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Borrowings			20,000
Repayments			(20,000)
Senior Notes 4 Percent Due 2022 [Member]
Debt Instrument [Line Items]
Borrowings			670,000
Ending Balance	673,278		673,617
Note Payable To Anadarko [Member]
Debt Instrument [Line Items]
Repayments			(175,000)
Senior Notes 2 Point 6 Percent Due 2018 [Member]
Debt Instrument [Line Items]
Beginning Balance	0
Borrowings	250,000
Ending Balance	$ 249,718

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Consolidated Statement of Equity and Partners' Capital (Parenthetical) (USD $)	12 Months Ended			12 Months Ended
	Dec. 31, 2012 Partners' Capital [Member]	Dec. 31, 2012 Chipeta Processing Limited Liability Company [Member] Partners' Capital [Member]	Aug. 31, 2012 Affiliated Entity [Member] Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2013 Capitalized Interest [Member] Parent Net Investment [Member]
Ownership interest by noncontrolling owners			24.00%
Acquisitions 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
Deferred taxes on capitalized interest				$ 5,500,000

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Consolidated Statements of Income (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Cost of product	$ 364,285,000	[1],[2]	$ 336,079,000	[1],[2]	$ 327,371,000	[1],[2]
Operation and maintenance	168,657,000	[1],[2]	140,106,000	[1],[2]	126,464,000	[1],[2]
General and administrative	29,751,000	[1],[2]	99,212,000	[1],[2]	40,564,000	[1],[2]
Interest expense	51,797,000	[1]	42,060,000	[1]	30,345,000	[1]
Affiliated Entity [Member]
Cost of product	129,045,000	[3]	145,250,000	[3]	83,722,000	[3]
Operation and maintenance	56,435,000	[4]	51,237,000	[4]	51,339,000	[4]
General and administrative	23,354,000	[5]	92,847,000	[5]	33,305,000	[5]
Interest expense	$ 0	[6]	$ 2,766,000	[6]	$ 4,935,000	[6]

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $129.0 million, $145.3 million and $83.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Operation and maintenance includes charges from Anadarko of $56.4 million, $51.2 million and $51.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. General and administrative includes charges from Anadarko of $23.4 million, $92.8 million and $33.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 5.

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

[4] Represents expenses incurred on 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 on 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 The Incentive Plan and WGP LTIP and Anadarko Incentive Plans within this Note 5).

[6] For the year ended December 31, 2012, includes 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 facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

9.  ASSET RETIREMENT OBLIGATIONS

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

	Year Ended December 31,
thousands	2013			2012
Carrying amount of asset retirement obligations at beginning of year	$	66,723		$	64,345
Liabilities incurred	14,143			9,414
Liabilities settled	(1,943		)	(786		)
Accretion expense	4,326			4,270
Revisions in estimated liabilities	(5,214		)	(10,520		)
Carrying amount of asset retirement obligations at end of year	$	78,035		$	66,723

Revisions in estimated liabilities for the year ended December 31, 2013, 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, 2013, represented the increase in the capital expansion at the Wattenberg and Hilight systems and the June 2013 completion of the Brasada facility.

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.

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Document and Entity Information	12 Months Ended
	Dec. 31, 2013
Document And Entity Information [Abstract]
Entity Registrant Name	WESTERN GAS PARTNERS LP
Entity Central Index Key	0001414475
Document Type	8-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

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Debt and Interest Expense

12 Months Ended

Dec. 31, 2013

Debt Instruments [Abstract]

Debt and Interest Expense

10.  DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt as of December 31, 2013 and 2012:

	December 31, 2013						December 31, 2012
thousands	Principal		Carrying Value		Fair Value(1)		Principal		Carrying Value		Fair Value (1)
4.000% Senior Notes due 2022	$	670,000	$	673,278	$	641,237	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021	500,000		495,173		533,615		500,000		494,661		499,946
2.600% Senior Notes due 2018	250,000		249,718		247,988		—		—		—
Total debt outstanding	$	1,420,000	$	1,418,169	$	1,422,840	$	1,170,000	$	1,168,278	$	1,169,874

⁽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, 2013 and 2012:

thousands	Carrying Value
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	4,100
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings	710,000
Repayments of revolving credit facility	(710,000		)
Issuance of 2.600% Senior Notes due 2018	250,000
Other	(109		)
Balance as of December 31, 2013	$	1,418,169

Senior Notes. In August 2013, the Partnership completed the offering of $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018 (the “2018 Notes”) at a price to the public of 99.879% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2018 Notes is 2.806%. Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $1.5 million, original issue discount and debt issuance costs) were used to repay amounts then outstanding under the Partnership’s $800.0 million senior unsecured revolving credit facility (“RCF”).

The 2018 Notes mature on August 15, 2018, unless earlier redeemed. The Partnership may redeem the 2018 Notes in whole or in part, at any time before July 15, 2018, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2018 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2018 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 2018 Notes) plus 20 basis points, plus, in either case, accrued and unpaid interest to such redemption date, if any, on the principal amount being redeemed. On or after July 15, 2018, the 2018 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 2018 Notes to be redeemed, plus accrued interest on the 2018 Notes to be redeemed to the date of redemption.

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022. In October 2012, the Partnership issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022. The October 2012 notes and the June 2012 notes were issued under the same indenture and are considered a single class of securities, collectively referred to as the “2022 Notes.”

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”). The indentures governing the 2021 Notes, the 2022 Notes, and the 2018 Notes contain customary events of default. At December 31, 2013, the Partnership was in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes, and the 2018 Notes.

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.

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 2.82% prior to June 2012 when the note payable to Anadarko was repaid in full with proceeds from the June 2012 offering 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. At December 31, 2013 and 2012, the interest rate on the RCF was 1.67% and 1.71%, 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, 2013 and 2012. See Note 12.

As of December 31, 2013, the Partnership had no outstanding borrowings, $12.8 million in outstanding letters of credit issued and $787.2 million available for borrowing under the RCF. At December 31, 2013, the Partnership was in compliance with all covenants under the RCF.

The 2021 Notes, the 2022 Notes, the 2018 Notes and obligations under the RCF are recourse to the Partnership’s general partner. The Partnership’s general partner is indemnified by a wholly owned subsidiary of Anadarko, WGRI, against any claims made against the general partner under the 2022 Notes, the 2021 Notes, and/or the RCF. See Note 2 and Note 12 for a discussion of amendments to the RCF and borrowing activity under the new RCF in March 2014, related to acquisitions which closed after December 31, 2013.

10.  DEBT AND INTEREST EXPENSE (CONTINUED)

In connection with the acquisition of the Non-Operated Marcellus Interest in March 2013, the general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary agreed to indemnify the Partnership’s general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. The 2013 Indemnification Agreement applies to the 2018 Notes. The Partnership’s general partner and WGRI also amended and restated the existing indemnity agreement between them to reduce the amount for which WGRI would indemnify the Partnership’s general partner by an amount equal to any amounts payable to the Partnership’s general partner under the 2013 Indemnification Agreement. See Note 12.

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 London Interbank Offered Rate (“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 expense. The following table summarizes the amounts included in interest expense:

	Year Ended December 31,
thousands	2013			2012			2011
Third parties
Interest expense on long-term debt	$	59,293		$	41,171		$	20,533
Amortization of debt issuance costs and commitment fees (1)	4,449			4,319			5,297
Capitalized interest	(11,945		)	(6,196		)	(420		)
Total interest expense – third parties	51,797			39,294			25,410
Affiliates
Interest expense on note payable to Anadarko (2)	—			2,440			4,935
Interest expense on affiliate balances (3)	—			326			—
Total interest expense – affiliates	—			2,766			4,935
Interest expense	$	51,797		$	42,060		$	30,345

⁽¹⁾  For the years ended December 31, 2013 and 2012, includes $1.0 million and $1.1 million, respectively, of amortization of (i) the original issue discount for the June 2012 offering of the 2022 Notes, 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. In addition, for the year ended December 31, 2013, includes the amortization of the original issue discount and underwriters’ fees for the 2018 Notes of $0.2 million. 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⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

⁽³⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant.

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 100,728	[1]	$ 419,981	[1]
Accounts receivable, net	84,060	[1],[2]	50,233	[1],[2]
Other current assets	10,022	[1],[3]	6,998	[1],[3]
Total current assets	194,810	[1]	477,212	[1]
Note receivable - Anadarko	260,000	[1]	260,000	[1]
Property, plant and equipment
Cost	4,239,100	[1]	3,432,392	[1]
Less accumulated depreciation	855,845	[1]	714,436	[1]
Net property, plant and equipment	3,383,255	[1]	2,717,956	[1]
Goodwill	105,336	[1]	105,336	[1]
Other intangible assets	53,606	[1]	55,490	[1]
Equity investments	593,400	[1]	219,766	[1]
Other assets	27,401	[1]	27,798	[1]
Total assets	4,617,808	[1]	3,863,558	[1]
Current liabilities
Accounts and natural gas imbalance payables	39,589	[1],[4]	25,154	[1],[4]
Accrued ad valorem taxes	13,860	[1]	11,949	[1]
Income taxes payable	0	[1]	552	[1]
Accrued liabilities	137,011	[1],[5]	147,651	[1],[5]
Total current liabilities	190,460	[1]	185,306	[1]
Long-term debt	1,418,169	[1]	1,168,278	[1]
Deferred income taxes	37,998	[1]	47,149	[1]
Asset retirement obligations and other	79,145	[1]	68,749	[1]
Total long-term liabilities	1,535,312	[1]	1,284,176	[1]
Total liabilities	1,725,772	[1]	1,469,482	[1]
Equity and partners' capital
Common units (117,322,812 and 104,660,553 units issued and outstanding at December 31, 2013 and 2012, respectively)	2,431,193	[1]	1,957,066	[1]
General partner units (2,394,273 and 2,135,930 units issued and outstanding at December 31, 2013 and 2012, respectively)	78,157	[1]	52,752	[1]
Net investment by Anadarko	312,092	[1]	313,600	[1]
Total partners' capital	2,821,442	[1]	2,323,418	[1]
Noncontrolling interests	70,594	[1]	70,658	[1]
Total equity and partners' capital	2,892,036	[1]	2,394,076	[1]
Total liabilities, equity and partners' capital	$ 4,617,808	[1]	$ 3,863,558	[1]

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $47.9 million and $19.1 million as of December 31, 2013 and 2012, respectively.

[3] Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of December 31, 2013 and 2012, respectively.

[4] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.3 million and $2.5 million as of December 31, 2013 and 2012, respectively.

[5] Accrued liabilities include amounts payable to affiliates of $0.1 million as of December 31, 2013 and 2012.

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Equity and Partners' Capital

12 Months Ended

Dec. 31, 2013

Partners' Capital Notes [Abstract]

Equity and Partners' Capital

4.  EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public offerings of its common units during 2011, 2012 and 2013:

thousands except unit    and per-unit amounts	Common Units Issued (1)	GP Units Issued(2)	Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
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
May 2013 equity offering	7,015,000	143,163	61.18		13,203		424,733
December 2013 equity offering (3)	4,500,000	91,837	61.51		8,716		273,728

⁽¹⁾  Includes the issuance of 302,813 common units, 750,000 common units and 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.

⁽²⁾  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.

⁽³⁾  Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

In addition, pursuant to the Partnership’s registration statement filed with the U.S. Securities and Exchange Commission (“SEC”) in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”), during the three months ended December 31, 2013, the Partnership completed trades totaling 642,385 common units at an average price per unit of $60.83, generating gross proceeds of $39.9 million (including the general partner’s proportionate capital contribution and before $0.9 million of associated offering expenses). During the year ended December 31, 2013, the Partnership completed trades totaling 685,735 common units at an average price per unit of $60.84, generating gross proceeds of $42.6 million (including the general partner’s proportionate capital contribution and before $1.0 million of associated offering expenses).

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

The following table summarizes common and general partner units issued during the years ended December 31, 2012 and 2013:

	Common Units	General Partner Units	Total
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
Non-Operated Marcellus Interest acquisition	449,129	9,166	458,295
Long-Term Incentive Plan awards	12,395	253	12,648
May 2013 equity offering	7,015,000	143,163	7,158,163
Continuous Offering Program	685,735	13,996	699,731
December 2013 equity offering	4,500,000	91,837	4,591,837
Balance at December 31, 2013	117,322,812	2,394,345	119,717,157

Holdings of Partnership equity. As of December 31, 2013, WGP held 49,296,205 common units, representing a 41.2% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,394,345 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the Partnership’s IDRs. As of December 31, 2013, Anadarko Marcellus Midstream, L.L.C. (“AMM”), a subsidiary of Anadarko, separately held 449,129 common units, representing a 0.4% limited partner interest in the Partnership. As of December 31, 2013, the public held 67,577,478 common units, representing a 56.4% limited partner interest in the Partnership.

The Partnership’s net income earned on and subsequent to the date of the acquisition of the Partnership assets (as defined in Note 1) 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.

Net income per unit for common and subordinated units. 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.

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	2013			2012			2011
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Pre-acquisition net (income) loss allocated to Anadarko	(4,128		)	(27,391		)	(52,599		)
General partner interest in net (income) loss	(69,633		)	(28,089		)	(8,599		)
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Net income allocable to common units	$	200,866		$	78,897		$	110,542
Net income allocable to subordinated units	—			—			21,018
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Net income per unit – basic and diluted
Common units	$	1.83		$	0.84		$	1.64
Subordinated units	$	—		$	—		$	1.28
Weighted average units outstanding – basic and diluted
Common units	109,872			93,936			67,333
Subordinated units	—			—			16,431

Supplemental net income per unit for common and subordinated units. The following table sets forth the calculation of net income per common unit, if net income attributable to the Partnership’s assets (as defined in Note 1) acquired from Anadarko had been allocated to the limited partners for purposes of calculating net income per common and subordinated unit.

	Year Ended December 31,
thousands except per-unit amounts	2013			2012			2011
Limited partners’ interest in net income	$	200,866		$	78,897		$	131,560
Add: Pre-acquisition net income (loss) allocated to Anadarko	4,128			27,391			52,599
Add: General partner interest in net income (loss)	69,633			28,089			8,599
Less: Reallocation of general partner interest in net (income) loss	(69,717		)	(28,636		)	(9,650		)
Supplemental limited partners’ interest in net income	$	204,910		$	105,741		$	183,108
Net income allocable to common units	$	204,910		$	105,741		$	156,132
Net income allocable to subordinated units	—			—			26,976
Limited partners’ interest in net income	$	204,910		$	105,741		$	183,108
Supplemental net income per unit - basic and diluted
Common units	$	1.86		$	1.13		$	2.32
Subordinated units	$	—		$	—		$	1.64
Weighted average units outstanding - basic and diluted
Common units	109,872			93,936			67,333
Subordinated units	—			—			16,431

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Partnership Distributions

12 Months Ended

Dec. 31, 2013

Distributions Made to Members or Limited Partners [Abstract]

Partnership Distributions

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 board of directors of the general partner declared the following cash distributions to the Partnership’s unitholders for the periods presented:

thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
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	$	0.520	$	65,657	February 2013
2013
March 31	$	0.540	$	70,143	May 2013
June 30	$	0.560	$	79,315	August 2013
September 30	$	0.580	$	83,986	November 2013
December 31 (1)	$	0.600	$	92,609	February 2014

⁽¹⁾  On January 20, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

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.

3.  PARTNERSHIP DISTRIBUTIONS (CONTINUED)

General partner interest and incentive distribution rights. The general partner is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. The Partnership’s general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

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

The table above assumes that the Partnership’s general partner maintains its 2.0% general partner interest and that 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, 2013

Business Combinations [Abstract]

Acquisitions Table

The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2011, 2012 and 2013, 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
Platte Valley (1)	02/28/2011	100	%	$	303,000	$	602	—	—
Bison (2)	07/08/2011	100	%	—		25,000		2,950,284	60,210
MGR (3)	01/13/2012	100	%	299,000		159,587		632,783	12,914
Chipeta (4)	08/01/2012	24	%	—		128,250		151,235	3,086
Non-Operated Marcellus Interest(5)	03/01/2013	33.75	%	250,000		215,500		449,129	—
Anadarko-Operated Marcellus Interest(6)	03/08/2013	33.75	%	133,500		—		—	—
Mont Belvieu JV(7)	06/05/2013	25	%	—		78,129		—	—
OTTCO(8)	09/03/2013	100	%	27,500		—		—	—

⁽¹⁾  The Partnership acquired (i) a natural gas gathering system and related compression and other ancillary equipment and (ii) cryogenic gas processing facilities from a third party. These assets are located in the Denver-Julesburg Basin. The acquisition is referred to as the “Platte Valley acquisition.”

⁽²⁾  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.” 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.

⁽³⁾  The assets acquired from Anadarko consisted 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.”

⁽⁴⁾  The Partnership acquired Anadarko’s additional Chipeta interest (as described in Note 1). The Partnership received 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.

⁽⁵⁾  The Partnership acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in the Partnership.

⁽⁶⁾  The Partnership acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Anadarko-Operated Marcellus Interest acquisition below for further information, including the final allocation of the purchase price.

⁽⁷⁾  The Partnership acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See Mont Belvieu JV acquisition below for further information.

⁽⁸⁾  The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.

Purchase Price Allocation Table

The following is the final allocation of the purchase price, including $1.1 million of post-closing purchase price adjustments, to the assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition as of the acquisition date:

thousands
Property, plant and equipment	$	134,819
Asset retirement obligations	(174		)
Total purchase price	$	134,645

Pro Forma Condensed Financial Information Table

The following table presents pro forma condensed financial information of the Partnership as if the Anadarko-Operated Marcellus Interest acquisition had occurred on January 1, 2012:

	Year Ended December 31,
thousands except per-unit amounts	2013		2012
Revenues	$	1,031,017	$	899,353
Net income	285,591		147,238
Net income attributable to Western Gas Partners, LP	274,775		132,348
Net income per common unit - basic and diluted	$	1.82	$	0.82

Impact to Historical Consolidated Statements of Income Table

The following table presents the impact of the TEFR Interests on revenue, equity income (loss), net and net income (loss) as presented in the Partnership’s historical consolidated statements of income:

	Year Ended December 31, 2013
thousands	Partnership Historical		TEFR Interests			Combined
Revenues	$	1,029,763	$	—		$	1,029,763
Equity income (loss), net	23,732		(784		)	22,948
Net income (loss)	$	285,952	$	(509	)	$	285,443

	Year Ended December 31, 2012
thousands	Partnership Historical		TEFR Interests			Combined
Revenues	$	894,476	$	—		$	894,476
Equity income (loss), net	16,111		(69		)	16,042
Net income (loss)	$	149,311	$	(44	)	$	149,267

	Year Ended December 31, 2011
thousands	Partnership Historical		TEFR Interests		Combined
Revenues	$	858,144	$	—	$	858,144
Equity income (loss), net	11,261		—		11,261
Net income (loss)	$	206,861	$	—	$	206,861

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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, 2013 and 2012, asset retirement obligations and other on the consolidated balance sheets included a $1.9 million long-term liability for remediation and reclamation obligations. The recorded obligations do not include any anticipated insurance recoveries. The majority of 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 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, 2013, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of $47.1 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 Lancaster plant and an expansion project at the Fort Lupton compressor station in the Wattenberg system.

11.  COMMITMENTS AND CONTINGENCIES (CONTINUED)

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.

Rent expense associated with the office, warehouse and equipment leases was $2.8 million, $3.0 million and $4.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2013, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:

thousands	Operating Leases
2014	$	309
2015	245
2016	233
2017	157
2018	34
Thereafter	—
Total	$	978

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

7.  PROPERTY, PLANT AND EQUIPMENT

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

		December 31,
thousands	Estimated Useful Life	2013		2012
Land	n/a	$	2,584	$	501
Gathering systems	3 to 47 years	3,673,008		2,911,572
Pipelines and equipment	15 to 45 years	146,008		91,126
Assets under construction	n/a	405,633		422,002
Other	3 to 40 years	11,867		7,191
Total property, plant and equipment		4,239,100		3,432,392
Accumulated depreciation		855,845		714,436
Net property, plant and equipment		$	3,383,255	$	2,717,956

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 2013, the Partnership recognized a $1.2 million impairment primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest.

During 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 and an impairment of $0.6 million for the original installation costs on a compressor relocated within the Partnership’s operating assets.

During 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. Also during 2011, following an evaluation of estimated 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.

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Income Taxes - Deferred Tax Assets and Liabilities Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Income Tax Disclosure [Abstract]
Credit carryforwards	$ 14		$ 14
Net current deferred income tax assets	14		14
Depreciable property	(38,528)		(47,554)
Credit carryforwards	527		541
Other	3		(136)
Net long-term deferred income tax liabilities	(37,998)	[1]	(47,149)	[1]
Total net deferred income tax liabilities	$ (37,984)		$ (47,135)

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Transactions With Affiliates

12 Months Ended

Dec. 31, 2013

Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract]

Transactions with Affiliates

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’ separate bank accounts is generally swept to centralized accounts. Prior to the Partnership’s acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged or credited the Partnership interest at a variable rate on outstanding affiliate balances for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to 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. Concurrently 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 $296.7 million and $334.8 million at December 31, 2013 and 2012, 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 4.000% Senior Notes due 2022. See Note 10.

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the 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 2013, the Partnership extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2014. 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.

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of December 31, 2013 excluding the Hilight and Newcastle assets:

per barrel except natural gas	2014					2015					2016
Ethane	$	18.36	−	$	30.53	$	18.41	−	$	23.41	$	23.11
Propane	$	46.47	−	$	53.78	$	47.08	−	$	52.99	$	52.90
Isobutane	$	61.24	−	$	75.13	$	62.09	−	$	74.02	$	73.89
Normal butane	$	53.89	−	$	66.01	$	54.62	−	$	65.04	$	64.93
Natural gasoline	$	71.85	−	$	83.04	$	72.88	−	$	81.82	$	81.68
Condensate	$	75.22	−	$	83.04	$	76.47	−	$	81.82	$	81.68
Natural gas (per MMBtu)	$	4.45	−	$	6.20	$	4.66	−	$	5.96	$	4.87

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Below is a summary of the fixed prices or ranges on the Partnership’s outstanding commodity price swap agreements for the Hilight and Newcastle assets as of December 31, 2013:

per barrel except natural gas	2014
Propane				$	40.38
Normal butane	$	64.73	−	$	66.83
Natural gasoline				$	90.89
Condensate				$	87.30
Natural gas (per MMBtu)				$	3.45

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

	Year Ended December 31,
thousands	2013			2012			2011
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	21,382		$	37,665		$	33,845
Natural gas liquids sales	102,076			66,260			(36,802		)
Total	123,458			103,925			(2,957		)
Losses on commodity price swap agreements related to purchases (2)	(85,294		)	(89,710		)	(27,234		)
Net gains (losses) on commodity price swap agreements	$	38,164		$	14,215		$	(30,191	)

⁽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. For the years ended December 31, 2013, 2012 and 2011, 57%, 64% and 67%, respectively, of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) was attributable to natural gas production owned or controlled by Anadarko. For the years ended December 31, 2013, 2012 and 2011, 56%, 59% and 64%, respectively, of the Partnership’s processing throughput (excluding equity investment throughput and volumes measured in barrels) was attributable to natural gas production owned or controlled by Anadarko.

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

Omnibus agreement. Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing; and midstream administration. Anadarko, in accordance with the partnership and omnibus agreements, determines, in its reasonable discretion, amounts to be reimbursed by the Partnership in exchange for services provided under the omnibus agreement. See Summary of affiliate transactions below.

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

The following table summarizes the amounts the Partnership reimbursed to Anadarko:

	Year Ended December 31,
thousands	2013		2012		2011
General and administrative expenses	$	16,882	$	14,904	$	11,754
Public company expenses	7,152		6,830		7,735
Total reimbursement	$	24,034	$	21,734	$	19,489

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 beginning on 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.

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

WES LTIP. The general partner awards phantom units under the WES LTIP primarily to its independent directors and its Chief Executive Officer. 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 $0.6 million, $0.4 million and $0.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, there was $0.6 million of unrecognized compensation expense attributable to the outstanding awards under the WES LTIP, of which $0.5 million will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 1.4 years.

The following table summarizes WES LTIP award activity for the years ended December 31, 2013, 2012 and 2011:

	2013				2012				2011
	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	$	41.77	25,619		$	33.92	23,978		$	20.19	17,503
Vested	$	41.28	(14,695	)	$	33.20	(14,260	)	$	20.51	(15,119	)
Granted	$	62.49	5,920		$	45.91	15,901		$	35.66	21,594
Phantom units outstanding at end of year	$	49.47	16,844		$	41.77	25,619		$	33.92	23,978

WGP LTIP and Anadarko Incentive Plans. For the years ended December 31, 2013, 2012 and 2011, the Partnership’s general and administrative expenses included $3.0 million, $3.3 million and $2.5 million, respectively, of equity-based compensation expense, allocated to the Partnership by WGP and Anadarko, for awards granted to the executive officers of the general partner and other employees under the WGP LTIP and Anadarko Incentive Plans. Of these amounts, $2.9 million, $3.2 million and $1.0 million are reflected as a contribution to partners’ capital in the Partnership’s consolidated statements of equity and partners’ capital for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, the Partnership estimated that $5.5 million of unrecognized compensation expense attributable to the WGP LTIP and the Anadarko Incentive Plans (excluding performance-based awards) will be allocated to the Partnership over a weighted-average period of 2.1 years.

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

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

The Incentive Plan. For the years ended December 31, 2012 and 2011, the Partnership’s general and administrative expenses included $68.8 million and $11.4 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” (defined below) 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 were valued at $634.00 per UAR.

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

	Year Ended December 31,
	2013		2012		2011		2013		2012		2011
thousands	Purchases						Sales
Cash consideration	$	11,211	$	24,705	$	3,837	$	85	$	760	$	382
Net carrying value	5,309		8,009		1,998		38		393		316
Partners’ capital adjustment	$	5,902	$	16,696	$	1,839	$	47	$	367	$	66

Contributions in aid of construction costs from affiliates. During the fourth quarter of 2013, a subsidiary of Anadarko entered into an aid in construction agreement with the Partnership, whereby the Partnership will construct five receipt-point facilities at the Brasada facility that will serve the Anadarko subsidiary. Such subsidiary will reimburse the Partnership for costs associated with construction of the receipt points. These reimbursements are presented within the investing section of the Partnership’s consolidated statements of cash flows as “Contributions in aid of construction costs from affiliates.”

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes affiliate transactions, which include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas:

	Year ended December 31,
thousands	2013		2012		2011
Revenues (1)	$	805,526	$	688,026	$	647,419
Equity income, net	22,948		16,042		11,261
Cost of product (1)	129,045		145,250		83,722
Operation and maintenance (2)	56,435		51,237		51,339
General and administrative (3)	23,354		92,847		33,305
Operating expenses	208,834		289,334		168,366
Interest income, net (4)	16,900		16,900		24,106
Interest expense (5)	—		2,766		4,935
Distributions to unitholders (6)	169,150		98,280		68,039
Contributions from noncontrolling interest owners (7)	—		12,588		16,476
Distributions to noncontrolling interest owners (7)	—		6,528		9,437

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

⁽²⁾  Represents expenses incurred on 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 on 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 The Incentive Plan and WGP LTIP and Anadarko Incentive Plans within this Note 5).

⁽⁴⁾  Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets and the Bison 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⁾  For the year ended December 31, 2012, includes 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 facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

⁽⁶⁾  Represents distributions paid under the partnership agreement.

⁽⁷⁾  As described in Note 2, the Partnership acquired the additional Chipeta interest 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, 2013

Income Tax Disclosure [Abstract]

Income Taxes

6.  INCOME TAXES

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

	Year Ended December 31,
thousands	2013			2012			2011
Current income tax expense (benefit)
Federal income tax expense (benefit)	$	(30,176	)	$	(7,576	)	$	15,248
State income tax expense (benefit)	640			(1,843		)	322
Total current income tax expense (benefit)	(29,536		)	(9,419		)	15,570
Deferred income tax expense (benefit)
Federal income tax expense	32,930			22,324			13,075
State income tax expense (benefit)	(1,039		)	7,785			3,505
Total deferred income tax expense	31,891			30,109			16,580
Total income tax expense	$	2,355		$	20,690		$	32,150

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	2013			2012			2011
Income before income taxes	$	287,798		$	169,957		$	239,011
Statutory tax rate	—		%	—		%	—		%
Tax computed at statutory rate	$	—		$	—		$	—
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition	3,090			17,226			29,502
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)	624			2,206			1,984
Texas margin tax expense (benefit)	(1,359		)	1,258			664
Income tax expense	$	2,355		$	20,690		$	32,150
Effective tax rate	1		%	12		%	13		%

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

	December 31,
thousands	2013			2012
Credit carryforwards	$	14		$	14
Net current deferred income tax assets	14			14
Depreciable property	(38,528		)	(47,554		)
Credit carryforwards	527			541
Other	3			(136		)
Net long-term deferred income tax liabilities	(37,998		)	(47,149		)
Total net deferred income tax liabilities	$	(37,984	)	$	(47,135	)

Credit carryforwards, which are available for use on future income tax returns, consist of $0.5 million of state income tax credits that expire in 2026.

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Components of Working Capital

12 Months Ended

Dec. 31, 2013

Components Of Working Capital [Abstract]

Components of Working Capital

8.  COMPONENTS OF WORKING CAPITAL

A summary of other current assets is as follows:

	December 31,
thousands	2013		2012
Natural gas liquids inventory	$	2,584	$	1,678
Natural gas imbalance receivables	3,605		1,663
Prepaid insurance	2,123		1,897
Other	1,710		1,760
Total other current assets	$	10,022	$	6,998

8.  COMPONENTS OF WORKING CAPITAL (CONTINUED)

A summary of accrued liabilities is as follows:

	December 31,
thousands	2013		2012
Accrued capital expenditures	$	94,750	$	112,311
Accrued plant purchases	21,396		16,350
Accrued interest expense	18,119		15,868
Short-term asset retirement obligations	1,966		1,711
Short-term remediation and reclamation obligations	562		799
Other	218		612
Total accrued liabilities	$	137,011	$	147,651

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Components of Working Capital - Other Current Assets Table (details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Other Current Assets [Line Items]
Natural gas liquids inventory	$ 2,584		$ 1,678
Natural gas imbalance receivables	3,605		1,663
Prepaid insurance	2,123		1,897
Other	1,710		1,760
Other current assets	$ 10,022	[1],[2]	$ 6,998	[1],[2]

[1] Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of December 31, 2013 and 2012, respectively.

[2] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Asset Retirement Obligations Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Carrying amount of asset retirement obligations at beginning of year	$ 66,723	$ 64,345
Liabilities incurred	14,143	9,414
Liabilities settled	(1,943)	(786)
Accretion expense	4,326	4,270
Revisions in estimated liabilities	(5,214)	(10,520)
Carrying amount of asset retirement obligations at end of year	$ 78,035	$ 66,723

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Property, Plant and Equipment - Additional Information (details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012 Gathering System [Member]	Dec. 31, 2012 Equipment [Member]	Dec. 31, 2011 Equipment [Member]	Dec. 31, 2011 Pipelines And Equipment [Member]
Property, Plant and Equipment [Line Items]
Impairment	$ 1.2	$ 6.0	$ 0.6	$ 7.3	$ 3.0

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Summary of Significant Accounting Policies - Equity Method Investment Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Balance	$ 219,766	[1]
Investment earnings (loss), net of amortization	22,948	[1],[2],[3]	16,042	[1],[2],[3]	11,261	[1],[2],[3]
Contributions	294,693	[1]	108,457	[1]	6,203	[1]
Distributions	(17,698)	[1],[3]	(20,660)	[1],[3]	(15,999)	[1],[3]
Distributions in excess of cumulative earnings	(4,438)	[1],[3]	0	[1],[3]	0	[1],[3]
Balance	593,400	[1]	219,766	[1]
Fort Union [Member]
Schedule of Equity Method Investments [Line Items]
Balance	23,453	[4]	22,268	[4]
Initial investment	0	[4]	0	[4]
Investment earnings (loss), net of amortization	6,273	[4]	6,383	[4]
Contributions	16	[4]	0	[4]
Capitalized interest	0	[4]
Distributions	(4,570)	[4]	(5,198)	[4]
Distributions in excess of cumulative earnings	0	[4]
Balance	25,172	[4]	23,453	[4]
Table Text Block Supplement [Abstract]
Approval Percentage	65.00%
White Cliffs [Member]
Schedule of Equity Method Investments [Line Items]
Balance	17,567	[5]	17,710	[5]
Initial investment	0	[5]	0	[5]
Investment earnings (loss), net of amortization	9,681	[5]	7,871	[5]
Contributions	19,087	[5]	862	[5]
Capitalized interest	0	[5]
Distributions	(9,099)	[5]	(8,876)	[5]
Distributions in excess of cumulative earnings	(2,197)	[5]
Balance	35,039	[5]	17,567	[5]
Table Text Block Supplement [Abstract]
Approval Percentage	75.00%
Rendezvous [Member]
Schedule of Equity Method Investments [Line Items]
Balance	65,110	[6]	69,839	[6]
Initial investment	0	[6]	0	[6]
Investment earnings (loss), net of amortization	2,088	[6]	1,857	[6]
Contributions	0	[6]	0	[6]
Capitalized interest	0	[6]
Distributions	(4,029)	[6]	(6,586)	[6]
Distributions in excess of cumulative earnings	(2,241)	[6]
Balance	60,928	[6]	65,110	[6]
Table Text Block Supplement [Abstract]
Approval Percentage	100.00%
MontBelvieuJointVenture [Member]
Schedule of Equity Method Investments [Line Items]
Balance	0	[7]	0	[7]
Initial investment	78,129	[7]	0	[7]
Investment earnings (loss), net of amortization	5,690	[7]	0	[7]
Contributions	37,309	[7]	0	[7]
Capitalized interest	1,352	[7]
Distributions	0	[7]	0	[7]
Distributions in excess of cumulative earnings	0	[7]
Balance	122,480	[7]	0	[7]
Table Text Block Supplement [Abstract]
Approval Percentage	50.00%
Texas Express Gathering Limited Liability Company [Member]
Schedule of Equity Method Investments [Line Items]
Balance	9,033	[8]	0	[8]
Initial investment	0	[8]	9,086	[8]
Investment earnings (loss), net of amortization	93	[8]	(53)	[8]
Contributions	6,732	[8]	0	[8]
Capitalized interest	791	[8]
Distributions	0	[8]	0	[8]
Distributions in excess of cumulative earnings	0	[8]
Balance	16,649	[8]	9,033	[8]
Table Text Block Supplement [Abstract]
Approval Percentage	50.00%
Texas Express Pipeline Limited Liability Company [Member]
Schedule of Equity Method Investments [Line Items]
Balance	80,737	[9]	6,110	[9]
Initial investment	0	[9]	0	[9]
Investment earnings (loss), net of amortization	(776)	[9]	(4)	[9]
Contributions	108,969	[9]	74,631	[9]
Capitalized interest	8,801	[9]
Distributions	0	[9]	0	[9]
Distributions in excess of cumulative earnings	0	[9]
Balance	197,731	[9]	80,737	[9]
Table Text Block Supplement [Abstract]
Approval Percentage	50.00%
Front Range Pipeline Limited Liability Company [Member]
Schedule of Equity Method Investments [Line Items]
Balance	23,866	[10]	0	[10]
Initial investment	0	[10]	23,878	[10]
Investment earnings (loss), net of amortization	(101)	[10]	(12)	[10]
Contributions	105,547	[10]	0	[10]
Capitalized interest	6,089	[10]
Distributions	0	[10]	0	[10]
Distributions in excess of cumulative earnings	0	[10]
Balance	$ 135,401	[10]	$ 23,866	[10]
Table Text Block Supplement [Abstract]
Approval Percentage	50.00%

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Income earned from equity investments is classified as affiliate. See Note 1.

[3] Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

[4] 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.

[5] 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.

[6] 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.

[7] The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.

[8] The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

[9] The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

[10] The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

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Transactions With Affiliates - Commodity Price Per Unit Table (details)	Dec. 31, 2013
Ethane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	23.11
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 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
Propane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.90
Propane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	46.47
Propane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	47.08
Propane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.78
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 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 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 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 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 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 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
Condensate [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.68
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 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
Natural Gas (per MMbtu) [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.87
Natural Gas (per MMbtu) [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.45
Natural Gas (per MMbtu) [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	4.66
Natural Gas (per MMbtu) [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	6.20
Natural Gas (per MMbtu) [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	5.96
Highlight And Newcastle [Member] | Propane [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	40.38
Highlight And Newcastle [Member] | Normal Butane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	64.73
Highlight And Newcastle [Member] | Normal Butane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	66.83
Highlight And Newcastle [Member] | Natural Gasoline [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	90.89
Highlight And Newcastle [Member] | Condensate [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	87.30
Highlight And Newcastle [Member] | Natural Gas (per MMbtu) [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	3.45

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business combinations policy

Presentation of Partnership assets. The “Partnership assets” refer collectively to the assets owned and interests accounted for under the equity method by the Partnership as of December 31, 2013. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s general partner, each acquisition of Partnership 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 Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of the Partnership 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 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 Partnership assets during the periods reported. Net income attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income per common unit or subordinated unit.

Anadarko-Operated Marcellus Interest acquisition. The Anadarko-Operated Marcellus Interest acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Anadarko-Operated Marcellus Interest were included in the Partnership’s consolidated statements of income beginning on the acquisition date in the first quarter of 2013.

Due to Anadarko’s control of the Partnership through its ownership and control of WGP, the acquisition of the TEFR Interests 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 TEFR Interests from 2011 when Anadarko made its initial investment in the respective businesses. The consolidated financial statements for periods prior to the Partnership’s acquisition of the TEFR Interests 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 TEFR Interests during the period reported.

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, utilizing 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 condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions 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.

Note receivable from and amounts payable to Anadarko. Concurrently 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 $296.7 million and $334.8 million at December 31, 2013 and 2012, 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.

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, 2013, the third-party accounts receivable balance was net of the associated bad-debt reserve of $13,000. As of December 31, 2012, there was no reserve for bad debts.

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, 2013, natural gas imbalance receivables and payables were $3.6 million and $2.5 million, respectively. As of December 31, 2012, natural gas imbalance receivables and payables were $1.7 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 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 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 to Note 7 for a description of impairments recorded during the years ended December 31, 2013, 2012 and 2011.

Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. These cash receipts are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. See Note 5.

Capitalized interest policy

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

Mont Belvieu JV acquisition. The acquisition purchase price represented the Partnership’s 25% share of construction costs incurred by the joint venture partner and 25% of the capitalized interest charged to the financial statements of the Mont Belvieu JV up to the date of acquisition. The allocated capitalized interest is reflected as a component of the equity investment balance recorded upon acquisition. Based on the total estimated net project cost, the construction of the fractionation facilities owned by the Mont Belvieu JV is considered a significant project and satisfies criteria for capitalization of interest. Capitalization of interest subsequent to the acquisition is treated as a basis difference between the cost of the investment and the underlying equity in the net assets of the Mont Belvieu JV. Upon completion of construction in the fourth quarter of 2013, the Partnership began amortizing the capitalized interest recognized subsequent to the Mont Belvieu JV acquisition. This amortization is reflected as an adjustment to equity earnings from the Mont Belvieu JV.

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 paid to 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 such net assets on their respective acquisition dates. The consolidated balance sheets as of December 31, 2013 and 2012, include goodwill of $105.3 million, the impairment of which (if applicable) is not 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. An initial qualitative assessment may be performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. 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 qualitative evaluation as of October 1, 2013, 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, of (i) contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which are amortized on a straight-line basis over 50 years, and (ii) interconnect agreements at Chipeta entered into in November 2012, amortized on a straight-line basis over 10 years.

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, 2013, the carrying value of the Partnership’s intangible assets was $53.6 million, net of $3.4 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, 2012, the carrying value of the Partnership’s intangible assets was $55.5 million, net of $2.0 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 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 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 ultimately 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 sales 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 “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,139,027 units remained available for future issuance as of December 31, 2013. Upon vesting of each phantom unit awarded under the WES LTIP, 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 WES 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 WES 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 Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) for the year ended December 31, 2013, (ii) the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) for the years ended December 31, 2012 and 2011, and (iii) 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”) for all periods presented. 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. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized. However, distribution equivalent rights awarded in tandem with equity-or liability-based awards are paid in cash and reflected within financing cash flows in the consolidated statements of cash flows. 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 beginning on 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 standards 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, 2013 or 2012.

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 earned on and subsequent to the date of the acquisition 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. Net income attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income per common unit or subordinated unit. See Note 4.

Capital lease, lessor income policy

Other assets. For the years ended December 31, 2013 and 2012, other current assets on the consolidated balance sheets includes $0.4 million 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 December 2014. Other assets 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, 2013

Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract]

Commodity Price Swap Agreements Table

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of December 31, 2013 excluding the Hilight and Newcastle assets:

per barrel except natural gas	2014					2015					2016
Ethane	$	18.36	−	$	30.53	$	18.41	−	$	23.41	$	23.11
Propane	$	46.47	−	$	53.78	$	47.08	−	$	52.99	$	52.90
Isobutane	$	61.24	−	$	75.13	$	62.09	−	$	74.02	$	73.89
Normal butane	$	53.89	−	$	66.01	$	54.62	−	$	65.04	$	64.93
Natural gasoline	$	71.85	−	$	83.04	$	72.88	−	$	81.82	$	81.68
Condensate	$	75.22	−	$	83.04	$	76.47	−	$	81.82	$	81.68
Natural gas (per MMBtu)	$	4.45	−	$	6.20	$	4.66	−	$	5.96	$	4.87

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Below is a summary of the fixed prices or ranges on the Partnership’s outstanding commodity price swap agreements for the Hilight and Newcastle assets as of December 31, 2013:

per barrel except natural gas	2014
Propane				$	40.38
Normal butane	$	64.73	−	$	66.83
Natural gasoline				$	90.89
Condensate				$	87.30
Natural gas (per MMBtu)				$	3.45

Gains (Losses) on Commodity Price Swap Agreements Table

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

	Year Ended December 31,
thousands	2013			2012			2011
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	21,382		$	37,665		$	33,845
Natural gas liquids sales	102,076			66,260			(36,802		)
Total	123,458			103,925			(2,957		)
Losses on commodity price swap agreements related to purchases (2)	(85,294		)	(89,710		)	(27,234		)
Net gains (losses) on commodity price swap agreements	$	38,164		$	14,215		$	(30,191	)

⁽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

	2013				2012				2011
	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	$	41.77	25,619		$	33.92	23,978		$	20.19	17,503
Vested	$	41.28	(14,695	)	$	33.20	(14,260	)	$	20.51	(15,119	)
Granted	$	62.49	5,920		$	45.91	15,901		$	35.66	21,594
Phantom units outstanding at end of year	$	49.47	16,844		$	41.77	25,619		$	33.92	23,978

Equipment Purchase and Sale

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

	Year Ended December 31,
	2013		2012		2011		2013		2012		2011
thousands	Purchases						Sales
Cash consideration	$	11,211	$	24,705	$	3,837	$	85	$	760	$	382
Net carrying value	5,309		8,009		1,998		38		393		316
Partners’ capital adjustment	$	5,902	$	16,696	$	1,839	$	47	$	367	$	66

Related Party Transactions Tables

The following table summarizes the amounts the Partnership reimbursed to Anadarko:

	Year Ended December 31,
thousands	2013		2012		2011
General and administrative expenses	$	16,882	$	14,904	$	11,754
Public company expenses	7,152		6,830		7,735
Total reimbursement	$	24,034	$	21,734	$	19,489

The following table summarizes affiliate transactions, which include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas:

	Year ended December 31,
thousands	2013		2012		2011
Revenues (1)	$	805,526	$	688,026	$	647,419
Equity income, net	22,948		16,042		11,261
Cost of product (1)	129,045		145,250		83,722
Operation and maintenance (2)	56,435		51,237		51,339
General and administrative (3)	23,354		92,847		33,305
Operating expenses	208,834		289,334		168,366
Interest income, net (4)	16,900		16,900		24,106
Interest expense (5)	—		2,766		4,935
Distributions to unitholders (6)	169,150		98,280		68,039
Contributions from noncontrolling interest owners (7)	—		12,588		16,476
Distributions to noncontrolling interest owners (7)	—		6,528		9,437

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

⁽²⁾ Represents expenses incurred on 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 on 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 The Incentive Plan and WGP LTIP and Anadarko Incentive Plans within this Note 5).

⁽⁴⁾ Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets and the Bison 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⁾ For the year ended December 31, 2012, includes 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 facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

⁽⁶⁾ Represents distributions paid under the partnership agreement.

⁽⁷⁾ As described in Note 2, the Partnership acquired the additional Chipeta interest 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 and Partners' Capital - Supplemental Calculation of Net Income per Unit Table (details) (USD $) Share data in Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Earnings Per Unit [Line Items]
Limited partners' interest in net income	$ 200,866,000	[1],[2]	$ 78,897,000	[1],[2]	$ 131,560,000	[1],[2]
Pre-acquisition net (income) loss allocated to Anadarko	4,128,000	[1]	27,391,000	[1]	52,599,000	[1]
General partner interest in net (income) loss	69,633,000	[1],[2]	28,089,000	[1],[2]	8,599,000	[1],[2]
Supplemental [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	204,910,000		105,741,000		183,108,000
Reallocation of general partner interest in net (income) loss	(69,717,000)		(28,636,000)		(9,650,000)
Common Units [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	200,866,000		78,897,000		110,542,000
Common Units [Member] | Supplemental [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	204,910,000		105,741,000		156,132,000
Subordinated [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	0		0		21,018,000
Subordinated [Member] | Supplemental [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income	$ 0		$ 0		$ 26,976,000
Limited Partner [Member] | Common Units [Member]
Earnings Per Unit [Line Items]
Supplemental net income per unit - basic and diluted	$ 1.83	[1]	$ 0.84	[1]	$ 1.64	[1]
Weighted average units outstanding - basic and diluted	109,872		93,936		67,333
Limited Partner [Member] | Common Units [Member] | Supplemental [Member]
Earnings Per Unit [Line Items]
Supplemental net income per unit - basic and diluted	$ 1.86		$ 1.13		$ 2.32
Limited Partner [Member] | Subordinated [Member]
Earnings Per Unit [Line Items]
Supplemental net income per unit - basic and diluted	$ 0	[1],[3]	$ 0	[1],[3]	$ 1.28	[1],[3]
Weighted average units outstanding - basic and diluted	0		0		16,431
Limited Partner [Member] | Subordinated [Member] | Supplemental [Member]
Earnings Per Unit [Line Items]
Supplemental net income per unit - basic and diluted	$ 0		$ 0		$ 1.64

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Represents net income earned on and subsequent to the date of 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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Acquisitions - Impact to Historical Consolidated Statement of Income (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues	$ 1,029,763	[1]	$ 894,476	[1]	$ 858,144	[1]
Equity income (loss), net	22,948	[1],[2],[3]	16,042	[1],[2],[3]	11,261	[1],[2],[3]
Net income (loss)	285,443	[1]	149,267	[1]	206,861	[1]
Partnership Historical [Member]
Revenues	1,029,763		894,476		858,144
Equity income (loss), net	23,732		16,111		11,261
Net income (loss)	285,952		149,311		206,861
Texas Express And Front Range [Member]
Revenues	0		0		0
Equity income (loss), net	(784)		(69)		0
Net income (loss)	$ (509)		$ (44)		$ 0

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Income earned from equity investments is classified as affiliate. See Note 1.

[3] Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
GP units issued	2,394,345		2,135,930
General partner units outstanding	2,394,345		2,135,930
Accounts receivable, net	$ 84,060	[1],[2]	$ 50,233	[1],[2]
Other current assets	10,022	[1],[3]	6,998	[1],[3]
Accounts and natural gas imbalance payables	39,589	[1],[4]	25,154	[1],[4]
Accrued liabilities	137,011	[1],[5]	147,651	[1],[5]
Affiliated Entity [Member]
Accounts receivable, net	47,900		19,100
Other current assets	100		400
Accounts and natural gas imbalance payables	2,300		2,500
Accrued liabilities	$ 100		$ 100
Common Units [Member]
Common units issued	117,322,812		104,660,553
Units outstanding	117,322,812		104,660,553

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $47.9 million and $19.1 million as of December 31, 2013 and 2012, respectively.

[3] Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of December 31, 2013 and 2012, respectively.

[4] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.3 million and $2.5 million as of December 31, 2013 and 2012, respectively.

[5] Accrued liabilities include amounts payable to affiliates of $0.1 million as of December 31, 2013 and 2012.

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Acquisitions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Acquisitions

2.  ACQUISITIONS

In May 2008, concurrently with the closing of the Partnership’s IPO, Anadarko contributed to the Partnership the assets and liabilities of Anadarko Gathering Company LLC, Pinnacle Gas Treating LLC, and MIGC LLC. In December 2008, the Partnership 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. In July 2009, the Partnership closed on the acquisition of a 51% membership interest in Chipeta from Anadarko. The Partnership closed the acquisitions of Anadarko’s Granger and Wattenberg assets in January 2010 and August 2010, respectively. In September 2010, the Partnership acquired a 10% interest in White Cliffs. See Note 12.

2.  ACQUISITIONS (CONTINUED)

The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2011, 2012 and 2013, 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
Platte Valley (1)	02/28/2011	100	%	$	303,000	$	602	—	—
Bison (2)	07/08/2011	100	%	—		25,000		2,950,284	60,210
MGR (3)	01/13/2012	100	%	299,000		159,587		632,783	12,914
Chipeta (4)	08/01/2012	24	%	—		128,250		151,235	3,086
Non-Operated Marcellus Interest(5)	03/01/2013	33.75	%	250,000		215,500		449,129	—
Anadarko-Operated Marcellus Interest(6)	03/08/2013	33.75	%	133,500		—		—	—
Mont Belvieu JV(7)	06/05/2013	25	%	—		78,129		—	—
OTTCO(8)	09/03/2013	100	%	27,500		—		—	—

⁽¹⁾  The Partnership acquired (i) a natural gas gathering system and related compression and other ancillary equipment and (ii) cryogenic gas processing facilities from a third party. These assets are located in the Denver-Julesburg Basin. The acquisition is referred to as the “Platte Valley acquisition.”

⁽²⁾  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.” 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.

⁽³⁾  The assets acquired from Anadarko consisted 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.”

⁽⁴⁾  The Partnership acquired Anadarko’s additional Chipeta interest (as described in Note 1). The Partnership received 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.

⁽⁵⁾  The Partnership acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in the Partnership.

⁽⁶⁾  The Partnership acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Anadarko-Operated Marcellus Interest acquisition below for further information, including the final allocation of the purchase price.

⁽⁷⁾  The Partnership acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See Mont Belvieu JV acquisition below for further information.

⁽⁸⁾  The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.

2.  ACQUISITIONS (CONTINUED)

Anadarko-Operated Marcellus Interest acquisition. The Anadarko-Operated Marcellus Interest acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Anadarko-Operated Marcellus Interest were included in the Partnership’s consolidated statements of income beginning on the acquisition date in the first quarter of 2013.

The following is the final allocation of the purchase price, including $1.1 million of post-closing purchase price adjustments, to the assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition as of the acquisition date:

thousands
Property, plant and equipment	$	134,819
Asset retirement obligations	(174		)
Total purchase price	$	134,645

The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition. The fair values of the interests in the land, right-of-way contracts, and gathering systems were based on the market and income approaches. 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.

The following table presents pro forma condensed financial information of the Partnership as if the Anadarko-Operated Marcellus Interest acquisition had occurred on January 1, 2012:

	Year Ended December 31,
thousands except per-unit amounts	2013		2012
Revenues	$	1,031,017	$	899,353
Net income	285,591		147,238
Net income attributable to Western Gas Partners, LP	274,775		132,348
Net income per common unit - basic and diluted	$	1.82	$	0.82

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Anadarko-Operated Marcellus Interest acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s pro forma information in the table above includes $14.1 million of revenues and $0.7 million of operating expenses, excluding depreciation, amortization and impairments, attributable to the Anadarko-Operated Marcellus Interest that are included in the Partnership’s consolidated statement of income for the year ended December 31, 2013. The pro forma adjustments reflect pre-acquisition results of the Anadarko-Operated Marcellus Interest including (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the purchase price allocated to property, plant and equipment and estimated useful lives; and (c) interest on the Partnership’s borrowings under its revolving credit facility to finance the Anadarko-Operated Marcellus Interest acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the Anadarko-Operated Marcellus Interest acquisition, nor any future acquisition related expenses.

2.  ACQUISITIONS (CONTINUED)

Mont Belvieu JV acquisition. The acquisition purchase price represented the Partnership’s 25% share of construction costs incurred by the joint venture partner and 25% of the capitalized interest charged to the financial statements of the Mont Belvieu JV up to the date of acquisition. The allocated capitalized interest is reflected as a component of the equity investment balance recorded upon acquisition. Based on the total estimated net project cost, the construction of the fractionation facilities owned by the Mont Belvieu JV is considered a significant project and satisfies criteria for capitalization of interest. Capitalization of interest subsequent to the acquisition is treated as a basis difference between the cost of the investment and the underlying equity in the net assets of the Mont Belvieu JV. Upon completion of construction in the fourth quarter of 2013, the Partnership began amortizing the capitalized interest recognized subsequent to the Mont Belvieu JV acquisition. This amortization is reflected as an adjustment to equity earnings from the Mont Belvieu JV.

TEFR Interests Acquisition. On March 3, 2014, the Partnership acquired Anadarko’s 20% interest in TEP and TEG, and a 33.33% interest in FRP (collectively, the “TEFR Interests acquisition”) for $375.0 million. The Partnership financed the TEFR Interests acquisition with $6.3 million of cash on hand, borrowings of $350.0 million on the 2014 WES RCF, and the issuance of 308,490 WES common units to Anadarko at an implied price of $60.78 per unit. See Note 12.

Due to Anadarko’s control of the Partnership through its ownership and control of WGP, the acquisition of the TEFR Interests 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 TEFR Interests from 2011 when Anadarko made its initial investment in the respective businesses. The consolidated financial statements for periods prior to the Partnership’s acquisition of the TEFR Interests 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 TEFR Interests during the period reported.

The following table presents the impact of the TEFR Interests on revenue, equity income (loss), net and net income (loss) as presented in the Partnership’s historical consolidated statements of income:

	Year Ended December 31, 2013
thousands	Partnership Historical		TEFR Interests			Combined
Revenues	$	1,029,763	$	—		$	1,029,763
Equity income (loss), net	23,732		(784		)	22,948
Net income (loss)	$	285,952	$	(509	)	$	285,443

	Year Ended December 31, 2012
thousands	Partnership Historical		TEFR Interests			Combined
Revenues	$	894,476	$	—		$	894,476
Equity income (loss), net	16,111		(69		)	16,042
Net income (loss)	$	149,311	$	(44	)	$	149,267

	Year Ended December 31, 2011
thousands	Partnership Historical		TEFR Interests		Combined
Revenues	$	858,144	$	—	$	858,144
Equity income (loss), net	11,261		—		11,261
Net income (loss)	$	206,861	$	—	$	206,861

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Income Taxes - Components of Income Tax Expense Table (details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Current Income Tax Expense (Benefit) [Abstract]
Federal income tax expense (benefit)	$ (30,176)		$ (7,576)		$ 15,248
State income tax expense (benefit)	640		(1,843)		322
Total current income tax expense (benefit)	(29,536)		(9,419)		15,570
Deferred Income Tax Expense (Benefit) [Abstract]
Federal income tax expense	32,930		22,324		13,075
State income tax expense (benefit)	(1,039)		7,785		3,505
Total deferred income tax expense	31,891	[1]	30,109	[1]	16,580	[1]
Total income tax expense	$ 2,355	[1]	$ 20,690	[1]	$ 32,150	[1]

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Debt and Interest Expense - Interest Expense Table (details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Debt Instrument [Line Items]
Interest Expense	$ 51,797,000	[1]	$ 42,060,000	[1]	$ 30,345,000	[1]
Senior Notes 4 Percent Due 2022 [Member]
Table Text Block Supplement [Abstract]
Amortization related to Senior Notes					500,000
Senior Notes 5 Point 375 Percent Due 2021 [Member] | Senior Notes 4 Percent Due 2022 [Member]
Table Text Block Supplement [Abstract]
Amortization related to Senior Notes	1,000,000		1,100,000
Third Parties [Member]
Debt Instrument [Line Items]
Interest expense on long-term debt	59,293,000		41,171,000		20,533,000
Amortization of debt issuance costs and commitment fees	4,449,000	[2]	4,319,000	[2]	5,297,000	[2]
Capitalized interest	(11,945,000)		(6,196,000)		(420,000)
Interest Expense	51,797,000		39,294,000		25,410,000
Affiliated Entity [Member]
Debt Instrument [Line Items]
Interest expense on note payable to Anadarko	0	[3]	2,440,000	[3]	4,935,000	[3]
Interest expense on affiliate balances	0	[4]	326,000	[4]	0	[4]
Interest Expense	0	[5]	2,766,000	[5]	4,935,000	[5]
Senior Notes 2 Point 6 Percent Due 2018 [Member]
Table Text Block Supplement [Abstract]
Amortization related to Senior Notes	$ 200,000

[1] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

[2] For the years ended December 31, 2013 and 2012, includes $1.0 million and $1.1 million, respectively, of amortization of (i) the original issue discount for the June 2012 offering of the 2022 Notes, 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. In addition, for the year ended December 31, 2013, includes the amortization of the original issue discount and underwriters’ fees for the 2018 Notes of $0.2 million. 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.

[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 facility and Lancaster plant. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant.

[5] For the year ended December 31, 2012, includes 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 facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

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Income Taxes (tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Components of Income Tax Expense Table

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

	Year Ended December 31,
thousands	2013			2012			2011
Current income tax expense (benefit)
Federal income tax expense (benefit)	$	(30,176	)	$	(7,576	)	$	15,248
State income tax expense (benefit)	640			(1,843		)	322
Total current income tax expense (benefit)	(29,536		)	(9,419		)	15,570
Deferred income tax expense (benefit)
Federal income tax expense	32,930			22,324			13,075
State income tax expense (benefit)	(1,039		)	7,785			3,505
Total deferred income tax expense	31,891			30,109			16,580
Total income tax expense	$	2,355		$	20,690		$	32,150

Tax Rate Reconciliation Table

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	2013			2012			2011
Income before income taxes	$	287,798		$	169,957		$	239,011
Statutory tax rate	—		%	—		%	—		%
Tax computed at statutory rate	$	—		$	—		$	—
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition	3,090			17,226			29,502
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)	624			2,206			1,984
Texas margin tax expense (benefit)	(1,359		)	1,258			664
Income tax expense	$	2,355		$	20,690		$	32,150
Effective tax rate	1		%	12		%	13		%

Income Tax Temporary Differences Table

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

	December 31,
thousands	2013			2012
Credit carryforwards	$	14		$	14
Net current deferred income tax assets	14			14
Depreciable property	(38,528		)	(47,554		)
Credit carryforwards	527			541
Other	3			(136		)
Net long-term deferred income tax liabilities	(37,998		)	(47,149		)
Total net deferred income tax liabilities	$	(37,984	)	$	(47,135	)

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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			1 Months Ended		12 Months Ended	1 Months Ended							1 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		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 Limited Liability Company [Member]		Dec. 31, 2013 Chipeta Processing Limited Liability Company [Member]	Mar. 31, 2013 Non-Operated Marcellus Interest [Member]		Mar. 31, 2013 Anadarko-Operated Marcellus Interest [Member]		Jun. 30, 2013 MontBelvieuJointVenture [Member]		Jun. 30, 2013 MontBelvieuJointVenture [Member] Fractionator [Member]	Sep. 30, 2013 Overland Trail Transmission Limited Liability Company [Member]		Jul. 31, 2011 Common Units [Member] Bison [Member]		Jan. 31, 2012 Common Units [Member] Mountain Gas Resources [Member]		Aug. 31, 2012 Common Units [Member] Chipeta Processing Limited Liability Company [Member]		Mar. 31, 2013 Common Units [Member] Non-Operated Marcellus Interest [Member]		Jul. 31, 2011 General Partner [Member] Bison [Member]		Jan. 31, 2012 General Partner [Member] Mountain Gas Resources [Member]		Aug. 31, 2012 General Partner [Member] Chipeta Processing Limited Liability Company [Member]
Business Acquisition [Line Items]
Percentage acquired							100.00%	[1]	100.00%	[2]		100.00%	[3]		24.00%	[4]	75.00%	33.75%	[5]	33.75%	[6]				100.00%	[7]
Equity method investment ownership														22.00%								25.00%	[8]
Borrowings	$ 957,503	[9]	$ 1,041,648	[9]	$ 1,055,939	[9]	$ 303,000	[1]				$ 299,000	[3]					$ 250,000	[5]	$ 133,500	[6]				$ 27,500	[7]
Cash on hand							602	[1]	25,000	[2]		159,587	[3]		128,250	[4]		215,500	[5]			78,129	[8]
Units issued																											2,950,284	[2]	632,783	[3]	151,235	[4]	449,129	[5]	60,210	[2]	12,914	[3]	3,086	[4]
Table Text Block Supplement [Abstract]
Ownership interest by noncontrolling owners																	25.00%
GP units issued	2,394,345		2,135,930															9,166
Proceeds from issuance of common and general partner units, net of offering expenses	$ 740,825	[9]	$ 625,877	[9]	$ 335,317	[9]												$ 500
General partner's interest	2.00%																	2.00%
Assets, number of units											3													2

[1] The Partnership acquired (i) a natural gas gathering system and related compression and other ancillary equipment and (ii) cryogenic gas processing facilities from a third party. These assets are located in the Denver-Julesburg Basin. The acquisition is referred to as the “Platte Valley acquisition.”

[2] 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.” 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.

[3] The assets acquired from Anadarko consisted 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.”

[4] The Partnership acquired Anadarko’s additional Chipeta interest (as described in Note 1). The Partnership received 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.

[5] The Partnership acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in the Partnership.

[6] The Partnership acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Anadarko-Operated Marcellus Interest acquisition below for further information, including the final allocation of the purchase price.

[7] The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.

[8] The Partnership acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See Mont Belvieu JV acquisition below for further information.

[9] Financial information has been recast to include the financial position and results attributable to the TEFR Interests. See Note 1 and Note 2.

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Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Subsequent Events

12.  SUBSEQUENT EVENTS

Effective February 12, 2014, Anthony R. Chase resigned as a director of the Partnership’s general partner due to his appointment to the board of directors of Anadarko. In connection with his resignation and in recognition of his service, the board of directors of the Partnership’s general partner accelerated the vesting of 1,280 phantom units held by Mr. Chase. Also effective February 12, 2014, Steven D. Arnold was appointed to the board of directors as an independent director and member of the audit committee and special committee of the board of directors.

On February 26, 2014, the Partnership entered into a five-year senior unsecured revolving credit agreement (the “2014 RCF”), amending and restating the RCF, which was originally entered into in March 2011 and had an outstanding balance of $60.0 million immediately prior to closing on the 2014 RCF. The aggregate initial commitments of the 2014 RCF lenders are $1.2 billion and are expandable to a maximum of $1.5 billion. The 2014 RCF matures on February 26, 2019, and bears interest at LIBOR, plus applicable margins ranging from 0.975% to 1.45%, 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 zero to 0.45%, based upon the Partnership’s senior unsecured debt rating. The Partnership is required to pay a quarterly facility fee ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), also based upon its senior unsecured debt rating. As of February 26, 2014, there was $60.0 million outstanding on the 2014 RCF, drawn to repay amounts that were outstanding on the RCF upon entering into the 2014 RCF.

Refer to Note 2 for a description of the TEFR Interests acquisition on March 3, 2014. In connection with the TEFR Interests acquisition, the Partnership’s general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “TEFR Indemnification Agreement”) whereby such subsidiary will indemnify the Partnership’s general partner for any recourse liability it may have for 2014 RCF borrowings, or other debt financing, attributable to the TEFR Interests acquisition. The Partnership’s general partner and WGRI also amended and restated the existing indemnity agreement between them (as discussed in Note 10) to reduce the amount for which WGRI would indemnify the Partnership’s general partner by an amount equal to any amounts payable to the Partnership’s general partner under the TEFR Indemnification Agreement. The Partnership’s general partner and another wholly owned subsidiary of Anadarko also amended and restated the 2013 Indemnification Agreement (as discussed in Note 10) primarily to conform language among all the indemnity agreements with the Partnership’s general partner.