10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2013

Or

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

For the transition period from             to       

Commission file number: 001-34046

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware	26-1075808
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1201 Lake Robbins Drive The Woodlands, Texas	77380 (Zip Code)
(Address of principal executive offices)

(832) 636-6000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

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

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

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

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

There were 112,380,764 common units outstanding as of November 4, 2013.

TABLE OF CONTENTS

PART I		FINANCIAL INFORMATION	PAGE
	Item 1.	Financial Statements
		Consolidated Statements of Income for the three and nine months ended September 30, 2013 and 2012	4
		Consolidated Balance Sheets as of September 30, 2013, and December 31, 2012	5
		Consolidated Statement of Equity and Partners’ Capital for the nine months ended September 30, 2013	6
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	7
		Notes to Consolidated Financial Statements	8
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
		Cautionary Note Regarding Forward-Looking Statements	24
		Executive Summary	26
		Acquisitions	27
		Equity Offerings	28
		Results of Operations	29
		Operating Results	29
		Key Performance Metrics	37
		Liquidity and Capital Resources	40
		Contractual Obligations	46
		Off-Balance Sheet Arrangements	46
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
	Item 4.	Controls and Procedures	47
PART II		OTHER INFORMATION
	Item 1.	Legal Proceedings	47
	Item 1A.	Risk Factors	47
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
	Item 6.	Exhibits	49

2

DEFINITIONS

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

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

Btu: British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

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

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

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

Imbalance: Imbalances result from (i) differences between gas volumes nominated by customers and gas volumes received from those customers and (ii) differences between gas volumes received from customers and gas volumes delivered to those customers.

MBbls/d: One thousand barrels per day.

MMBtu: One million British thermal units.

MMcf/d: One million cubic feet per day.

Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.

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

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands except unit and per-unit amounts	2013			2012 (1)			2013			2012 (1)
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	83,606		$	61,388		$	218,680		$	182,448
Natural gas, natural gas liquids and condensate sales	129,411			115,132			371,077			324,793
Equity income and other, net	4,607			4,085			13,457			12,219
Total revenues – affiliates	217,624			180,605			603,214			519,460
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids	47,175			32,545			124,791			96,518
Natural gas, natural gas liquids and condensate sales	11,915			20,974			31,539			62,025
Other, net	1,287			610			3,330			1,717
Total revenues – third parties	60,377			54,129			159,660			160,260
Total revenues	278,001			234,734			762,874			679,720
Operating expenses
Cost of product (2)	93,516			89,107			270,059			254,719
Operation and maintenance (2)	42,757			35,493			121,165			103,304
General and administrative (2)	7,276			15,039			22,228			35,623
Property and other taxes	6,649			5,328			18,520			14,998
Depreciation, amortization and impairments	37,615			28,455			106,551			83,263
Total operating expenses	187,813			173,422			538,523			491,907
Operating income	90,188			61,312			224,351			187,813
Interest income, net – affiliates	4,225			4,225			12,675			12,675
Interest expense (3)	(13,018		)	(10,977		)	(37,483		)	(30,118		)
Other income (expense), net	439			522			1,612			(287		)
Income before income taxes	81,834			55,082			201,155			170,083
Income tax expense	58			5,080			4,431			14,588
Net income	81,776			50,002			196,724			155,495
Net income attributable to noncontrolling interests	3,376			3,423			7,467			11,956
Net income attributable to Western Gas Partners, LP	$	78,400		$	46,579		$	189,257		$	143,539
Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	78,400		$	46,579		$	189,257		$	143,539
Pre-acquisition net (income) loss allocated to Anadarko	—			(7,062		)	(4,637		)	(19,582		)
General partner interest in net (income) loss (4)	(18,693		)	(8,042		)	(47,733		)	(18,508		)
Limited partners’ interest in net income (4)	$	59,707		$	31,475		$	136,887		$	105,449
Net income per common unit – basic and diluted	$	0.53		$	0.33		$	1.26		$	1.14
Weighted average common units outstanding – basic and diluted	112,143			95,883			108,540			92,627

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

⁽²⁾  Cost of product includes product purchases from Anadarko (as defined in Note 1) of $33.8 million and $97.8 million for the three and nine months ended September 30, 2013, respectively, and $42.8 million and $115.6 million for the three and nine months ended September 30, 2012, respectively. Operation and maintenance includes charges from Anadarko of $13.5 million and $41.0 million for the three and nine months ended September 30, 2013, respectively, and $12.6 million and $38.0 million for the three and nine months ended September 30, 2012, respectively. General and administrative includes charges from Anadarko of $5.9 million and $17.3 million for the three and nine months ended September 30, 2013, respectively, and $14.2 million and $30.8 million for the three and nine months ended September 30, 2012, respectively. See Note 5.

⁽³⁾  Includes affiliate (as defined in Note 1) interest expense of zero for the three and nine months ended September 30, 2013, and $0.1 million and $2.7 million for the three and nine months ended September 30, 2012, respectively. See Note 8.

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

See accompanying Notes to Consolidated Financial Statements.

4

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

thousands except number of units	September 30, 2013		December 31, 2012(1)
ASSETS
Current assets
Cash and cash equivalents	$	38,364	$	419,981
Accounts receivable, net (2)	75,788		50,233
Other current assets (3)	8,763		6,998
Total current assets	122,915		477,212
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	4,061,389		3,432,392
Less accumulated depreciation	817,489		714,436
Net property, plant and equipment	3,243,900		2,717,956
Goodwill	105,336		105,336
Other intangible assets	54,436		55,490
Equity investments	227,566		106,130
Other assets	28,078		27,798
Total assets	$	4,042,231	$	3,749,922
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables (4)	$	19,131	$	25,154
Accrued ad valorem taxes	18,472		11,949
Income taxes payable	190		552
Accrued liabilities (5)	140,166		147,651
Total current liabilities	177,959		185,306
Long-term debt – third parties	1,518,110		1,168,278
Deferred income taxes	1,830		47,153
Asset retirement obligations and other	76,336		68,749
Total long-term liabilities	1,596,276		1,284,180
Total liabilities	1,774,235		1,469,486
Equity and partners’ capital
Common units (112,174,911 and 104,660,553 units issued and outstanding at September 30, 2013, and December 31, 2012, respectively)	2,127,040		1,957,066
General partner units (2,288,573 and 2,135,930 units issued and outstanding at September 30, 2013, and December 31, 2012, respectively)	68,585		52,752
Net investment by Anadarko	—		199,960
Total partners’ capital	2,195,625		2,209,778
Noncontrolling interests	72,371		70,658
Total equity and partners’ capital	2,267,996		2,280,436
Total liabilities, equity and partners’ capital	$	4,042,231	$	3,749,922

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

⁽²⁾  Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $40.1 million and $19.1 million as of September 30, 2013, and December 31, 2012, respectively.

⁽³⁾  Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of September 30, 2013, and December 31, 2012, respectively.

⁽⁴⁾  Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.8 million and $2.5 million as of September 30, 2013, and December 31, 2012, respectively.

⁽⁵⁾  Accrued liabilities include amounts payable to affiliates of $0.1 million as of September 30, 2013 and December 31, 2012.

See accompanying Notes to Consolidated Financial Statements.

5

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(UNAUDITED)

	Partners’ Capital
thousands	Net Investment by Anadarko			Common Units			General Partner Units			Noncontrolling Interests			Total
Balance at December 31, 2012(1)	$	199,960		$	1,957,066		$	52,752		$	70,658		$	2,280,436
Net income	4,637			136,887			47,733			7,467			196,724
Issuance of common and general partner units, net of offering expenses	—			418,517			9,278			—			427,795
Contributions from noncontrolling interest owners	—			—			—			2,247			2,247
Distributions to noncontrolling interest owners	—			—			—			(8,001		)	(8,001		)
Distributions to unitholders	—			(173,976		)	(41,139		)	—			(215,115		)
Acquisitions from affiliates	(255,635		)	(209,865		)	—			—			(465,500		)
Contributions of equity-based compensation from Anadarko	—			2,101			43			—			2,144
Net pre-acquisition contributions from (distributions to) Anadarko	4,508			—			—			—			4,508
Net distributions of other assets to Anadarko	—			(3,998		)	(82		)				(4,080		)
Elimination of net deferred tax liabilities	46,530			—			—			—			46,530
Other	—			308			—			—			308
Balance at September 30, 2013	$	—		$	2,127,040		$	68,585		$	72,371		$	2,267,996

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

See accompanying Notes to Consolidated Financial Statements.

6

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended   September 30,
thousands	2013			2012 (1)
Cash flows from operating activities
Net income	$	196,724		$	155,495
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	106,551			83,263
Non-cash equity-based compensation expense	2,564			2,769
Deferred income taxes	1,207			21,565
Debt-related amortization and other items, net	1,756			1,728
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(27,387		)	47,272
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	6,818			29,261
Change in other items, net	836			2,234
Net cash provided by operating activities	289,069			343,587
Cash flows from investing activities
Capital expenditures	(469,678		)	(403,949		)
Acquisitions from affiliates	(469,884		)	(605,960		)
Acquisitions from third parties	(240,274		)	—
Investments in equity affiliates	(45,126		)	(147		)
Proceeds from the sale of assets to affiliates	82			760
Other	(1,524		)	—
Net cash used in investing activities	(1,226,404		)	(1,009,296		)
Cash flows from financing activities
Borrowings, net of debt issuance costs	842,566			885,291
Repayments of debt	(495,000		)	(549,000		)
Increase (decrease) in outstanding checks	(3,335		)	2,534
Proceeds from the issuance of common and general partner units, net of offering expenses	427,848			216,462
Distributions to unitholders	(215,115		)	(141,505		)
Contributions from noncontrolling interest owners	2,247			26,888
Distributions to noncontrolling interest owners	(8,001		)	(14,303		)
Net contributions from (distributions to) Anadarko	4,508			60,277
Net cash provided by financing activities	555,718			486,644
Net increase (decrease) in cash and cash equivalents	(381,617		)	(179,065		)
Cash and cash equivalents at beginning of period	419,981			226,559
Cash and cash equivalents at end of period	$	38,364		$	47,494
Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets	$	4,080		$	10,790
Interest paid, net of capitalized interest	$	34,974		$	16,460
Taxes paid	$	—		$	495

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

See accompanying Notes to Consolidated Financial Statements.

7

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

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.

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 consolidated subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), and a joint venture, Enterprise EF78 LLC (“Mont Belvieu JV”). See Note 2. “Equity investment throughput” refers to the Partnership’s 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as third-party producers and customers. As of September 30, 2013, the Partnership’s assets, exclusive of interests in Fort Union, White Cliffs, Rendezvous and the Mont Belvieu JV accounted for under the equity method, consisted of the following:

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

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

Western Gas Equity Partners, LP. In December 2012, WGP completed its initial public offering (“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 approximately $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.

8

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (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. Investments in noncontrolled 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 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. 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, and certain prior-period amounts have been reclassified to conform to the current-year presentation.

For the nine months ended September 30, 2012, operating cash inflows and investing cash outflows in the Partnership’s unaudited consolidated statements of cash flows include a reduction of $35.7 million attributable to the correction of an error discovered during analysis of accounts payable balances. This analysis revealed that certain 2012 invoices received, but not yet paid, were properly attributable to ongoing capital projects rather than to operating expenses. Management concluded that this misstatement was not material relative to the nine months ended September 30, 2012, and has corrected the error within the unaudited statement of cash flows for the nine months ended September 30, 2012, as included in this report.

Certain information and note disclosures commonly included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s 2012 Form 10-K, as filed with the SEC on February 28, 2013, certain sections of which were recast in the Partnership’s Current Report on Form 8-K, as filed with the SEC on May 13, 2013, to reflect the results of the Non-Operated Marcellus Interest acquisition (as defined in Note 2). Management believes that the disclosures made are adequate to make the information not misleading.

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement. On August 1, 2012, the Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (the “additional Chipeta interest”). Prior to this transaction, the interests in Chipeta held by Anadarko and a third-party member were reflected as noncontrolling interests in the consolidated financial statements. The acquisition of Anadarko’s then remaining 24% interest was accounted for on a prospective basis as the Partnership acquired an additional interest in an already-consolidated entity. As such, effective August 1, 2012, 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. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of September 30, 2013. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s general partner, each of the Partnership’s acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such assets as of the date of common control. See Note 2.

9

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

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

2. ACQUISITIONS

The following table presents the acquisitions completed by the Partnership during 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
MGR (1)	01/13/2012	100	%	$	299,000	$	159,587	632,783	12,914
Chipeta (2)	08/01/2012	24	%	—		128,250		151,235	3,086
Non-Operated Marcellus Interest(3)	03/01/2013	33.75	%	250,000		215,500		449,129	—
Anadarko-Operated Marcellus Interest(4)	03/08/2013	33.75	%	133,500		—		—	—
Mont Belvieu JV(5)	06/05/2013	25	%	—		78,129		—	—
OTTCO(6)	09/03/2013	100	%	27,500		—		—	—

⁽¹⁾  The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”

⁽²⁾  The Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (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.

⁽³⁾  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. See Non-Operated Marcellus Interest acquisition below for further information.

⁽⁴⁾  The interest acquired from a third party consisted of 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. 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 as of September 30, 2013.

⁽⁵⁾  The acquisition from a third party consisted of a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. 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.

⁽⁶⁾  The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline which connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming. The assets acquired are referred to as the “OTTCO pipeline” and the acquisition as the “OTTCO acquisition.”

10

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS (CONTINUED)

Non-Operated Marcellus Interest acquisition. Because the Non-Operated Marcellus Interest acquisition was a transfer of net assets between entities under common control, the Partnership’s historical financial statements previously filed with the SEC have been recast in this Form 10-Q to include the results attributable to the Non-Operated Marcellus Interest as if the Partnership owned such assets for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko, including the Non-Operated Marcellus Interest, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

The following table presents the revenue and net income impact of the Non-Operated Marcellus Interest on revenue and net income as presented in the Partnership’s historical consolidated statements of income:

	Three Months Ended September 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	219,020	$	15,714	$	234,734
Net income	42,940		7,062		50,002

	Nine Months Ended September 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	636,603	$	43,117	$	679,720
Net income	135,913		19,582		155,495

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 as of September 30, 2013, 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.

11

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS (CONTINUED)

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

	Nine Months Ended   September 30,
thousands except per-unit amounts	2013		2012
Revenues	$	764,128	$	682,820
Net income	196,872		153,423
Net income attributable to Western Gas Partners, LP	189,405		141,467
Net income per common unit - basic and diluted	$	1.26	$	1.12

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 $8.1 million of revenues and $0.5 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 nine months ended September 30, 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.

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. The Partnership will begin to amortize the capitalized interest recognized subsequent to the acquisition upon completion of the facilities, and will reflect the amortization as an adjustment to equity earnings from the Mont Belvieu JV.

12

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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
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
2013
March 31	$	0.540	$	70,143	May 2013
June 30	$	0.560	$	79,315	August 2013
September 30(1)	$	0.580	$	83,986	November 2013

⁽¹⁾  On October 16, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.58 per unit, or $84.0 million in aggregate, including incentive distributions. The cash distribution is payable on November 12, 2013, to unitholders of record at the close of business on October 31, 2013.

4. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public offerings of its common units during 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
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

⁽¹⁾  Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

⁽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.

In addition, pursuant to the Partnership’s registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”), the Partnership initiated trades totaling 218,750 common units during the three and nine months ended September 30, 2013, at an average price per unit of $58.22, generating gross proceeds of $12.7 million (including the general partner’s proportionate capital contribution and before $0.1 million of invoiced offering expenses), of which $2.7 million had been received as of September 30, 2013.

13

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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

The following table summarizes common and general partner units issued during the nine months ended September 30, 2013:

	Common Units	General Partner Units	Total
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	6,879	140	7,019
May 2013 equity offering	7,015,000	143,163	7,158,163
Continuous Offering Program	43,350	174	43,524
Balance at September 30, 2013	112,174,911	2,288,573	114,463,484

Holdings of Partnership equity. As of September 30, 2013, WGP held 49,296,205 common units, representing a 43.1% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,288,573 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the Partnership’s IDRs. As of September 30, 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 September 30, 2013, the public held 62,429,577 common units, representing a 54.5% limited partner interest in the Partnership.

The Partnership’s net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 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.

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.

14

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 approximately $301.5 million and $334.8 million at September 30, 2013, and December 31, 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 8.

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. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. The Partnership has not entered into any new commodity price swap agreements since the fourth quarter of 2011.

15

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of September 30, 2013:

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

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	6,923		$	9,132		$	14,707		$	30,728
Natural gas liquids sales	27,541			25,986			83,049			46,020
Total	34,464			35,118			97,756			76,748
Losses on commodity price swap agreements related to purchases (2)	(23,902		)	(25,803		)	(66,613		)	(70,342		)
Net gains (losses) on commodity price swap agreements	$	10,562		$	9,315		$	31,143		$	6,406

⁽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. Approximately 56% and 63% of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended September 30, 2013 and 2012, respectively, and 58% and 64% for the nine months ended September 30, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 58% and 61% of the Partnership’s processing throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended September 30, 2013 and 2012, respectively, and 56% and 59% for the nine months ended September 30, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko.

16

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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

	Nine Months Ended September 30,
	2013		2012		2013		2012
thousands	Purchases				Sales
Consideration (1)	$	6,167	$	18,946	$	82	$	760
Net carrying value	2,039		6,765		34		392
Partners’ capital adjustment	$	4,128	$	12,181	$	48	$	368

⁽¹⁾ Includes a payable of $1.8 million for pipe and equipment purchased in September 2013.

Long-term incentive plan. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“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 $0.1 million and $0.4 million for the three and nine months ended September 30, 2013, respectively, and $0.1 million and $0.3 million for the three and nine months ended September 30, 2012, respectively.

Equity incentive plan and Anadarko incentive plans. The Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) and (ii) the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (“Anadarko Incentive Plans”).

The Partnership’s general and administrative expenses included $0.8 million and $2.2 million for the three and nine months ended September 30, 2013, respectively, and $0.8 million and $2.4 million for the three and nine months ended September 30, 2012, respectively, of equity-based compensation expense for awards granted to the executive officers of the general partner and other employees under the Anadarko Incentive Plans, which was allocated to the Partnership by Anadarko.

For the three and nine months ended September 30, 2012, the Partnership’s general and administrative expenses included $8.6 million and $13.9 million, respectively, of compensation expense for grants of Unit Value Rights, Unit Appreciation Rights (“UARs”) and Distribution Equivalent Rights 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. Awards outstanding under the Incentive Plan at September 30, 2012, were valued at $1,053 per UAR. WGP’s IPO in December 2012 resulted in the vesting of all then unvested Incentive Plan awards and the effective termination of the Incentive Plan.

17

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
thousands	2013		2012		2013		2012
Revenues (1)	$	217,624	$	180,605	$	603,214	$	519,460
Cost of product (1)	33,753		42,839		97,801		115,603
Operation and maintenance (2)	13,469		12,638		41,021		38,040
General and administrative (3)	5,867		14,227		17,325		30,811
Operating expenses	53,089		69,704		156,147		184,454
Interest income, net (4)	4,225		4,225		12,675		12,675
Interest expense (5)	—		81		—		2,684
Distributions to unitholders (6)	44,378		25,852		121,493		69,615
Contributions from noncontrolling interest owners (7)	—		2,148		—		12,588
Distributions to noncontrolling interest owners (7)	—		1,464		—		6,528

⁽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 Equity incentive plan and Anadarko incentive plans within this Note 5).

⁽⁴⁾  Represents interest income recognized on the note receivable from Anadarko.

⁽⁵⁾  For the three and nine months ended September 30, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 8) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. 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 and Lancaster plants in the fourth quarter of 2012. See Note receivable from and amounts payable to Anadarko within this Note 5.

⁽⁶⁾  Represents distributions paid under the partnership agreement.

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

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

18

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. PROPERTY, PLANT AND EQUIPMENT

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

thousands	Estimated Useful Life	September 30, 2013		December 31, 2012
Land	n/a	$	2,584	$	501
Gathering systems	3 to 47 years	3,610,879		2,911,572
Pipelines and equipment	15 to 45 years	119,278		91,126
Assets under construction	n/a	318,107		422,002
Other	3 to 25 years	10,541		7,191
Total property, plant and equipment		4,061,389		3,432,392
Accumulated depreciation		817,489		714,436
Net property, plant and equipment		$	3,243,900	$	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 7.

During the second quarter of 2013, the Partnership recognized a $1.0 million impairment primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest.

7. COMPONENTS OF WORKING CAPITAL

A summary of other current assets is as follows:

thousands	September 30, 2013		December 31, 2012
Natural gas liquids inventory	$	2,438	$	1,678
Natural gas imbalance receivables	2,729		1,663
Prepaid insurance	1,934		1,897
Other	1,662		1,760
Total other current assets	$	8,763	$	6,998

A summary of accrued liabilities is as follows:

thousands	September 30, 2013		December 31, 2012
Accrued capital expenditures	$	100,876	$	112,311
Accrued plant purchases	20,738		16,350
Accrued interest expense	16,620		15,868
Short-term asset retirement obligations	1,187		1,711
Short-term remediation and reclamation obligations	609		799
Other	136		612
Total accrued liabilities	$	140,166	$	147,651

19

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt as of September 30, 2013, and December 31, 2012:

	September 30, 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	$	673,363	$	651,580	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021	500,000		495,042		531,210		500,000		494,661		499,946
Revolving credit facility	100,000		100,000		100,000		—		—		—
2.600% Senior Notes due 2018	250,000		249,705		249,134		—		—		—
Total debt outstanding	$	1,520,000	$	1,518,110	$	1,531,924	$	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 nine months ended September 30, 2013:

thousands	Carrying Value
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings	595,000
Repayments of revolving credit facility	(495,000		)
Issuance of 2.600% Senior Notes due 2018	250,000
Other	(168		)
Balance as of September 30, 2013	$	1,518,110

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 will be paid semi-annually on February 15 and August 15 of each year, commencing on February 15, 2014. The 2018 Notes will mature on August 15, 2018, unless redeemed, in whole or in part, prior to maturity. 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”).

In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, the Partnership issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The 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”) at a price to the public of 98.778% of the face amount.

At September 30, 2013, the Partnership was in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes and the 2018 Notes.

20

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE (CONTINUED)

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.

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. At September 30, 2013, and December 31, 2012, the interest rate on the RCF was 1.68% 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 September 30, 2013, and December 31, 2012.

At September 30, 2013, the Partnership had $100.0 million of outstanding borrowings, $12.8 million in outstanding letters of credit issued and $687.2 million available for borrowing under the RCF. At September 30, 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, and as of December 31, 2012, the Partnership’s general partner was indemnified by a wholly owned subsidiary of Anadarko, Western Gas Resources, Inc. (“WGRI”), against any claims made against the general partner under the 2022 Notes, the 2021 Notes and/or the RCF.

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. As of September 30, 2013, the 2013 Indemnification Agreement applied to the $250.0 million of 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.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE (CONTINUED)

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Third parties
Interest expense on long-term debt	$	14,994		$	11,919		$	43,783		$	28,036
Amortization of debt issuance costs and commitment fees (1)	1,135			1,201			3,252			3,225
Capitalized interest	(3,111		)	(2,224		)	(9,552		)	(3,827		)
Total interest expense – third parties	13,018			10,896			37,483			27,434
Affiliates
Interest expense on note payable to Anadarko (2)	—			—			—			2,440
Interest expense on affiliate balances (3)	—			81			—			244
Total interest expense – affiliates	—			81			—			2,684
Interest expense	$	13,018		$	10,977		$	37,483		$	30,118

⁽¹⁾  For the three and nine months ended September 30, 2013, includes $0.3 million and $0.8 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 2018 Notes and (iii) underwriters’ fees. For the three and nine months ended September 30, 2012, includes $0.4 million and $0.8 million, respectively, of amortization of the original issue discount and underwriters’ fees for the 2022 Notes issued in June 2012 and the 2021 Notes.

⁽²⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 8.

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

9. COMMITMENTS AND CONTINGENCIES

Litigation and legal proceedings. In March 2011, DCP Midstream LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering LLC, in Weld County District Court (the “Court”) in Colorado, alleging that Anadarko and its affiliates diverted gas from DCP’s gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering LLC, the entity which holds the Wattenberg assets. Anadarko countersued DCP asserting that DCP has not properly allocated values and charges to Anadarko for the gas that DCP gathers and/or processes, and seeks a judgment that DCP has no valid gathering or processing rights to much of the gas production it is claiming, in addition to other claims.

In July 2011, the Court denied the defendants’ motion to dismiss without ruling on the merits and the case is in the discovery phase. Trial is set for April 2014. Management does not believe the outcome of this proceeding will have a material effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership intends to vigorously defend this litigation. Furthermore, without regard to the merit of DCP’s claims, management believes that the Partnership has adequate contractual indemnities covering the claims against it in this lawsuit.

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

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

9. COMMITMENTS AND CONTINGENCIES (CONTINUED)

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 September 30, 2013, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of approximately $61.3 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. In addition, as of September 30, 2013, and in conjunction with the Mont Belvieu JV acquisition, the Partnership is committed to fund 25%, or approximately $13.6 million, of the total remaining estimated net project cost to complete the construction of the fractionation facilities over the next six months (see Note 2).

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 $0.6 million and $2.0 million for the three and nine months ended September 30, 2013, respectively, and $0.8 million and $2.3 million for the three and nine months ended September 30, 2012, respectively.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and notes to consolidated financial statements, which are included under Part I, Item 1 of this quarterly report, as well as our historical consolidated financial statements, and the notes thereto, included in our 2012 Form 10-K (which were recast in our Current Report on Form 8-K, as filed with the Securities and Exchange Commission, or “SEC,” on May 13, 2013, to reflect the results of the acquisition of the Non-Operated Marcellus Interest), and our other public filings and press releases. Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refer 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 consolidated subsidiary of Anadarko Petroleum Corporation. Western Gas Equity Holdings, LLC is WGP’s general partner and a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and our general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC, (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), and a joint venture, Enterprise EF78 LLC (“Mont Belvieu JV”). “Equity investment throughput” refers to our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions by management, forward-looking statements concerning our operations, economic performance and financial condition. These statements can be identified by the use of forward-looking terminology including “may,” “will,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or financial condition or include other “forward-looking” information. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will be realized.

These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

• our ability to pay distributions to our unitholders;

• our assumptions about the energy market;

• future throughput, including Anadarko’s production, which is gathered or processed by or transported through our assets;

• operating results;

• competitive conditions;

• technology;

• availability of capital resources to fund acquisitions, capital expenditures and other contractual obligations, and our ability to access those resources from Anadarko or through the debt or equity capital markets;

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

• weather;

• inflation;

• availability of goods and services;

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

• changes in regulations at the federal, state and local level or the inability to timely obtain or maintain permits that could affect our and our customers’ activities; environmental risks; regulations by the Federal Energy Regulatory Commission (“FERC”); and liability under federal and state laws and regulations;

• legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;

• changes in the financial or operational condition of Anadarko;

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

• our commitments to capital projects;

• ability to utilize our revolving credit facility (“RCF”);

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

• our ability to repay debt;

• our ability to mitigate commodity price risks inherent in our percent-of-proceeds and keep-whole contracts;

• conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;

• our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

• our ability to acquire assets on acceptable terms;

• non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing and transportation agreements and our $260.0 million note receivable from Anadarko;

• timing, amount and terms of future issuances of equity and debt securities; and

• other factors discussed below, in “Risk Factors” included in our 2012 Form 10-K, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates,” in our quarterly reports on Form 10-Q and elsewhere in our other public filings and press releases.

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

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EXECUTIVE SUMMARY

We are a growth-oriented Delaware master limited partnership organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently own assets located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), north-central Pennsylvania, and the Mid-Continent (Kansas and Oklahoma) and are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko and its consolidated subsidiaries, as well as for third-party producers and customers. As of September 30, 2013, we owned and operated thirteen natural gas gathering systems, eight natural gas treating facilities, eight natural gas processing facilities, three NGL pipelines and three natural gas pipelines. In addition, we had interests in five non-operated natural gas gathering systems, one operated natural gas gathering system and three operated natural gas processing facilities, with separate interests accounted for under the equity method in two natural gas gathering systems, a crude oil pipeline and two NGL fractionators currently under construction. We also had the Lancaster processing facility under construction in Northeast Colorado at the end of the third quarter of 2013.

Significant financial highlights during the first nine months of 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 2 for additional information.

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

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

• We completed the acquisition of a 25% interest in the Mont Belvieu JV, which is constructing NGL fractionators located in Mont Belvieu, Texas, and the acquisition of Overland Trail Transmission, LLC, which owns and operates an intrastate pipeline connecting our Red Desert and Granger complexes in southwestern Wyoming. See Acquisitions below.

• We issued 7,058,350 common units to the public, generating net proceeds of $427.3 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 completed the acquisition of Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems in north-central Pennsylvania and the acquisition from a third party of a 33.75% interest (operated by Anadarko) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, also in north-central Pennsylvania. See Acquisitions below.

• We raised our distribution to $0.58 per unit for the third quarter of 2013, representing a 4%increase over the distribution for the second quarter of 2013, a 16%increase over the distribution for the third quarter of 2012, and our eighteenth consecutive quarterly increase.

Significant operational highlights during the first nine months of 2013 included the following:

• Throughput attributable to Western Gas Partners, LP totaled 3,285 MMcf/d and 3,111 MMcf/d for the three and nine months ended September 30, 2013, respectively, representing a 16% and a 13%increase, respectively, compared to the same periods in 2012.

• Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.59 per Mcf and $0.57 per Mcf for the three and nine months ended September 30, 2013, respectively, representing a 9% and 6%increase, respectively, compared to the same periods in 2012.

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ACQUISITIONS

Acquisitions. The following table presents our acquisitions during 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
MGR (1)	01/13/2012	100	%	$	299,000	$	159,587	632,783	12,914
Chipeta (2)	08/01/2012	24	%	—		128,250		151,235	3,086
Non-Operated Marcellus Interest(3)	03/01/2013	33.75	%	250,000		215,500		449,129	—
Anadarko-Operated Marcellus Interest(4)	03/08/2013	33.75	%	133,500		—		—	—
Mont Belvieu JV(5)	06/05/2013	25	%	—		78,129		—	—
OTTCO(6)	09/03/2013	100	%	27,500		—		—	—

⁽¹⁾  The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant with a capacity of 125 MMcf/d, the Red Desert processing plant with a capacity of 48 MMcf/d, 1,295 miles of gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a 338-mile mainline gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”

⁽²⁾  We acquired Anadarko’s then remaining 24% membership interest in Chipeta (as described in Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q). We received distributions related to the additional interest beginning July 1, 2012. This transaction brought our 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 our consolidated financial statements for all periods presented.

⁽³⁾  We 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, our 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 us.

⁽⁴⁾  The interest acquired from a third party consisted of 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. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽⁵⁾  The acquisition from a third party consisted of a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. 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 Note 2—Acquisitionsin the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽⁶⁾  We acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline which connects our Red Desert and Granger complexes in southwestern Wyoming. The assets acquired are referred to as the “OTTCO pipeline” and the acquisition as the “OTTCO acquisition.” See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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Presentation of Partnership assets.References to the “Partnership assets” refer collectively to the assets owned by us, as of September 30, 2013. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q). Further, after an acquisition of assets from Anadarko, we may be required to recast our financial statements to include the activities of such assets as of the date of common control.

The historical financial statements previously filed with the SEC have been recast in this Form 10-Q to include the results attributable to the Non-Operated Marcellus Interest as if we owned such assets for all periods presented. The consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko, including the Non-Operated Marcellus Interest, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported.

EQUITY OFFERINGS

Equity offerings. We completed the following public equity offerings during 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
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

⁽¹⁾ Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

⁽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.

Other equity offerings. Pursuant to our registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”), we initiated trades totaling 218,750 common units during the three and nine months ended September 30, 2013, at an average price per unit of $58.22, generating gross proceeds of $12.7 million (including our general partner’s proportionate capital contribution and before $0.1 million of invoiced offering expenses), of which $2.7 million had been received as of September 30, 2013.

On December 12, 2012, in connection with the closing of the WGP initial public offering (“IPO”), we sold 8,722,966 common units to WGP and 178,019 general partner units to our general partner, in each case at a price of $46.00 per unit, pursuant to a unit purchase agreement among us, our general partner and WGP. The sale of common units and general partner units resulted in aggregate proceeds to us of $409.4 million. We used the net proceeds from this offering for general partnership purposes, including the funding of capital expenditures.

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RESULTS OF OPERATIONS

OPERATING RESULTS

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Gathering, processing and transportation of natural gas and natural gas liquids	$	130,781		$	93,933		$	343,471		$	278,966
Natural gas, natural gas liquids and condensate sales	141,326			136,106			402,616			386,818
Equity income and other, net	5,894			4,695			16,787			13,936
Total revenues(1)	278,001			234,734			762,874			679,720
Total operating expenses(1)	187,813			173,422			538,523			491,907
Operating income	90,188			61,312			224,351			187,813
Interest income, net – affiliates	4,225			4,225			12,675			12,675
Interest expense	(13,018		)	(10,977		)	(37,483		)	(30,118		)
Other income (expense), net	439			522			1,612			(287		)
Income before income taxes	81,834			55,082			201,155			170,083
Income tax expense	58			5,080			4,431			14,588
Net income	81,776			50,002			196,724			155,495
Net income attributable to noncontrolling interests	3,376			3,423			7,467			11,956
Net income attributable to Western Gas Partners, LP	$	78,400		$	46,579		$	189,257		$	143,539
Key performance metrics(2)
Gross margin	$	184,485		$	145,627		$	492,815		$	425,001
Adjusted EBITDA attributable to Western Gas Partners, LP	$	125,174		$	97,494		$	328,749		$	279,813
Distributable cash flow	$	105,881		$	74,778		$	274,794		$	229,429

⁽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 1 of this Form 10-Q.

⁽²⁾  Gross margin, Adjusted EBITDA and Distributable cash flow are defined under the caption Key Performance Metrics within this Item 2. Such caption also includes reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles in the United States (“GAAP”).

For purposes of the following discussion, any increases or decreases “for the three months ended September 30, 2013” refer to the comparison of the three months ended September 30, 2013, to the three months ended September 30, 2012; any increases or decreases “for the nine months ended September 30, 2013” refer to the comparison of the nine months ended September 30, 2013, to the nine months ended September 30, 2012; and any increases or decreases “for the three and nine months ended September 30, 2013” refer to both the comparisons for the three and nine months ended September 30, 2013.

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Throughput

	Three Months Ended   September 30,				Nine Months Ended   September 30,
throughput in MMcf/d	2013	2012	Inc/ (Dec)		2013	2012	Inc/ (Dec)
Gathering, treating and transportation (1)	1,844	1,576	17	%	1,746	1,598	9	%
Processing (2)	1,397	1,228	14	%	1,320	1,182	12	%
Equity investment (3)	221	236	(6	)%	211	236	(11	)%
Total throughput(4)	3,462	3,040	14	%	3,277	3,016	9	%
Throughput attributable to noncontrolling interests	177	204	(13	)%	166	254	(35	)%
Total throughput attributable to Western Gas Partners, LP	3,285	2,836	16	%	3,111	2,762	13	%

⁽¹⁾  Excludes average NGL pipeline volumes of25MBbls/d and22MBbls/d for thethree and nine months ended September 30, 2013, respectively, and22MBbls/d and25MBbls/d for thethree and nine months ended September 30, 2012, respectively. Includes 100% of Wattenberg system volumes for all periods presented and throughput beginning March 2013 attributable to the Anadarko-Operated Marcellus Interest.

⁽²⁾  Consists of 100% of Chipeta, Hilight and Platte Valley system volumes, 100% of the Granger and Red Desert complex volumes, and 50% of Newcastle volumes.

⁽³⁾  Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes, and excludes our 10% share of average White Cliffs pipeline volumes consisting of6MBbls/d and7 MBbls/d for the three and nine months ended September 30, 2013, respectively, and 6 MBbls/d for both the three and nine months ended September 30, 2012.

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

Gathering, treating and transportation throughputincreased by268MMcf/d and148MMcf/d for the three and nine months ended September 30, 2013, respectively, 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.

Processing throughput increased by169MMcf/d and138MMcf/d for the three and nine months ended September 30, 2013, respectively, primarily due to throughput increases at Chipeta, the start-up of the Brasada plant in June 2013, and an increase in volumes at the Red Desert complex due to additional well connections during the period. In addition, for the nine months ended September 30, 2013, 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.

Equity investment volumes decreased by 15 MMcf/d and 25 MMcf/d for the three and nine months ended September 30, 2013, respectively, primarily due to lower throughput at the Fort Union system due to production declines in the area.

Natural Gas Gathering, Processing and Transportation Revenues

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands except percentages	2013		2012		Inc/ (Dec)		2013		2012		Inc/ (Dec)
Gathering, processing and transportation of natural gas and natural gas liquids	$	130,781	$	93,933	39	%	$	343,471	$	278,966	23	%

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Revenues from gathering, processing and transportation of natural gas and natural gas liquids increased by $36.8 million for the three months ended September 30, 2013, primarily due to increases of $9.1 million, $7.2 million, and $7.2 million at the Non-Operated Marcellus Interest, the Wattenberg system, and Chipeta, respectively, due to higher throughput, an increase of $6.1 million due to the start-up of the Brasada plant in June 2013, and an increase of $4.7 million due to the addition of the Anadarko-Operated Marcellus Interest beginning in March 2013.

Revenues from gathering, processing and transportation of natural gas and natural gas liquids increased by $64.5 million for the nine months ended September 30, 2013, primarily due to increases of $21.6 million, $17.4 million, and $12.0 million at the Non-Operated Marcellus Interest, the Wattenberg system, and Chipeta, respectively, all due to higher throughput, an increase of $8.1 million due to the addition of the Anadarko-Operated Marcellus Interest beginning in March 2013, and an increase of $6.9 million due to the start-up of the Brasada plant in June 2013.

Natural Gas, Natural Gas Liquids and Condensate Sales

thousands except percentages and   per-unit amounts	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2013		2012		Inc/ (Dec)		2013		2012		Inc/ (Dec)
Natural gas sales	$	30,034	$	24,223	24	%	$	85,025	$	73,524	16	%
Natural gas liquids sales	104,535		105,124		(1	)%	294,133		291,293		1	%
Drip condensate sales	6,757		6,759		—	%	23,458		22,001		7	%
Total	$	141,326	$	136,106	4	%	$	402,616	$	386,818	4	%
Average price per unit:
Natural gas (per Mcf)	$	5.06	$	4.21	20	%	$	4.53	$	4.19	8	%
Natural gas liquids (per Bbl)	$	48.09	$	48.80	(1	)%	$	47.65	$	47.89	(1	)%
Drip condensate (per Bbl)	$	76.69	$	75.13	2	%	$	76.18	$	75.78	1	%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $5.2 million for the three months ended September 30, 2013, which consisted of a $5.8 millionincrease in natural gas sales and a $0.6 milliondecrease in NGLs sales.

For the three months ended September 30, 2013, natural gas sales increased primarily due to a 20%increase in the overall sales price of natural gas and increased sales volumes resulting from higher throughput at the Wattenberg system, the Red Desert complex, and the Hilight system, partially offset by a decrease at the Granger complex due to lower volumes sold as a result of a decline in throughput and 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 agreements.

The decline in NGLs sales for the three months ended September 30, 2013, was primarily due to a decrease of $6.8 million at Chipeta due to a decrease in average price, partially offset by an increase in volume, a decrease of $5.3 million at the Platte Valley system due to the gas flow change described above, and a decrease of $1.9 million at the Granger complex due to lower volumes sold as a result of declines in throughput. These decreases were partially offset by increases of $6.2 million, $4.9 million and $2.1 million at the Hilight system, the Wattenberg system and the Red Desert complex, respectively, due to higher volumes sold as a result of increased throughput.

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $15.8 million for the nine months ended September 30, 2013, which consisted of an $11.5 millionincrease in sales of natural gas, a $2.8 millionincrease in NGLs sales and a $1.5 millionincrease in drip condensate sales.

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For the nine months ended September 30, 2013, natural gas sales increased primarily due to an 8%increase in the overall sales price of natural gas and higher sales volumes at the Red Desert complex and the Wattenberg system. These increases were partially offset by a decrease at the Granger complex due to a decrease in volumes sold as a result of decreased throughput.

The growth in NGLs sales for the nine months ended September 30, 2013, was primarily due to increases of $15.4 million, $8.5 million, $4.9 million and $4.0 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 $16.5 million at Chipeta (with a corresponding decrease in cost of product), a decrease of $8.8 million at the Granger complex due to a decrease in volumes sold as a result of decreased throughput, and a decrease of $5.8 million at the Platte Valley system due to the aforementioned gas flow changes.

The growth in drip condensate sales for the nine months ended September 30, 2013 was primarily due to a $1.6 million increase at the Wattenberg system due to an increase in condensate volumes sold as a result of increased throughput.

For the three and nine months ended September 30, 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 1 of this Form 10-Q.

Equity Income and Other Revenues

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands except percentages	2013		2012		Inc/ (Dec)		2013		2012		Inc/ (Dec)
Equity income	$	4,501	$	3,804	18	%	$	12,205	$	10,752	14	%
Other revenues, net	1,393		891		56	%	4,582		3,184		44	%
Total	$	5,894	$	4,695	26	%	$	16,787	$	13,936	20	%

For the three and nine months ended September 30, 2013, equity income increased by $0.7 million and $1.5 million, respectively, primarily due to volume increases at White Cliffs, partially offset by a decrease in income due to lower volumes at Fort Union.

Other revenues, net increased by $0.5 million and $1.4 million for the three and nine months ended September 30, 2013, respectively, primarily due to the collection of deficiency fees associated with volume commitments at Chipeta.

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Cost of Product and Operation and Maintenance Expenses

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands except percentages	2013		2012		Inc/ (Dec)		2013		2012		Inc/ (Dec)
Cost of product	$	93,516	$	89,107	5	%	$	270,059	$	254,719	6	%
Operation and maintenance	42,757		35,493		20	%	121,165		103,304		17	%
Total cost of product and operation and maintenance expenses	$	136,273	$	124,600	9	%	$	391,224	$	358,023	9	%

Including the effects of commodity price swap agreements on purchases, cost of product expense for the three months ended September 30, 2013, increased by $4.4 million primarily due to the volume fluctuations noted in Throughput and Natural Gas, Natural Gas Liquids and Condensate Sales within this Item 2, resulting in the following:

• a $3.7 million net increase in residue purchases primarily at the Wattenberg system, the Red Desert complex, and the Hilight system, partially offset by decreases at the Platte Valley system and the Granger complex;

• a $0.7 million increase due to changes in imbalance positions; and

• a $1.5 million net decrease in NGL purchases primarily at Chipeta, the Platte Valley system, and the Granger complex, partially offset by increases at the Hilight system, the Red Desert complex, and the Wattenberg system.

Including the effects of commodity price swap agreements on purchases, cost of product expense for the nine months ended September 30, 2013, increased by $15.3 million primarily due to the volume fluctuations noted in Throughput and Natural Gas, Natural Gas Liquids and Condensate Sales within this Item 2, resulting in the following:

• a $9.7 million net increase in residue purchases primarily at the Red Desert complex, the Wattenberg system, and the Granger straddle plant, partially offset by decreases at the Granger complex and the Hilight system; and

• a $3.6 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 Granger complex, and the Platte Valley system.

Cost of product expense for the three and nine months ended September 30, 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 1 of this Form 10-Q.

Operation and maintenance expense increased by $7.3 million for the three months ended September 30, 2013, primarily due to a $4.0 million increase in plant repairs and maintenance and a $2.5 million increase in salaries, wages and payroll taxes, primarily at the Wattenberg system, Chipeta and the Brasada plant.

Operation and maintenance expense increased by $17.9 million for the nine months ended September 30, 2013, primarily due to an increase of $6.9 million in property, overhead and facility expense attributable to the Non-Operated Marcellus Interest. In addition, plant repairs and maintenance increased by $6.3 million, and salaries, wages, and payroll tax expense increased by $4.9 million, primarily at the Wattenberg system, Chipeta, the Hilight system and the Brasada plant.

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General and Administrative, Depreciation and Other Expenses

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands except percentages	2013		2012		Inc/ (Dec)		2013		2012		Inc/ (Dec)
General and administrative	$	7,276	$	15,039	(52	)%	$	22,228	$	35,623	(38	)%
Property and other taxes	6,649		5,328		25	%	18,520		14,998		23	%
Depreciation, amortization and impairments	37,615		28,455		32	%	106,551		83,263		28	%
Total general and administrative, depreciation and other expenses	$	51,540	$	48,822	6	%	$	147,299	$	133,884	10	%

General and administrative expenses decreased by $7.8 million and $13.4 million for the three and nine months ended September 30, 2013, respectively, primarily due to a decrease of $8.6 million and $13.9 million, respectively, in non-cash compensation expenses attributable to the awards outstanding under the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (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 increases of $0.5 million and $1.3 million, respectively, in corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement.

For the three months ended September 30, 2013, property and other taxes increased by $1.3 million, primarily due to ad valorem tax increases of $0.8 million associated with capital additions at the Wattenberg system and Chipeta and $0.3 million due to the completion of the Brasada plant in June 2013. For the nine months ended September 30, 2013, property and other taxes increased by $3.5 million, primarily due to ad valorem tax increases of $2.6 million associated with capital additions at the Platte Valley and Wattenberg systems and $0.8 million due to the completion of the Brasada plant in June 2013.

For the three months ended September 30, 2013, depreciation, amortization and impairments increased by $9.2 million, primarily attributable to a $3.2 million increase in depreciation expense associated with capital projects completed at the Wattenberg system, Chipeta, and the Hilight system, a $2.4 million increase in depreciation expense related to the completion of the Brasada plant in June 2013, a $1.7 million increase in depreciation expense associated with the Non-Operated Marcellus Interest, and a $1.2 million increase in depreciation expense associated with the March 2013 acquisition of the Anadarko-Operated Marcellus Interest.

For the nine months ended September 30, 2013, depreciation, amortization and impairments increased by $23.3 million, primarily attributable to a $10.1 million increase in depreciation expense associated with capital projects completed at the Wattenberg system, Chipeta, and the Platte Valley and Hilight systems, a $5.5 million increase in depreciation and impairment expense associated with the Non-Operated Marcellus Interest, a $3.7 million increase in depreciation expense related to the completion of the Brasada plant in June 2013, and a $2.7 million increase in depreciation expense associated with the March 2013 acquisition of the Anadarko-Operated Marcellus Interest.

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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.”

	Three Months Ended   September 30,								Nine Months Ended   September 30,
thousands except percentages	2013			2012			Inc/ (Dec)		2013			2012			Inc/ (Dec)
Interest income on note receivable	$	4,225		$	4,225		—	%	$	12,675		$	12,675		—	%
Interest income, net – affiliates	$	4,225		$	4,225		—	%	$	12,675		$	12,675		—	%
Third parties
Interest expense on long-term debt	$	(14,994	)	$	(11,919	)	26	%	$	(43,783	)	$	(28,036	)	56	%
Amortization of debt issuance costs and commitment fees (1)	(1,135		)	(1,201		)	(5	)%	(3,252		)	(3,225		)	1	%
Capitalized interest	3,111			2,224			40	%	9,552			3,827			150	%
Affiliates
Interest expense on note payable to Anadarko (2)	—			—			—	%	—			(2,440		)	(100	)%
Interest expense on affiliate balances (3)	—			(81		)	(100	)%	—			(244		)	(100	)%
Interest expense	$	(13,018	)	$	(10,977	)	19	%	$	(37,483	)	$	(30,118	)	24	%

⁽¹⁾  For the three and nine months ended September 30, 2013, includes $0.3 million and $0.8 million, respectively, of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes, the 2021 Notes, and the 2018 Notes. For the three and nine months ended September 30, 2012, includes $0.4 million and $0.8 million, respectively, of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes issued in June 2012 and the 2021 Notes.

⁽²⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽³⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures incurred in 2011 related to the construction of the Brasada and Lancaster plants. In the fourth quarter of 2012, we repaid the reimbursement payable to Anadarko associated with the construction of the Brasada and Lancaster plants. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Interest expense increased by $2.0 million and $7.4 million for the three and nine months ended September 30, 2013, respectively, primarily due to interest expense incurred on the 2022 Notes of $1.5 million and $14.7 million, respectively, as well as interest incurred on the 2018 Notes of $0.8 million for both the three and nine months ended September 30, 2013. In addition, interest expense increased on the RCF by $0.7 million and $0.2 million, respectively, for the three and nine months ended September 30, 2013, primarily due to greater average outstanding borrowings in the current period. However, for the nine months ended September 30, 2013, the increase in interest expense was partially offset by a decrease of $2.4 million attributable to the repayment of the note payable to Anadarko in June 2012. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Also partially offsetting the increases in interest expense for the three and nine months ended September 30, 2013, were increases of capitalized interest of $0.9 million and $5.7 million, respectively, associated with the expansion of the Lancaster plant and construction of the two Mont Belvieu fractionators. The increase in capitalized interest for the nine months ended September 30, 2013, also included interest associated with the construction of the Brasada plant which was completed in June 2013.

35

Other Income (Expense), Net

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands except percentages	2013		2012		Inc/ (Dec)		2013		2012			Inc/ (Dec)
Other income (expense), net	$	439	$	522	(16	)%	$	1,612	$	(287	)	n/m (1)

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

For the three and nine months ended September 30, 2013 and 2012, other income (expense), net included $0.4 million and $1.2 million, respectively, of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition. In addition, for the three and nine months ended September 30, 2013, other income (expense), net included $0.1 million and $0.4 million, respectively, of interest earned on overnight investments. For the nine months ended September 30, 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 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Income Tax Expense

	Three Months Ended   September 30,								Nine Months Ended   September 30,
thousands except percentages	2013			2012			Inc/ (Dec)		2013			2012			Inc/ (Dec)
Income before income taxes	$	81,834		$	55,082		49	%	$	201,155		$	170,083		18	%
Income tax expense	58			5,080			(99	)%	4,431			14,588			(70	)%
Effective tax rate	—		%	9		%			2		%	9		%

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 Non-Operated Marcellus Interest prior to and including March 2013 and (b) the MGR assets prior to and including January 2012 was subject to federal and state income tax. Income earned by the Non-Operated Marcellus Interest and MGR assets for periods subsequent to March 2013 and January 2012, respectively, was only subject to Texas margin tax on income apportionable to Texas.

Noncontrolling Interests

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands except percentages	2013		2012		Inc/ (Dec)		2013		2012		Inc/ (Dec)
Net income attributable to noncontrolling interests	$	3,376	$	3,423	(1	)%	$	7,467	$	11,956	(38	)%

For the nine months ended September 30, 2013, net income attributable to noncontrolling interests decreased by $4.5 million, primarily due to our acquisition of Anadarko’s then remaining 24% membership interest in Chipeta in August 2012. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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KEY PERFORMANCE METRICS

thousands except percentages and gross margin per Mcf	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2013		2012		Inc/ (Dec)		2013		2012		Inc/ (Dec)
Gross margin	$	184,485	$	145,627	27	%	$	492,815	$	425,001	16	%
Gross margin per Mcf (1)	0.58		0.52		12	%	0.55		0.51		8	%
Gross margin per Mcf attributable to Western Gas Partners, LP (2)	0.59		0.54		9	%	0.57		0.54		6	%
Adjusted EBITDA attributable to Western Gas Partners, LP (3)	125,174		97,494		28	%	328,749		279,813		17	%
Distributable cash flow (3)	$	105,881	$	74,778	42	%	$	274,794	$	229,429	20	%

⁽¹⁾ Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union and our 22% interest in income and volumes attributable to Rendezvous. Gross margin also includes 100% of gross margin attributable to our NGL pipelines and our 10% interest in income attributable to White Cliffs.

⁽²⁾  Calculated as described in footnote one above, except also excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.

⁽³⁾  For reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read the descriptions below under the captions Adjusted EBITDA, Distributable cash flow and Reconciliation to GAAP measures.

Gross margin and Gross margin per Mcf. Gross margin increased by $38.9 million and $67.8 million for the three and nine months ended September 30, 2013, respectively, primarily due to higher margins at the Non-Operated Marcellus Interest, the Wattenberg system, the Anadarko-Operated Marcellus Interest, Chipeta, and the start-up of the Brasada plant in June 2013.

Gross margin per Mcf increased by $0.06 and $0.04 for the three and nine months ended September 30, 2013, respectively, 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 EBITDA. We define “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.

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Adjusted EBITDA increased by $27.7 million for the three months ended September 30, 2013, primarily due to a $42.6 millionincrease in total revenues excluding equity income. This amount was offset by a $7.3 millionincrease in operation and maintenance expenses, a $4.4 millionincrease in cost of product, a $1.3 millionincrease in property and other tax expense, and a $1.1 milliondecrease in distributions from equity investees.

Adjusted EBITDA increased by $48.9 million for the nine months ended September 30, 2013, primarily due to an $81.7 millionincrease in total revenues excluding equity income and a $4.5 milliondecrease in net income attributable to noncontrolling interest. These amounts were offset by a $17.9 millionincrease in operation and maintenance expenses, a $15.3 millionincrease in cost of product, and a $3.5 millionincrease in property and other tax expense.

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 distributable cash flow 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.

Distributable cash flow increased by $31.1 million for the three months ended September 30, 2013, primarily due to a $27.7 millionincrease in Adjusted EBITDA and a $6.0 milliondecrease in maintenance capital expenditures, offset by a $3.0 millionincrease in net cash paid for interest expense.

Distributable cash flow increased by $45.4 million for the nine months ended September 30, 2013, primarily due to a $48.9 millionincrease in Adjusted EBITDA and a $9.3 milliondecrease in maintenance capital expenditures, offset by a $13.3 millionincrease in net cash paid for interest expense.

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

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

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	125,174		$	97,494		$	328,749		$	279,813
Less:
Distributions from equity investees	4,531			5,584			15,563			15,603
Non-cash equity-based compensation expense	962			9,417			2,663			16,407
Interest expense	13,018			10,977			37,483			30,118
Income tax expense	58			5,080			4,431			14,588
Depreciation, amortization and impairments (1)	36,970			28,011			104,651			81,507
Other expense (1)	—			—			—			1,665
Add:
Equity income, net	4,501			3,804			12,205			10,752
Interest income, net – affiliates	4,225			4,225			12,675			12,675
Other income (1) (2)	39			125			419			187
Net income attributable to Western Gas Partners, LP	$	78,400		$	46,579		$	189,257		$	143,539
Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	125,174		$	97,494		$	328,749		$	279,813
Adjusted EBITDA attributable to noncontrolling interests	4,017			3,866			9,362			13,709
Interest income (expense), net	(8,793		)	(6,752		)	(24,808		)	(17,443		)
Non-cash equity based compensation expense	(80		)	(8,482		)	(99		)	(13,638		)
Debt-related amortization and other items, net	630			698			1,756			1,728
Current income tax expense	(80		)	646			(3,224		)	6,977
Other income (expense), net (2)	43			126			424			(1,475		)
Distributions from equity investees less than (in excess of) equity income, net	(30		)	(1,780		)	(3,358		)	(4,851		)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable	(1,304		)	34,817			(28,425		)	47,403
Accounts payable, accrued liabilities and natural gas imbalance payable	6,482			39,209			6,818			29,261
Other	(2,003		)	(2,441		)	1,874			2,103
Net cash provided by operating activities	$	124,056		$	157,401		$	289,069		$	343,587
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities							$	289,069		$	343,587
Net cash used in investing activities							$	(1,226,404	)	$	(1,009,296	)
Net cash provided by financing activities							$	555,718		$	486,644

⁽¹⁾ 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 1 of this Form 10-Q.

⁽²⁾  Excludes income of $0.4 million and $1.2 million for each of the three and nine months ended September 30, 2013 and 2012, respectively, related to a component of a gas processing agreement accounted for as a capital lease. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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	Three Months Ended   September 30,					Nine Months Ended   September 30,
thousands except Coverage ratio	2013			2012		2013			2012
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	105,881		$	74,778	$	274,794		$	229,429
Less:
Distributions from equity investees	4,531			5,584		15,563			15,603
Non-cash equity-based compensation expense	962			9,417		2,663			16,407
Interest expense, net (non-cash settled)	—			81		—			244
Income tax expense	58			5,080		4,431			14,588
Depreciation, amortization and impairments (1)	36,970			28,011		104,651			81,507
Other expense (1)	—			—		—			1,665
Add:
Equity income, net	4,501			3,804		12,205			10,752
Cash paid for maintenance capital expenditures (1) (3)	7,389			13,398		19,595			28,863
Capitalized interest	3,111			2,224		9,552			3,827
Cash paid for income taxes	—			423		—			495
Other income (1) (2)	39			125		419			187
Net income attributable to Western Gas Partners, LP	$	78,400		$	46,579	$	189,257		$	143,539
Distributions declared (4)
Limited partners	$	65,181				$	184,734
General partner	18,805					48,710
Total	$	83,986				$	233,444
Coverage ratio	1.26		x			1.18		x

⁽¹⁾ 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 1 of this Form 10-Q.

⁽²⁾  Excludes income of $0.4 million and $1.2 million for each of the three and nine months ended September 30, 2013 and 2012, respectively, related to a component of a gas processing agreement accounted for as a capital lease. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽³⁾  Net of a prior period adjustment reclassifying $0.7 million from capital expenditures to operating expenses for the nine months ended September 30, 2012.

⁽⁴⁾  Reflects distributions of $0.58 and $1.68 per unit declared for the three and nine months ended September 30, 2013, respectively.

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 September 30, 2013, included cash and cash equivalents, cash flows generated from operations, including interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under our RCF, and issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and 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.

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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 October 16, 2013, the board of directors of our general partner declared a cash distribution to our unitholders of $0.58 per unit, which equates to $84.0 million in aggregate including incentive distributions. The cash distribution is payable on November 12, 2013, to unitholders of record at the close of business on October 31, 2013.

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 Part II, Item 1A—Risk Factors of this Form 10-Q.

Working capital. As of September 30, 2013, we had a $55.0 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. 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. Our working capital deficit as of September 30, 2013, was primarily due to our use of $215.5 million of cash on hand to fund the Non-Operated Marcellus Interest acquisition on March 1, 2013 and $78.1 million of cash on hand to fund the Mont Belvieu JV acquisition on June 5, 2013. As of September 30, 2013, we had $687.2 million available for borrowing under our $800.0 million RCF.

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.

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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: 

	Nine Months Ended   September 30,
thousands	2013		2012
Acquisitions	$	710,158	$	605,960
Expansion capital expenditures	$	450,107	$	374,338
Maintenance capital expenditures	19,571		29,611
Total capital expenditures (1)	$	469,678	$	403,949
Capital incurred (2)	$	458,236	$	450,989

⁽¹⁾  Capital expenditures for the nine months ended September 30, 2013, included $8.0 million of capitalized interest. Capital expenditures included the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners for all periods presented. Capital expenditures for the nine months ended September 30, 2012, included $105.8 million of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest acquisition.

⁽²⁾  Capital incurred for the nine months ended September 30, 2013, included $8.0 million of capitalized interest. Capital incurred for the nine months ended September 30, 2013 and 2012, included $8.8 million and $109.6 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest acquisition and included the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

Acquisitions included the OTTCO acquisition in the third quarter of 2013, the Mont Belvieu JV acquisition in the second quarter of 2013, the Anadarko-Operated Marcellus Interest acquisition and the Non-Operated Marcellus Interest acquisition in the first quarter of 2013, the acquisition of Anadarko’s then remaining 24% membership interest in Chipeta in the third quarter of 2012, and the MGR acquisition in the first quarter of 2012, as discussed in Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Capital expenditures, excluding acquisitions, increased by $65.7 million for the nine months ended September 30, 2013. Expansion capital expenditures increased by $75.8 million (including a $4.2 million increase in capitalized interest) for the nine months ended September 30, 2013, primarily due to an increase of $110.1 million related to the construction of the Brasada and Lancaster plants and a $54.8 million increase in expenditures at the Wattenberg and Hilight systems. These increases were partially offset by a $93.8 million decrease at Chipeta and the Non-Operated Marcellus Interest. Maintenance capital expenditures decreased by $10.0 million, primarily as a result of decreased expenditures of $9.4 million at the Wattenberg, Hilight, Haley, and Platte Valley systems and the Red Desert complex, partially offset by a $1.2 million increase at the Anadarko-Operated Marcellus Interest.

We have updated our estimated total capital expenditures for the year ended December 31, 2013, including our 75% share of Chipeta’s capital expenditures and excluding acquisitions, from an originally reported range of $550 million to $600 million, to a current range of $670 million to $740 million, to include the 2013 portion of expansion capital at Lancaster, as well as the additional expansion capital needed at both the Wattenberg and Hilight systems.

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:

	Nine Months Ended   September 30,
thousands	2013			2012
Net cash provided by (used in):
Operating activities	$	289,069		$	343,587
Investing activities	(1,226,404		)	(1,009,296		)
Financing activities	555,718			486,644
Net increase (decrease) in cash and cash equivalents	$	(381,617	)	$	(179,065	)

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Operating Activities. Net cash provided by operating activities during the nine months ended September 30, 2013, was $289.1 million, compared to $343.6 million for the nine months ended September 30, 2012. Operating cash flows decreased primarily due to the impact of changes in working capital items, partially offset by higher sales volumes and higher average natural gas prices. The impact of changes in working capital items was largely attributable to a decrease in the change in accrued interest expense due to interest paid on the 2022 Notes issued in the second half of 2012. Refer to Operating Results within this Item 2 for a discussion of our results of operations as compared to the prior period.

Investing Activities. Net cash used in investing activities for the nine months ended September 30, 2013, included the following:

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

• $469.7 million of capital expenditures;

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

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

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

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

• $26.0 million of capital contributions to the Mont Belvieu JV to fund our current share of construction costs for the fractionation facilities anticipated to be completed by the first quarter of 2014; and

• $4.4 million of cash paid for equipment purchases from Anadarko.

Net cash used in investing activities for the nine months ended September 30, 2012, included the following:

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

• $403.9 million of capital expenditures;

• $128.3 million of cash paid for Anadarko’s then remaining 24% membership interest in Chipeta; and

• $18.9 million of cash paid for equipment purchases from Anadarko.

Financing Activities. Net cash provided by financing activities for the nine months ended September 30, 2013, included the following:

• $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;

• $250.0 million of borrowings to fund the Non-Operated Marcellus Interest acquisition;

• $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;

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

• $184.0 million of borrowings to fund capital expenditures;

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

• $2.6 million of net proceeds from activity under our Continuous Offering Program (as defined and discussed in Registered Securities within this Item 2), 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 Non-Operated Marcellus Interest acquisition.

Net contributions from Anadarko attributable to intercompany balances were $4.5 million during the nine months ended September 30, 2013, representing intercompany transactions attributable to the Non-Operated Marcellus Interest acquisition.

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Net cash provided by financing activities for the nine months ended September 30, 2012, included the following:

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

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

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

Proceeds from our 2022 Notes offering were used to repay amounts outstanding under our RCF and our note payable to Anadarko. Net contributions from Anadarko attributable to intercompany balances were $60.3 million during the nine months ended September 30, 2012, representing intercompany transactions attributable to the Non-Operated Marcellus Interest acquisition.

For the nine months ended September 30, 2013 and 2012, we paid $215.1 million and $141.5 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners of Chipeta totaled $2.2 million and $26.9 million during the nine months ended September 30, 2013 and 2012, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions to noncontrolling interest owners of Chipeta totaled $8.0 million and $14.3 million for the nine months ended September 30, 2013 and 2012, respectively, representing the distributions paid as of September 30 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 Anadarko’s then remaining 24% membership interest in Chipeta.

Debt and credit facility. As of September 30, 2013, the carrying value of our outstanding debt consisted of $249.7 million of the 2018 Notes, $673.4 million of the 2022 Notes, $495.0 million of the 2021 Notes and $100.0 million of the RCF. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Senior Notes. In August 2013, we completed the offering of $250.0 million aggregate principal amount of 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 is 2.806%. Interest will be paid semi-annually on February 15 and August 15 of each year, commencing on February 15, 2014. The 2018 Notes will mature on August 15, 2018, unless redeemed, in whole or in part, prior to maturity. 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.

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.

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.

At September 30, 2013, we were in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes and 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.

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Revolving credit facility. As of September 30, 2013, we had $100.0 million of outstanding borrowings and $12.8 million in outstanding letters of credit issued under our $800.0 million RCF. The interest rate was 1.68% and 1.71% at September 30, 2013, and December 31, 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 September 30, 2013, and December 31, 2012. At September 30, 2013, we were 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 our general partner, and as of December 31, 2012, our general partner was 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.

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. As of September 30, 2013, the 2013 Indemnification Agreement applied to the $250.0 million of 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.

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 1 of this Form 10-Q for a discussion of trades initiated 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.

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.

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CONTRACTUAL OBLIGATIONS

Our contractual obligations include, among other things, a revolving credit facility, other third-party long-term debt, capital obligations related to our expansion projects and various operating leases. Refer toNote 8—Debt and Interest Expense and Note 9—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q for an update to our contractual obligations as of September 30, 2013, including, but not limited to, increases in committed capital.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than operating leases. The information pertaining to operating leases required for this item is provided under Note 9—Commitments and Contingencies included in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk. Certain of our processing services are provided under percent-of-proceeds and keep-whole agreements in which Anadarko is typically responsible for the marketing of the natural gas and NGLs. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of natural gas and NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, we compensate the producer for this amount of gas by supplying additional gas or by paying an agreed-upon value for the gas utilized.

To mitigate our exposure to changes in commodity prices as a result of the purchase and sale of natural gas, condensate or NGLs, we currently have in place commodity price swap agreements with Anadarko expiring at various times through December 2016. For additional information on the commodity price swap agreements, see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

In addition, pursuant to certain of our contracts, we retain and sell drip condensate that is recovered during the gathering of natural gas. As part of this arrangement, we are required to provide a thermally equivalent volume of natural gas or the cash equivalent thereof to the shipper. Thus, our revenues for this portion of our contractual arrangement are based on the price received for the drip condensate, and our costs for this portion of our contractual arrangement depend on the price of natural gas. Historically, drip condensate sells at a price representing a discount to the price of New York Mercantile Exchange, or NYMEX, West Texas Intermediate crude oil.

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

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

Interest rate risk. Interest rates during the nine months ended September 30, 2013, were low compared to historic rates. As of September 30, 2013, we had $100.0 million of outstanding borrowings under our RCF (which bears interest at a rate based on London Interbank Offered Rate (“LIBOR”)). If interest rates rise, our future financing costs could increase. A 10% change in LIBOR would have resulted in a nominal change in net income and the fair value of our borrowings under the RCF.

We may incur additional variable rate debt in the future, either under our RCF or other financing sources, including commercial bank borrowings or debt issuances.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of the Partnership’s general partner performed an evaluation of the Partnership’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (“Exchange Act”). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Partnership’s disclosure controls and procedures are effective as of September 30, 2013.

Changes in Internal Control Over Financial Reporting. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2013, that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are not a party to any legal, regulatory or administrative proceedings other than proceedings arising in the ordinary course of our business. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial condition.

In July 2013, Kerr-McGee Gathering LLC, one of our subsidiaries, entered into a consent order with the Colorado Department of Public Health and Environment relating to the failure to comply with certain terms of certain permits at its Frederick compression station and agreed to pay a penalty of approximately $125,000.

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors under Part I, Item 1A set forth in our Form 10-K for the year ended December 31, 2012, together with all of the other information included in this document, and in our other public filings, press releases, and public discussions with management of the Partnership. Additionally, for a full discussion of the risks associated with Anadarko’s business, see Item 1A under Part I in Anadarko’s Form 10-K for the year ended December 31, 2012, Anadarko’s quarterly reports on Form 10-Q and Anadarko’s other public filings, press releases, and public discussions with Anadarko management. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

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Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties that are beyond our control. These uncertainties could also affect downstream assets which we do not own or control, but which are critical to certain of our growth projects. Delays in the completion of new downstream assets, or the unavailability of existing downstream assets, due to environmental, regulatory or political considerations could have an adverse impact on the completion or utilization of our growth projects. In addition, construction activities could be subject to state, county and local ordinances that restrict the time, place or manner in which those activities may be conducted. Construction projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing existing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

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

In connection with common units issued through our Continuous Offering Program, our general partner purchased 174 general partner units for $10,862 in cash during the three months ended September 30, 2013, to maintain its 2.0% general partner interest in us. Proceeds from the Continuous Offering Program, including from the sale of the general partner units, were used for general partnership purposes, including the funding of capital expenditures. The general partner units were issued in reliance on an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended.

Additionally, in connection with our May 2013 equity offering, our general partner purchased 143,163 general partner units to maintain its 2.0% general partner interest in us for $8.8 million in cash. Proceeds from the May 2013 equity offering, including from the sale of the general partner units, were used for the repayment of a portion of the outstanding borrowings under our RCF, with the remaining proceeds used for general partnership purposes, including the funding of capital expenditures. The general partner units were issued in reliance on an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended.

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Item 6. Exhibits

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

2.1#	Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
2.2#	Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 13, 2008, File No. 001-34046).
2.3#	Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
2.4#	Contribution Agreement, dated as of January 29, 2010 by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Mountain Gas Resources LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010 File No. 001-34046).
2.5#	Contribution Agreement, dated as of July 30, 2010, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
2.6#	Purchase and Sale Agreement, dated as of January 14, 2011, by and among Western Gas Partners, LP, Kerr-McGee Gathering LLC and Encana Oil & Gas (USA) Inc. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 18, 2011 File No. 001-34046).
2.7#	Contribution Agreement, dated as of December 15, 2011, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 15, 2011, File No. 001-34046).
2.8#	Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
3.1	Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.2	First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
3.3	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated December 19, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
3.4	Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of April 15, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046).

49

3.5	Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated July 22, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
3.6	Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated January 29, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
3.7	Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 2, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
3.8	Amendment No. 6 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated July 8, 2011 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 8, 2011, File No. 001-34046).
3.9	Amendment No. 7 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated January 13, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 17, 2012, File No. 001-34046).
3.10	Amendment No. 8 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 1, 2012 (incorporated by reference to Exhibit 3.10 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 2, 2012, File No. 001-34046).
3.11	Amendment No. 9 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated December 12, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
3.12	Amendment No. 10 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 1, 2013 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
3.13	Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.14	Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
4.1	Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
4.2	Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.3	First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.4	Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.5	Fifth Supplemental Indenture, dated as of August 14, 2013, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
4.6	Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
4.7	Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).

50

31.1*	Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
#	Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document

51

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	WESTERN GAS PARTNERS, LP
November 7, 2013
	/s/ Donald R. Sinclair
	Donald R. Sinclair President and Chief Executive Officer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)
November 7, 2013
	/s/ Benjamin M. Fink
	Benjamin M. Fink Senior Vice President, Chief Financial Officer and Treasurer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)

52

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Donald R. Sinclair, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Western Gas Partners, LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 7, 2013

/s/ Donald R. Sinclair

Donald R. Sinclair

President and Chief Executive Officer

Western Gas Holdings, LLC

(as general partner of Western Gas Partners, LP)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Benjamin M. Fink, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Western Gas Partners, LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. 

Date: November 7, 2013

/s/ Benjamin M. Fink

Benjamin M. Fink

Senior Vice President, Chief Financial Officer and Treasurer

Western Gas Holdings, LLC

(as general partner of Western Gas Partners, LP)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

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

(1) the Quarterly Report on Form 10-Q of the Partnership for the period ending September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

November 7, 2013
	/s/ Donald R. Sinclair
	Donald R. Sinclair
	President and Chief Executive Officer
	Western Gas Holdings, LLC
	(as general partner of Western Gas Partners, LP)
November 7, 2013
	/s/ Benjamin M. Fink
	Benjamin M. Fink
	Senior Vice President, Chief Financial Officer and Treasurer
	Western Gas Holdings, LLC
	(as general partner of Western Gas Partners, LP)

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

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business combinations policy

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of September 30, 2013. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s general partner, each of the Partnership’s acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such assets as of the date of common control. See Note 2.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of Partnership assets from Anadarko, including the Non-Operated Marcellus Interest, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. Net income attributable to the Partnership assets for periods prior to the Partnership’s acquisition of such assets is not allocated to the limited partners for purposes of calculating net income per common 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.

Net income per common unit policy

The Partnership’s net income for periods including and subsequent to 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.

Fair value policy

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 approximately $301.5 million and $334.8 million at September 30, 2013, and December 31, 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.

Capitalized interest policy

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. The Partnership will begin to amortize the capitalized interest recognized subsequent to the acquisition upon completion of the facilities, and will reflect the amortization as an adjustment to equity earnings from the Mont Belvieu JV.

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Consolidated Balance Sheets (USD $)	Sep. 30, 2013		Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 38,364,000		$ 419,981,000	[1]
Accounts receivable, net	75,788,000	[2]	50,233,000	[1],[2]
Other current assets	8,763,000	[3]	6,998,000	[1],[3]
Total current assets	122,915,000		477,212,000	[1]
Note receivable - Anadarko	260,000,000		260,000,000	[1]
Property, plant and equipment
Cost	4,061,389,000		3,432,392,000	[1]
Less accumulated depreciation	817,489,000		714,436,000	[1]
Net property, plant and equipment	3,243,900,000		2,717,956,000	[1]
Goodwill	105,336,000		105,336,000	[1]
Other intangible assets	54,436,000		55,490,000	[1]
Equity investments	227,566,000		106,130,000	[1]
Other assets	28,078,000		27,798,000	[1]
Total assets	4,042,231,000		3,749,922,000	[1]
Current liabilities
Accounts and natural gas imbalance payables	19,131,000	[4]	25,154,000	[1],[4]
Accrued ad valorem taxes	18,472,000		11,949,000	[1]
Income taxes payable	190,000		552,000	[1]
Accrued liabilities	140,166,000	[5]	147,651,000	[1],[5]
Total current liabilities	177,959,000		185,306,000	[1]
Long-term debt - third parties	1,518,110,000		1,168,278,000	[1]
Deferred income taxes	1,830,000		47,153,000	[1]
Asset retirement obligations and other	76,336,000		68,749,000	[1]
Total long-term liabilities	1,596,276,000		1,284,180,000	[1]
Total liabilities	1,774,235,000		1,469,486,000	[1]
Equity and partners' capital
Common units (112,174,911 and 104,660,553 units issued and outstanding at September 30, 2013, and December 31, 2012, respectively)	2,127,040,000		1,957,066,000	[1]
General partner units (2,288,573 and 2,135,930 units issued and outstanding at September 30, 2013, and December 31, 2012, respectively)	68,585,000		52,752,000	[1]
Net investment by Anadarko	0		199,960,000	[1]
Total partners' capital	2,195,625,000		2,209,778,000	[1]
Noncontrolling interests	72,371,000		70,658,000	[1]
Total equity and partners' capital	2,267,996,000		2,280,436,000	[1]
Total liabilities, equity and partners' capital	4,042,231,000		3,749,922,000	[1]
Affiliated Entity [Member]
Current assets
Accounts receivable, net	40,100,000		19,100,000
Other current assets	100,000		400,000
Current liabilities
Accounts and natural gas imbalance payables	2,800,000		2,500,000
Accrued liabilities	$ 100,000		$ 100,000

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

[2] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $40.1 million and $19.1 million as of September 30, 2013, and December 31, 2012, respectively.

[3] Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of September 30, 2013, and December 31, 2012, respectively.

[4] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.8 million and $2.5 million as of September 30, 2013, and December 31, 2012, respectively.

[5] Accrued liabilities include amounts payable to affiliates of $0.1 million as of September 30, 2013 and December 31, 2012.

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Partnership Distributions

9 Months Ended

Sep. 30, 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
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
2013
March 31	$	0.540	$	70,143	May 2013
June 30	$	0.560	$	79,315	August 2013
September 30(1)	$	0.580	$	83,986	November 2013

⁽¹⁾  On October 16, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.58 per unit, or $84.0 million in aggregate, including incentive distributions. The cash distribution is payable on November 12, 2013, to unitholders of record at the close of business on October 31, 2013.

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Components of Working Capital (tables)

9 Months Ended

Sep. 30, 2013

Components Of Working Capital [Abstract]

Other Current Assets Table

A summary of other current assets is as follows:

thousands	September 30, 2013		December 31, 2012
Natural gas liquids inventory	$	2,438	$	1,678
Natural gas imbalance receivables	2,729		1,663
Prepaid insurance	1,934		1,897
Other	1,662		1,760
Total other current assets	$	8,763	$	6,998

Accrued Liabilities Table

A summary of accrued liabilities is as follows:

thousands	September 30, 2013		December 31, 2012
Accrued capital expenditures	$	100,876	$	112,311
Accrued plant purchases	20,738		16,350
Accrued interest expense	16,620		15,868
Short-term asset retirement obligations	1,187		1,711
Short-term remediation and reclamation obligations	609		799
Other	136		612
Total accrued liabilities	$	140,166	$	147,651

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Description of Business and Basis of Presentation (tables)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Assets Table

As of September 30, 2013, the Partnership’s assets, exclusive of interests in Fort Union, White Cliffs, Rendezvous and the Mont Belvieu JV accounted for under the equity method, consisted of the following:

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

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Debt and Interest Expense - Debt Activity Table (details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Debt Instrument [Line Items]
Beginning Balance	$ 1,168,278	[1]
Other	(168)
Ending Balance	1,518,110
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Beginning Balance	0
Borrowings	595,000
Repayments	(495,000)
Ending Balance	100,000
Senior Notes 2 Point 6 Percent Due 2018 [Member]
Debt Instrument [Line Items]
Beginning Balance	0
Borrowings	250,000
Ending Balance	$ 249,705

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

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Transactions With Affiliates - Commodity Price Per Unit Table (details)	Sep. 30, 2013
Ethane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	23.11
Ethane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	18.32
Ethane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	18.36
Ethane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	18.41
Ethane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	30.10
Ethane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	30.53
Ethane [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	23.41
Propane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	52.90
Propane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	45.90
Propane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	46.47
Propane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	47.08
Propane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	55.84
Propane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	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 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	60.44
Isobutane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	61.24
Isobutane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	62.09
Isobutane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	77.66
Isobutane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	75.13
Isobutane [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	74.02
Normal Butane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	64.93
Normal Butane [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.20
Normal Butane [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	53.89
Normal Butane [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	54.62
Normal Butane [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	68.24
Normal Butane [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	66.01
Normal Butane [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	65.04
Natural Gasoline [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.68
Natural Gasoline [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	70.89
Natural Gasoline [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	71.85
Natural Gasoline [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	72.88
Natural Gasoline [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	92.23
Natural Gasoline [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	83.04
Natural Gasoline [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.82
Condensate [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.68
Condensate [Member] | Minimum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	74.04
Condensate [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	75.22
Condensate [Member] | Minimum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	76.47
Condensate [Member] | Maximum [Member] | Year 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	85.84
Condensate [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	83.04
Condensate [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	81.82
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 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	3.75
Natural Gas (per MMbtu) [Member] | Minimum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	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 2013 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	6.09
Natural Gas (per MMbtu) [Member] | Maximum [Member] | Year 2014 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	6.20
Natural Gas (per MMbtu) [Member] | Maximum [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity Swap Fixed Price	5.96

XML

Description of Business and Basis of Presentation - Additional Information (details) (USD $) In Millions, except Share data, unless otherwise specified			9 Months Ended			9 Months Ended			1 Months Ended			1 Months Ended	9 Months Ended
	May 31, 2013	Jun. 30, 2012	Sep. 30, 2012 Statement Of Cash Flow [Member]	Sep. 30, 2013 Fort Union [Member]	Sep. 30, 2013 Rendezvous [Member]	Sep. 30, 2013 Non-Operated Marcellus Interest [Member]	Sep. 30, 2013 Anadarko-Operated Marcellus Interest [Member]	Sep. 30, 2013 Newcastle [Member]	Jul. 31, 2009 Chipeta Processing Limited Liability Company [Member]	Sep. 30, 2013 Chipeta Processing Limited Liability Company [Member]	Aug. 31, 2012 Chipeta Processing Limited Liability Company [Member]	Dec. 31, 2012 Western Gas Equity Partners [Member]	Sep. 30, 2013 Western Gas Equity Partners [Member]	Sep. 30, 2013 Western Gas Equity Partners [Member] Incentive Distribution Rights [Member]
Equity method investment ownership				14.81%	22.00%
Ownership interest						33.75%	33.75%	50.00%	51.00%				100.00%
Percentage ownership of general partner													2.00%
General partner's interest														100.00%
Common units issued												19,758,150
Price per unit	$ 61.18	$ 43.88										$ 22.00
Proceeds From Issuance of Private Placement												$ 409.4
Correction of error			$ 35.7
Ownership interest by noncontrolling owners										25.00%	24.00%

XML

Description of Business and Basis of Presentation - Asset Table (details)	Sep. 30, 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
Natural Gas Treating Facilities [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	8
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 Liquids Pipeline [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	3
Natural Gas Pipelines [Member] | Operated [Member]
Assets [Line Items]
Assets, number of units	3

XML

Components of Working Capital - Accrued Liabilities Table (details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Accrued Liabilities [Line Items]
Other accrued liabilities	$ 136		$ 612
Accrued interest expense	16,620		15,868
Short-term asset retirement obligations	1,187		1,711
Short-term remediation and reclamation obligations	609		799
Accrued liabilities	140,166	[1]	147,651	[1],[2]
Accrued Capital Expenditures [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	100,876		112,311
Accrued Plant Purchases [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	$ 20,738		$ 16,350

[1] Accrued liabilities include amounts payable to affiliates of $0.1 million as of September 30, 2013 and December 31, 2012.

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

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Partnership Distributions - Additional Information (details)	9 Months Ended
	Sep. 30, 2013
Distributions Made to Members or Limited Partners [Abstract]
Partnership agreement day requirement of distribution of available cash	45 days

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Transactions With Affiliates - Equipment Purchase and Sale Table (details) (USD $) In Thousands, unless otherwise specified	9 Months Ended						9 Months Ended
	Sep. 30, 2013		Dec. 31, 2012		Sep. 30, 2013 Affiliated Entity [Member]	Dec. 31, 2012 Affiliated Entity [Member]	Sep. 30, 2013 Affiliated Entity [Member] Purchases [Member]		Sep. 30, 2012 Affiliated Entity [Member] Purchases [Member]		Sep. 30, 2013 Affiliated Entity [Member] Sales [Member]		Sep. 30, 2012 Affiliated Entity [Member] Sales [Member]
Related Party Transaction [Line Items]
Consideration given for equipment							$ 6,167	[1]	$ 18,946	[1]
Consideration received for equipment											82	[1]	760	[1]
Net carrying value							2,039		6,765		34		392
Partners' capital adjustment	308						4,128		12,181		48		368
Table Text Block Supplement [Abstract]
Accounts payable	$ 19,131	[2]	$ 25,154	[2],[3]	$ 2,800	$ 2,500	$ 1,800

[1] Includes a payable of $1.8 million for pipe and equipment purchased in September 2013.

[2] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.8 million and $2.5 million as of September 30, 2013, and December 31, 2012, respectively.

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

XML

Debt and Interest Expense - Interest Expense Table (details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Debt Instrument [Line Items]
Interest Expense	$ 13,018,000	[1]	$ 10,977,000	[1],[2]	$ 37,483,000	[1]	$ 30,118,000	[1],[2]
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			400,000				800,000
Third Parties [Member]
Debt Instrument [Line Items]
Interest expense on long-term debt	14,994,000		11,919,000		43,783,000		28,036,000
Amortization of debt issuance costs and commitment fees	1,135,000	[3]	1,201,000	[3]	3,252,000	[3]	3,225,000	[3]
Capitalized interest	(3,111,000)		(2,224,000)		(9,552,000)		(3,827,000)
Interest Expense	13,018,000		10,896,000		37,483,000		27,434,000
Affiliated Entity [Member]
Debt Instrument [Line Items]
Interest expense on note payable to Anadarko	0	[4]	0	[4]	0	[4]	2,440,000	[4]
Interest expense on affiliate balances	0	[5]	81,000	[5]	0	[5]	244,000	[5]
Interest Expense	0	[6],[7]	81,000	[6]	0	[6]	2,684,000	[8]
Senior Notes 2 Point 6 Percent Due 2018 [Member] | 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	$ 300,000				$ 800,000

[1] Includes affiliate (as defined in Note 1) interest expense of zero for the three and nine months ended September 30, 2013, and $0.1 million and $2.7 million for the three and nine months ended September 30, 2012, respectively. See Note 8.

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

[3] For the three and nine months ended September 30, 2013, includes $0.3 million and $0.8 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 2018 Notes and (iii) underwriters’ fees. For the three and nine months ended September 30, 2012, includes $0.4 million and $0.8 million, respectively, of amortization of the original issue discount and underwriters’ fees for the 2022 Notes issued in June 2012 and the 2021 Notes.

[4] In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 8.

[5] Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada and Lancaster plants.

[6] For the three and nine months ended September 30, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 8) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. 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 and Lancaster plants in the fourth quarter of 2012. See Note receivable from and amounts payable to Anadarko within this Note 5.

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

[8] Represents interest income recognized on the note receivable from Anadarko.

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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	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Anadarko-Operated Marcellus Interest [Member]
Business Acquisition [Line Items]
Revenues	$ 764,128	$ 682,820
Net income	196,872	153,423
Net income attributable to Western Gas Partners, LP	$ 189,405	$ 141,467
Net income per common unit - basic and diluted	$ 1.26	$ 1.12

XML

Property, Plant and Equipment Table (details) (USD $) In Thousands, unless otherwise specified								9 Months Ended				9 Months Ended						9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012		Sep. 30, 2013 Land [Member]	Dec. 31, 2012 Land [Member]	Sep. 30, 2013 Gathering systems [Member]	Dec. 31, 2012 Gathering systems [Member]	Sep. 30, 2013 Gathering systems [Member] Minimum [Member]	Sep. 30, 2013 Gathering systems [Member] Maximum [Member]	Sep. 30, 2013 Pipelines And Equipment [Member]	Dec. 31, 2012 Pipelines And Equipment [Member]	Sep. 30, 2013 Pipelines And Equipment [Member] Minimum [Member]	Sep. 30, 2013 Pipelines And Equipment [Member] Maximum [Member]	Sep. 30, 2013 Asset Under Construction [Member]	Dec. 31, 2012 Asset Under Construction [Member]	Sep. 30, 2013 Other [Member]	Dec. 31, 2012 Other [Member]	Sep. 30, 2013 Other [Member] Minimum [Member]	Sep. 30, 2013 Other [Member] Maximum [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment	$ 4,061,389	$ 3,432,392	[1]	$ 2,584	$ 501	$ 3,610,879	$ 2,911,572			$ 119,278	$ 91,126			$ 318,107	$ 422,002	$ 10,541	$ 7,191
Accumulated depreciation	817,489	714,436	[1]
Net property, plant and equipment	$ 3,243,900	$ 2,717,956	[1]
Estimated useful life								3 years	47 years			15 years	45 years					3 years	25 years

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

XML

Debt and Interest Expense (tables)

9 Months Ended

Sep. 30, 2013

Debt Instruments [Abstract]

Debt Outstanding and Debt Activity Tables

The following table presents the Partnership’s outstanding debt as of September 30, 2013, and December 31, 2012:

	September 30, 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	$	673,363	$	651,580	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021	500,000		495,042		531,210		500,000		494,661		499,946
Revolving credit facility	100,000		100,000		100,000		—		—		—
2.600% Senior Notes due 2018	250,000		249,705		249,134		—		—		—
Total debt outstanding	$	1,520,000	$	1,518,110	$	1,531,924	$	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 nine months ended September 30, 2013:

thousands	Carrying Value
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings	595,000
Repayments of revolving credit facility	(495,000		)
Issuance of 2.600% Senior Notes due 2018	250,000
Other	(168		)
Balance as of September 30, 2013	$	1,518,110

Interest Expense Table

The following table summarizes the amounts included in interest expense:

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Third parties
Interest expense on long-term debt	$	14,994		$	11,919		$	43,783		$	28,036
Amortization of debt issuance costs and commitment fees (1)	1,135			1,201			3,252			3,225
Capitalized interest	(3,111		)	(2,224		)	(9,552		)	(3,827		)
Total interest expense – third parties	13,018			10,896			37,483			27,434
Affiliates
Interest expense on note payable to Anadarko (2)	—			—			—			2,440
Interest expense on affiliate balances (3)	—			81			—			244
Total interest expense – affiliates	—			81			—			2,684
Interest expense	$	13,018		$	10,977		$	37,483		$	30,118

⁽¹⁾  For the three and nine months ended September 30, 2013, includes $0.3 million and $0.8 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 2018 Notes and (iii) underwriters’ fees. For the three and nine months ended September 30, 2012, includes $0.4 million and $0.8 million, respectively, of amortization of the original issue discount and underwriters’ fees for the 2022 Notes issued in June 2012 and the 2021 Notes.

⁽²⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 8.

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

XML

Consolidated Statement of Equity and Partners' Capital (USD $) In Thousands		Total	Net Investment by Anadarko [Member]	Common Units [Member]	General Partner [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2012	[1]	$ 2,280,436	$ 199,960	$ 1,957,066	$ 52,752	$ 70,658
Net income		196,724	4,637	136,887	47,733	7,467
Issuance of common and general partner units, net of offering expenses		427,795		418,517	9,278
Contributions from noncontrolling interest owners		2,247				2,247
Distributions to noncontrolling interest owners		(8,001)				(8,001)
Distributions to unitholders		(215,115)		(173,976)	(41,139)
Acquisitions from affiliates		(465,500)	(255,635)	(209,865)
Contributions of equity-based compensation from Anadarko		2,144		2,101	43
Net pre-acquisition contributions from (distributions to) Anadarko		4,508	4,508
Net distributions of other assets to Anadarko		(4,080)		(3,998)	(82)
Elimination of net deferred tax liabilities		46,530	46,530
Other		308		308
Balance at Sep. 30, 2013		$ 2,267,996		$ 2,127,040	$ 68,585	$ 72,371

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

XML

Description of Business and Basis of Presentation

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Basis of Presentation

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

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.

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 consolidated subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), and a joint venture, Enterprise EF78 LLC (“Mont Belvieu JV”). See Note 2. “Equity investment throughput” refers to the Partnership’s 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as third-party producers and customers. As of September 30, 2013, the Partnership’s assets, exclusive of interests in Fort Union, White Cliffs, Rendezvous and the Mont Belvieu JV accounted for under the equity method, consisted of the following:

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

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

Western Gas Equity Partners, LP. In December 2012, WGP completed its initial public offering (“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 approximately $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. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (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. Investments in noncontrolled 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 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. 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, and certain prior-period amounts have been reclassified to conform to the current-year presentation.

For the nine months ended September 30, 2012, operating cash inflows and investing cash outflows in the Partnership’s unaudited consolidated statements of cash flows include a reduction of $35.7 million attributable to the correction of an error discovered during analysis of accounts payable balances. This analysis revealed that certain 2012 invoices received, but not yet paid, were properly attributable to ongoing capital projects rather than to operating expenses. Management concluded that this misstatement was not material relative to the nine months ended September 30, 2012, and has corrected the error within the unaudited statement of cash flows for the nine months ended September 30, 2012, as included in this report.

Certain information and note disclosures commonly included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s 2012 Form 10-K, as filed with the SEC on February 28, 2013, certain sections of which were recast in the Partnership’s Current Report on Form 8-K, as filed with the SEC on May 13, 2013, to reflect the results of the Non-Operated Marcellus Interest acquisition (as defined in Note 2). Management believes that the disclosures made are adequate to make the information not misleading.

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement. On August 1, 2012, the Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (the “additional Chipeta interest”). Prior to this transaction, the interests in Chipeta held by Anadarko and a third-party member were reflected as noncontrolling interests in the consolidated financial statements. The acquisition of Anadarko’s then remaining 24% interest was accounted for on a prospective basis as the Partnership acquired an additional interest in an already-consolidated entity. As such, effective August 1, 2012, 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. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of September 30, 2013. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s general partner, each of the Partnership’s acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such assets as of the date of common control. See Note 2.

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

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

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Equity and Partners' Capital

9 Months Ended

Sep. 30, 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 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
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

⁽¹⁾  Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

⁽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.

In addition, pursuant to the Partnership’s registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”), the Partnership initiated trades totaling 218,750 common units during the three and nine months ended September 30, 2013, at an average price per unit of $58.22, generating gross proceeds of $12.7 million (including the general partner’s proportionate capital contribution and before $0.1 million of invoiced offering expenses), of which $2.7 million had been received as of September 30, 2013.

4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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

The following table summarizes common and general partner units issued during the nine months ended September 30, 2013:

	Common Units	General Partner Units	Total
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	6,879	140	7,019
May 2013 equity offering	7,015,000	143,163	7,158,163
Continuous Offering Program	43,350	174	43,524
Balance at September 30, 2013	112,174,911	2,288,573	114,463,484

Holdings of Partnership equity. As of September 30, 2013, WGP held 49,296,205 common units, representing a 43.1% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,288,573 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the Partnership’s IDRs. As of September 30, 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 September 30, 2013, the public held 62,429,577 common units, representing a 54.5% limited partner interest in the Partnership.

The Partnership’s net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 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.

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.

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Acquisitions

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

Acquisitions

2. ACQUISITIONS

The following table presents the acquisitions completed by the Partnership during 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
MGR (1)	01/13/2012	100	%	$	299,000	$	159,587	632,783	12,914
Chipeta (2)	08/01/2012	24	%	—		128,250		151,235	3,086
Non-Operated Marcellus Interest(3)	03/01/2013	33.75	%	250,000		215,500		449,129	—
Anadarko-Operated Marcellus Interest(4)	03/08/2013	33.75	%	133,500		—		—	—
Mont Belvieu JV(5)	06/05/2013	25	%	—		78,129		—	—
OTTCO(6)	09/03/2013	100	%	27,500		—		—	—

⁽¹⁾  The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”

⁽²⁾  The Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (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.

⁽³⁾  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. See Non-Operated Marcellus Interest acquisition below for further information.

⁽⁴⁾  The interest acquired from a third party consisted of 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. 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 as of September 30, 2013.

⁽⁵⁾  The acquisition from a third party consisted of a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. 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.

⁽⁶⁾  The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline which connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming. The assets acquired are referred to as the “OTTCO pipeline” and the acquisition as the “OTTCO acquisition.”

2. ACQUISITIONS (CONTINUED)

Non-Operated Marcellus Interest acquisition. Because the Non-Operated Marcellus Interest acquisition was a transfer of net assets between entities under common control, the Partnership’s historical financial statements previously filed with the SEC have been recast in this Form 10-Q to include the results attributable to the Non-Operated Marcellus Interest as if the Partnership owned such assets for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko, including the Non-Operated Marcellus Interest, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

The following table presents the revenue and net income impact of the Non-Operated Marcellus Interest on revenue and net income as presented in the Partnership’s historical consolidated statements of income:

	Three Months Ended September 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	219,020	$	15,714	$	234,734
Net income	42,940		7,062		50,002

	Nine Months Ended September 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	636,603	$	43,117	$	679,720
Net income	135,913		19,582		155,495

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 as of September 30, 2013, 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.

2. ACQUISITIONS (CONTINUED)

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

	Nine Months Ended   September 30,
thousands except per-unit amounts	2013		2012
Revenues	$	764,128	$	682,820
Net income	196,872		153,423
Net income attributable to Western Gas Partners, LP	189,405		141,467
Net income per common unit - basic and diluted	$	1.26	$	1.12

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 $8.1 million of revenues and $0.5 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 nine months ended September 30, 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.

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. The Partnership will begin to amortize the capitalized interest recognized subsequent to the acquisition upon completion of the facilities, and will reflect the amortization as an adjustment to equity earnings from the Mont Belvieu JV.

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Transactions With Affiliates - Summary Table (details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								9 Months Ended						3 Months Ended				9 Months Ended
	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2012		Jun. 30, 2012	Mar. 31, 2012	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013 Chipeta Processing Limited Liability Company [Member]	Aug. 31, 2012 Chipeta Processing Limited Liability Company [Member]	Sep. 30, 2013 Affiliated Entity [Member]		Sep. 30, 2012 Affiliated Entity [Member]		Sep. 30, 2013 Affiliated Entity [Member]		Sep. 30, 2012 Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues	$ 278,001				$ 234,734	[1]			$ 762,874		$ 679,720	[1]			$ 217,624	[2]	$ 180,605	[1],[2]	$ 603,214	[2]	$ 519,460	[1],[2]
Cost of product	93,516	[3]			89,107	[1],[3]			270,059	[3]	254,719	[1],[3]			33,753	[2]	42,839	[2]	97,801	[2]	115,603	[2]
Operation and maintenance	42,757	[3]			35,493	[1],[3]			121,165	[3]	103,304	[1],[3]			13,469	[4]	12,638	[4]	41,021	[4]	38,040	[4]
General and administrative	7,276	[3]			15,039	[1],[3]			22,228	[3]	35,623	[1],[3]			5,867	[5]	14,227	[5]	17,325	[5]	30,811	[5]
Operating expenses	187,813				173,422	[1]			538,523		491,907	[1]			53,089		69,704		156,147		184,454
Interest income, net	4,225	[6]			4,225	[6]			12,675	[6]	12,675	[6]
Interest expense	13,018	[7]			10,977	[1],[7]			37,483	[7]	30,118	[1],[7]			0	[2],[8]	81	[8]	0	[8]	2,684	[6]
Distributions to unitholders	83,986	[9]	79,315	70,143	56,346		52,425	46,053							44,378	[10]	25,852	[10]	121,493	[10]	69,615	[10]
Contributions from noncontrolling interest owners									2,247						0	[11]	2,148	[11]	0	[11]	12,588	[11]
Distributions to noncontrolling interest owners									$ 8,001						$ 0	[11]	$ 1,464	[11]	$ 0	[11]	$ 6,528	[11]
Table Text Block Supplement [Abstract]
Ownership interest by noncontrolling owners													25.00%	24.00%

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

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

[3] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $33.8 million and $97.8 million for the three and nine months ended September 30, 2013, respectively, and $42.8 million and $115.6 million for the three and nine months ended September 30, 2012, respectively. Operation and maintenance includes charges from Anadarko of $13.5 million and $41.0 million for the three and nine months ended September 30, 2013, respectively, and $12.6 million and $38.0 million for the three and nine months ended September 30, 2012, respectively. General and administrative includes charges from Anadarko of $5.9 million and $17.3 million for the three and nine months ended September 30, 2013, respectively, and $14.2 million and $30.8 million for the three and nine months ended September 30, 2012, respectively. See Note 5.

[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 Equity incentive plan and Anadarko incentive plans within this Note 5).

[6] Represents interest income recognized on the note receivable from Anadarko.

[7] Includes affiliate (as defined in Note 1) interest expense of zero for the three and nine months ended September 30, 2013, and $0.1 million and $2.7 million for the three and nine months ended September 30, 2012, respectively. See Note 8.

[8] For the three and nine months ended September 30, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 8) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. 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 and Lancaster plants in the fourth quarter of 2012. See Note receivable from and amounts payable to Anadarko within this Note 5.

[9] On October 16, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.58 per unit, or $84.0 million in aggregate, including incentive distributions. The cash distribution is payable on November 12, 2013, to unitholders of record at the close of business on October 31, 2013.

[10] Represents distributions paid under the partnership agreement.

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

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Acquisitions - Acquisitions Table (details) (USD $) In Thousands, except Share data, unless otherwise specified	9 Months Ended				1 Months Ended			1 Months Ended		9 Months Ended	1 Months Ended							1 Months Ended
	Sep. 30, 2013	Sep. 30, 2012		Dec. 31, 2012	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]		Sep. 30, 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 Mont Belvieu JV [Member]		Jun. 30, 2013 Mont Belvieu JV [Member] Fractionator [Member]	Sep. 30, 2013 Overland Trail Transmission Limited Liability Company [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]		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]		24.00%	[2]	75.00%	33.75%	[3]	33.75%	[4]				100.00%	[5]
Equity method investment ownership							22.00%								25.00%	[6]
Borrowings	$ 842,566	$ 885,291	[7]		$ 299,000	[1]					$ 250,000	[3]	$ 133,500	[4]				$ 27,500	[5]
Cash on hand					159,587	[1]		128,250	[2]		215,500	[3]			78,129	[6]
Units issued																				632,783	[1]	151,235	[2]	449,129	[3]	12,914	[1]	3,086	[2]
Table Text Block Supplement [Abstract]
Ownership interest by noncontrolling owners										25.00%
GP units issued	2,288,573			2,135,930							9,166
Proceeds from issuance of common and general partner units, net of offering expenses	$ 427,848	$ 216,462	[7]								$ 500
General partner's interest											2.00%
Assets, number of units																	2

[1] The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”

[2] The Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (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.

[3] 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. See Non-Operated Marcellus Interest acquisition below for further information.

[4] The interest acquired from a third party consisted of 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. 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 as of September 30, 2013.

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

[6] The acquisition from a third party consisted of a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. 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.

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

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Acquisitions - Additional Information (details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012		Sep. 30, 2013	Sep. 30, 2012
Business Acquisition [Line Items]
Revenues	$ 278,001	$ 234,734	[1]	$ 762,874	$ 679,720	[1]
Operating expenses	187,813	173,422	[1]	538,523	491,907	[1]
Anadarko-Operated Marcellus Interest [Member]
Business Acquisition [Line Items]
Revenues				8,100
Operating expenses				500
Purchase price adjustment	134,645			134,645
Anadarko-Operated Marcellus Interest [Member] | Purchase Price Allocation Adjustments [Member]
Business Acquisition [Line Items]
Purchase price adjustment	$ 1,100			$ 1,100

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

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Equity and Partners' Capital - Additional Information (details) (USD $)					9 Months Ended	1 Months Ended						9 Months Ended						9 Months Ended
	Sep. 30, 2013	May 31, 2013	Dec. 31, 2012	Jun. 30, 2012	Sep. 30, 2013 Western Gas Equity Partners [Member]	May 31, 2013 Common Units [Member]		Jun. 30, 2012 Common Units [Member]		Sep. 30, 2013 Common Units [Member]	Dec. 31, 2012 Common Units [Member]	Sep. 30, 2013 Common Units [Member] Western Gas Equity Partners [Member]	Sep. 30, 2013 Common Units [Member] Anadarko Marcellus Midstream [Member]	Sep. 30, 2013 Common Units [Member] Public [Member]	Sep. 30, 2013 Incentive Distribution Rights [Member] Western Gas Equity Partners [Member]	Sep. 30, 2013 Continuous Offering Program [Member]	Aug. 31, 2012 Continuous Offering Program [Member]	Sep. 30, 2013 Continuous Offering Program [Member] Initiated Trade [Member]	Sep. 30, 2013 Continuous Offering Program [Member] Common Units [Member]
Schedule Of Investments [Line Items]
Maximum aggregate principal of common stock																	$ 125,000,000
Common units issued						7,015,000	[1]	5,000,000	[1]									218,750	43,350
Average price per unit		$ 61.18		$ 43.88												$ 58.22
Offering expenses		13,203,000		7,468,000												100,000
Gross proceeds																$ 2,700,000		$ 12,700,000
Units owned										112,174,911	104,660,553	49,296,205	449,129	62,429,577
Ownership interest												43.10%	0.40%	54.50%
General partner units owned	2,288,573		2,135,930		2,288,573
General partner's interest					2.00%										100.00%

[1] Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

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Debt and Interest Expense - Additional Information (details) (USD $)			1 Months Ended	9 Months Ended	1 Months Ended			9 Months Ended			1 Months Ended	9 Months Ended			9 Months Ended			9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Dec. 31, 2012 Revolving Credit Facility [Member]	Sep. 30, 2013 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]	Sep. 30, 2013 Senior Notes 2 Point 6 Percent Due 2018 [Member]	Dec. 31, 2012 Senior Notes 2 Point 6 Percent Due 2018 [Member]	Sep. 30, 2013 Senior Notes 2 Point 6 Percent Due 2018 [Member] Indemnification Guarantee [Member]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Sep. 30, 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]	Sep. 30, 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]	Sep. 30, 2013 Note Payable To Anadarko [Member]	Dec. 31, 2010 Note Payable To Anadarko [Member]	Dec. 31, 2008 Note Payable To Anadarko [Member]
Debt Instrument [Line Items]
Principal	$ 1,520,000,000	$ 1,170,000,000	$ 0	$ 100,000,000			$ 250,000,000	$ 250,000,000	$ 0		$ 520,000,000	$ 670,000,000	$ 670,000,000	$ 150,000,000	$ 500,000,000	$ 500,000,000	$ 500,000,000			$ 175,000,000
Fixed interest rate							2.60%				4.00%			4.00%			5.375%		2.82%
Offering Percent							99.879%				99.194%			105.178%			98.778%
Effective interest rate							2.806%
Debt instrument, maturity date								Aug. 15, 2018				Jul. 01, 2022			Jun. 01, 2021			Aug. 02, 2013
Underwriting discount							1,500,000
Realized loss on terminated swap agreement											1,700,000
Line of credit, expiration date				Mar. 24, 2016
Revolving Credit Facility, current maximum borrowing capacity				800,000,000
Revolving Credit Facility, interest rate at period end			1.71%	1.68%
Facility fee			0.25%	0.25%	0.20%	0.35%
Outstanding borrowings				100,000,000
Outstanding letters of credit				12,800,000
Available borrowing capacity				687,200,000
Debt financings										$ 250,000,000.0

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Components of Working Capital - Other Current Assets Table (details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Other Current Assets [Line Items]
Natural gas liquids inventory	$ 2,438		$ 1,678
Natural gas imbalance receivables	2,729		1,663
Prepaid insurance	1,934		1,897
Other	1,662		1,760
Other current assets	$ 8,763	[1]	$ 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 September 30, 2013, and December 31, 2012, respectively.

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

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Consolidated Statements of Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Cost of product	$ 93,516	[1]	$ 89,107	[1],[2]	$ 270,059	[1]	$ 254,719	[1],[2]
Operation and maintenance	42,757	[1]	35,493	[1],[2]	121,165	[1]	103,304	[1],[2]
General and administrative	7,276	[1]	15,039	[1],[2]	22,228	[1]	35,623	[1],[2]
Interest expense	13,018	[3]	10,977	[2],[3]	37,483	[3]	30,118	[2],[3]
Affiliated Entity [Member]
Cost of product	33,753	[4]	42,839	[4]	97,801	[4]	115,603	[4]
Operation and maintenance	13,469	[5]	12,638	[5]	41,021	[5]	38,040	[5]
General and administrative	5,867	[6]	14,227	[6]	17,325	[6]	30,811	[6]
Interest expense	$ 0	[4],[7]	$ 81	[7]	$ 0	[7]	$ 2,684	[8]

[1] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $33.8 million and $97.8 million for the three and nine months ended September 30, 2013, respectively, and $42.8 million and $115.6 million for the three and nine months ended September 30, 2012, respectively. Operation and maintenance includes charges from Anadarko of $13.5 million and $41.0 million for the three and nine months ended September 30, 2013, respectively, and $12.6 million and $38.0 million for the three and nine months ended September 30, 2012, respectively. General and administrative includes charges from Anadarko of $5.9 million and $17.3 million for the three and nine months ended September 30, 2013, respectively, and $14.2 million and $30.8 million for the three and nine months ended September 30, 2012, respectively. See Note 5.

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

[3] Includes affiliate (as defined in Note 1) interest expense of zero for the three and nine months ended September 30, 2013, and $0.1 million and $2.7 million for the three and nine months ended September 30, 2012, respectively. See Note 8.

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

[5] 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.

[6] 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 Equity incentive plan and Anadarko incentive plans within this Note 5).

[7] For the three and nine months ended September 30, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 8) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. 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 and Lancaster plants in the fourth quarter of 2012. See Note receivable from and amounts payable to Anadarko within this Note 5.

[8] Represents interest income recognized on the note receivable from Anadarko.

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Components of Working Capital

9 Months Ended

Sep. 30, 2013

Components Of Working Capital [Abstract]

Components of Working Capital

7. COMPONENTS OF WORKING CAPITAL

A summary of other current assets is as follows:

thousands	September 30, 2013		December 31, 2012
Natural gas liquids inventory	$	2,438	$	1,678
Natural gas imbalance receivables	2,729		1,663
Prepaid insurance	1,934		1,897
Other	1,662		1,760
Total other current assets	$	8,763	$	6,998

A summary of accrued liabilities is as follows:

thousands	September 30, 2013		December 31, 2012
Accrued capital expenditures	$	100,876	$	112,311
Accrued plant purchases	20,738		16,350
Accrued interest expense	16,620		15,868
Short-term asset retirement obligations	1,187		1,711
Short-term remediation and reclamation obligations	609		799
Other	136		612
Total accrued liabilities	$	140,166	$	147,651

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
GP units issued	2,288,573		2,135,930
General partner units outstanding	2,288,573		2,135,930
Accounts receivable, net	$ 75,788	[1]	$ 50,233	[1],[2]
Other current assets	8,763	[3]	6,998	[2],[3]
Accounts and natural gas imbalance payables	19,131	[4]	25,154	[2],[4]
Accrued liabilities	140,166	[5]	147,651	[2],[5]
Affiliated Entity [Member]
Accounts receivable, net	40,100		19,100
Other current assets	100		400
Accounts and natural gas imbalance payables	2,800		2,500
Accrued liabilities	$ 100		$ 100
Common Units [Member]
Common units issued	112,174,911		104,660,553
Units outstanding	112,174,911		104,660,553

[1] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $40.1 million and $19.1 million as of September 30, 2013, and December 31, 2012, respectively.

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

[3] Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of September 30, 2013, and December 31, 2012, respectively.

[4] Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.8 million and $2.5 million as of September 30, 2013, and December 31, 2012, respectively.

[5] Accrued liabilities include amounts payable to affiliates of $0.1 million as of September 30, 2013 and December 31, 2012.

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Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Revenues
Total revenues	$ 278,001		$ 234,734	[1]	$ 762,874		$ 679,720	[1]
Operating expenses
Cost of product	93,516	[2]	89,107	[1],[2]	270,059	[2]	254,719	[1],[2]
Operation and maintenance	42,757	[2]	35,493	[1],[2]	121,165	[2]	103,304	[1],[2]
General and administrative	7,276	[2]	15,039	[1],[2]	22,228	[2]	35,623	[1],[2]
Property and other taxes	6,649		5,328	[1]	18,520		14,998	[1]
Depreciation, amortization and impairments	37,615		28,455	[1]	106,551		83,263	[1]
Total operating expenses	187,813		173,422	[1]	538,523		491,907	[1]
Operating income	90,188		61,312	[1]	224,351		187,813	[1]
Interest income, net - affiliates	4,225		4,225	[1]	12,675		12,675	[1]
Interest expense	(13,018)	[3]	(10,977)	[1],[3]	(37,483)	[3]	(30,118)	[1],[3]
Other income (expense), net	439		522	[1]	1,612		(287)	[1]
Income before income taxes	81,834		55,082	[1]	201,155		170,083	[1]
Income tax expense	58		5,080	[1]	4,431		14,588	[1]
Net income	81,776		50,002	[1]	196,724		155,495	[1]
Net income attributable to noncontrolling interests	3,376		3,423	[1]	7,467		11,956	[1]
Net income attributable to Western Gas Partners, LP	78,400		46,579	[1]	189,257		143,539	[1]
Limited partners' interest in net income:
Pre-acquisition net (income) loss allocated to Anadarko	0		(7,062)	[1]	(4,637)		(19,582)	[1]
General partner interest in net (income) loss	(18,693)	[4]	(8,042)	[1],[4]	(47,733)	[4]	(18,508)	[1],[4]
Limited partners' interest in net income	59,707	[4]	31,475	[1],[4]	136,887	[4]	105,449	[1],[4]
Affiliated Entity [Member]
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	83,606		61,388	[1]	218,680		182,448	[1]
Natural gas, natural gas liquids and condensate sales	129,411		115,132	[1]	371,077		324,793	[1]
Equity income and Other, net	4,607		4,085	[1]	13,457		12,219	[1]
Total revenues	217,624	[5]	180,605	[1],[5]	603,214	[5]	519,460	[1],[5]
Operating expenses
Cost of product	33,753	[5]	42,839	[5]	97,801	[5]	115,603	[5]
Operation and maintenance	13,469	[6]	12,638	[6]	41,021	[6]	38,040	[6]
General and administrative	5,867	[7]	14,227	[7]	17,325	[7]	30,811	[7]
Total operating expenses	53,089		69,704		156,147		184,454
Interest expense	0	[5],[8]	(81)	[8]	0	[8]	(2,684)	[9]
Third Parties [Member]
Revenues
Gathering, processing and transportation of natural gas and natural gas liquids	47,175		32,545	[1]	124,791		96,518	[1]
Natural gas, natural gas liquids and condensate sales	11,915		20,974	[1]	31,539		62,025	[1]
Equity income and Other, net	1,287		610	[1]	3,330		1,717	[1]
Total revenues	60,377		54,129	[1]	159,660		160,260	[1]
Operating expenses
Interest expense	$ (13,018)		$ (10,896)		$ (37,483)		$ (27,434)
Limited Partners [Member] | Common Units [Member]
Limited partners' interest in net income:
Net income per common unit - basic and diluted	$ 0.53		$ 0.33	[1]	$ 1.26		$ 1.14	[1]
Weighted average common units outstanding - basic and diluted	112,143		95,883	[1]	108,540		92,627	[1]

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

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $33.8 million and $97.8 million for the three and nine months ended September 30, 2013, respectively, and $42.8 million and $115.6 million for the three and nine months ended September 30, 2012, respectively. Operation and maintenance includes charges from Anadarko of $13.5 million and $41.0 million for the three and nine months ended September 30, 2013, respectively, and $12.6 million and $38.0 million for the three and nine months ended September 30, 2012, respectively. General and administrative includes charges from Anadarko of $5.9 million and $17.3 million for the three and nine months ended September 30, 2013, respectively, and $14.2 million and $30.8 million for the three and nine months ended September 30, 2012, respectively. See Note 5.

[3] Includes affiliate (as defined in Note 1) interest expense of zero for the three and nine months ended September 30, 2013, and $0.1 million and $2.7 million for the three and nine months ended September 30, 2012, respectively. See Note 8.

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

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

[6] 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.

[7] 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 Equity incentive plan and Anadarko incentive plans within this Note 5).

[8] For the three and nine months ended September 30, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 8) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. 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 and Lancaster plants in the fourth quarter of 2012. See Note receivable from and amounts payable to Anadarko within this Note 5.

[9] Represents interest income recognized on the note receivable from Anadarko.

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Commitments and Contingencies - Additional Information (details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Purchase Commitment [Member]	Sep. 30, 2013 Mont Belvieu JV [Member]	Jun. 30, 2013 Mont Belvieu JV [Member]
Commitments and Contingencies [Line Items]
Committed capital	$ 61.3		$ 61.3			$ 13.6
Term of instrument or obligation					12 months	6 months
Equity method investment ownership							25.00%
Rent expense associated with office and equipment leases	$ 0.6	$ 0.8	$ 2.0	$ 2.3

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Acquisitions - Impact to Historical Consolidated Statement of Income Table (details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012		Sep. 30, 2013	Sep. 30, 2012
Revenues	$ 278,001	$ 234,734	[1]	$ 762,874	$ 679,720	[1]
Net income	81,776	50,002	[1]	196,724	155,495	[1]
Partnership Historical [Member]
Revenues		219,020			636,603
Net income		42,940			135,913
Non-Operated Marcellus Interest [Member]
Revenues		15,714			43,117
Net income		$ 7,062			$ 19,582

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

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Property, Plant and Equipment (table)

9 Months Ended

Sep. 30, 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:

thousands	Estimated Useful Life	September 30, 2013		December 31, 2012
Land	n/a	$	2,584	$	501
Gathering systems	3 to 47 years	3,610,879		2,911,572
Pipelines and equipment	15 to 45 years	119,278		91,126
Assets under construction	n/a	318,107		422,002
Other	3 to 25 years	10,541		7,191
Total property, plant and equipment		4,061,389		3,432,392
Accumulated depreciation		817,489		714,436
Net property, plant and equipment		$	3,243,900	$	2,717,956

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Property, Plant and Equipment - Additional Information (details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Property, Plant and Equipment [Abstract]
Impairment	$ 1.0

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Transactions With Affiliates - Gains Losses Commodity Price Swap Table (details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ 10,562		$ 9,315		$ 31,143		$ 6,406
Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	34,464	[1]	35,118	[1]	97,756	[1]	76,748	[1]
Cost Of Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	(23,902)	[2]	(25,803)	[2]	(66,613)	[2]	(70,342)	[2]
Natural Gas Per Thousand Cubic Feet [Member] | Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	6,923	[1]	9,132	[1]	14,707	[1]	30,728	[1]
Natural Gas Liquids [Member] | Sales [Member]
Gains (losses) on commodity price swap
Net gains (losses) on commodity price swap agreements	$ 27,541	[1]	$ 25,986	[1]	$ 83,049	[1]	$ 46,020	[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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Equity and Partners' Capital - Equity Offerings Table (details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended											9 Months Ended
	May 31, 2013	Jun. 30, 2012	May 31, 2013 Common Units [Member]		Jun. 30, 2012 Common Units [Member]		May 31, 2013 Common Units [Member] Option On Securities [Member]	May 31, 2013 General Partner [Member]		Jun. 30, 2012 General Partner [Member]		Sep. 30, 2013 Western Gas Equity Partners [Member]
Capital Unit [Line Items]
Common units issued			7,015,000	[1]	5,000,000	[1]	915,000
General partner units issued								143,163	[2]	102,041	[2]
Price per unit	$ 61.18	$ 43.88
Underwriting discount and other offering expenses	$ 13,203	$ 7,468
Net proceeds	$ 424,733	$ 216,409
Table Text Block Supplement [Abstract]
General partner's interest												2.00%

[1] Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

[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.

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Equity and Partners' Capital - Limited Partner and General Partner Units (details)	1 Months Ended				9 Months Ended
	May 31, 2013		Jun. 30, 2012		Sep. 30, 2013
Capital Unit [Line Items]
Balance					106,796,483
Long-Term Incentive Plan Awards					7,019
Balance					114,463,484
Non-Operated Marcellus Interest [Member]
Capital Unit [Line Items]
Acquisition					458,295
May 2013 Equity Offering [Member]
Capital Unit [Line Items]
Offering					7,158,163
Continuous Offering Program [Member]
Capital Unit [Line Items]
Offering					43,524
Common Units [Member]
Capital Unit [Line Items]
Balance					104,660,553
Long-Term Incentive Plan Awards					6,879
Common units issued	7,015,000	[1]	5,000,000	[1]
Balance					112,174,911
Common Units [Member] | Non-Operated Marcellus Interest [Member]
Capital Unit [Line Items]
Acquisition					449,129
Common Units [Member] | May 2013 Equity Offering [Member]
Capital Unit [Line Items]
Common units issued					7,015,000
Common Units [Member] | Continuous Offering Program [Member]
Capital Unit [Line Items]
Common units issued					43,350
General Partner [Member]
Capital Unit [Line Items]
Balance					2,135,930
Long-Term Incentive Plan Awards					140
Offering	143,163	[2]	102,041	[2]
Balance					2,288,573
General Partner [Member] | Non-Operated Marcellus Interest [Member]
Capital Unit [Line Items]
Acquisition					9,166
General Partner [Member] | May 2013 Equity Offering [Member]
Capital Unit [Line Items]
Offering					143,163
General Partner [Member] | Continuous Offering Program [Member]
Capital Unit [Line Items]
Offering					174

[1] Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

[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.

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

6. PROPERTY, PLANT AND EQUIPMENT

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

thousands	Estimated Useful Life	September 30, 2013		December 31, 2012
Land	n/a	$	2,584	$	501
Gathering systems	3 to 47 years	3,610,879		2,911,572
Pipelines and equipment	15 to 45 years	119,278		91,126
Assets under construction	n/a	318,107		422,002
Other	3 to 25 years	10,541		7,191
Total property, plant and equipment		4,061,389		3,432,392
Accumulated depreciation		817,489		714,436
Net property, plant and equipment		$	3,243,900	$	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 7.

During the second quarter of 2013, the Partnership recognized a $1.0 million impairment primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest.

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Acquisitions - Purchase Price Allocation Table (details) (Anadarko-Operated Marcellus Interest [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 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

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Transactions With Affiliates - Additional Information (details) (USD $)				1 Months Ended	9 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended		9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012		May 31, 2008 Note Receivable From Anadarko [Member]	Sep. 30, 2013 Note Receivable From Anadarko [Member]	Dec. 31, 2012 Note Receivable From Anadarko [Member]	Sep. 30, 2013 Note Payable To Anadarko [Member]	Dec. 31, 2008 Note Payable To Anadarko [Member]	Jun. 30, 2012 Senior Notes 4 Percent Due 2022 [Member]	Sep. 30, 2013 Gathering Transportation And Treating [Member]	Sep. 30, 2012 Gathering Transportation And Treating [Member]	Sep. 30, 2013 Gathering Transportation And Treating [Member]	Sep. 30, 2012 Gathering Transportation And Treating [Member]	Sep. 30, 2013 Processing [Member]	Sep. 30, 2012 Processing [Member]	Sep. 30, 2013 Processing [Member]	Sep. 30, 2012 Processing [Member]	Sep. 30, 2013 Long Term Incentive Plan [Member]	Sep. 30, 2012 Long Term Incentive Plan [Member]	Sep. 30, 2013 Long Term Incentive Plan [Member]	Sep. 30, 2012 Long Term Incentive Plan [Member]	Sep. 30, 2013 Anadarko Incentive Plans [Member]	Sep. 30, 2012 Anadarko Incentive Plans [Member]	Sep. 30, 2013 Anadarko Incentive Plans [Member]	Sep. 30, 2012 Anadarko Incentive Plans [Member]	Sep. 30, 2012 Incentive Plan [Member]	Sep. 30, 2012 Incentive Plan [Member]	Sep. 30, 2012 Incentive Plan [Member] Unit Appreciation Right [Member]	Sep. 30, 2013 Independent Director [Member] Long Term Incentive Plan [Member]
Related Party Transaction [Line Items]
Note receivable, due date					May 14, 2038
Note receivable - Anadarko	$ 260,000,000	$ 260,000,000	[1]	$ 260,000,000.0
Debt instrument, maturity date							Aug. 02, 2013
Fixed annual rate for note receivable bearing interest				6.50%
The fair value of the note receivable					301,500,000	334,800,000
Principal	1,520,000,000	1,170,000,000						175,000,000
Fixed interest rate									4.00%
AffiliateThroughput Percent										56.00%	63.00%	58.00%	64.00%	58.00%	61.00%	56.00%	59.00%
Phantom units vesting term																				3 years									1 year
Equity based compensation expense																		$ 100,000	$ 100,000	$ 400,000	$ 300,000	$ 800,000	$ 800,000	$ 2,200,000	$ 2,400,000	$ 8,600,000	$ 13,900,000
UVR, UAR and DER Valuation																												$ 1,053

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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

9. COMMITMENTS AND CONTINGENCIES

Litigation and legal proceedings. In March 2011, DCP Midstream LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering LLC, in Weld County District Court (the “Court”) in Colorado, alleging that Anadarko and its affiliates diverted gas from DCP’s gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering LLC, the entity which holds the Wattenberg assets. Anadarko countersued DCP asserting that DCP has not properly allocated values and charges to Anadarko for the gas that DCP gathers and/or processes, and seeks a judgment that DCP has no valid gathering or processing rights to much of the gas production it is claiming, in addition to other claims.

In July 2011, the Court denied the defendants’ motion to dismiss without ruling on the merits and the case is in the discovery phase. Trial is set for April 2014. Management does not believe the outcome of this proceeding will have a material effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership intends to vigorously defend this litigation. Furthermore, without regard to the merit of DCP’s claims, management believes that the Partnership has adequate contractual indemnities covering the claims against it in this lawsuit.

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

9. COMMITMENTS AND CONTINGENCIES (CONTINUED)

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 September 30, 2013, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of approximately $61.3 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. In addition, as of September 30, 2013, and in conjunction with the Mont Belvieu JV acquisition, the Partnership is committed to fund 25%, or approximately $13.6 million, of the total remaining estimated net project cost to complete the construction of the fractionation facilities over the next six months (see Note 2).

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 $0.6 million and $2.0 million for the three and nine months ended September 30, 2013, respectively, and $0.8 million and $2.3 million for the three and nine months ended September 30, 2012, respectively.

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Transactions With Affiliates

9 Months Ended

Sep. 30, 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 approximately $301.5 million and $334.8 million at September 30, 2013, and December 31, 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 8.

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. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. The Partnership has not entered into any new commodity price swap agreements since the fourth quarter of 2011.

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of September 30, 2013:

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

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	6,923		$	9,132		$	14,707		$	30,728
Natural gas liquids sales	27,541			25,986			83,049			46,020
Total	34,464			35,118			97,756			76,748
Losses on commodity price swap agreements related to purchases (2)	(23,902		)	(25,803		)	(66,613		)	(70,342		)
Net gains (losses) on commodity price swap agreements	$	10,562		$	9,315		$	31,143		$	6,406

⁽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. Approximately 56% and 63% of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended September 30, 2013 and 2012, respectively, and 58% and 64% for the nine months ended September 30, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 58% and 61% of the Partnership’s processing throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended September 30, 2013 and 2012, respectively, and 56% and 59% for the nine months ended September 30, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko.

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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

	Nine Months Ended September 30,
	2013		2012		2013		2012
thousands	Purchases				Sales
Consideration (1)	$	6,167	$	18,946	$	82	$	760
Net carrying value	2,039		6,765		34		392
Partners’ capital adjustment	$	4,128	$	12,181	$	48	$	368

⁽¹⁾ Includes a payable of $1.8 million for pipe and equipment purchased in September 2013.

Long-term incentive plan. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“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 $0.1 million and $0.4 million for the three and nine months ended September 30, 2013, respectively, and $0.1 million and $0.3 million for the three and nine months ended September 30, 2012, respectively.

Equity incentive plan and Anadarko incentive plans. The Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) and (ii) the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (“Anadarko Incentive Plans”).

The Partnership’s general and administrative expenses included $0.8 million and $2.2 million for the three and nine months ended September 30, 2013, respectively, and $0.8 million and $2.4 million for the three and nine months ended September 30, 2012, respectively, of equity-based compensation expense for awards granted to the executive officers of the general partner and other employees under the Anadarko Incentive Plans, which was allocated to the Partnership by Anadarko.

For the three and nine months ended September 30, 2012, the Partnership’s general and administrative expenses included $8.6 million and $13.9 million, respectively, of compensation expense for grants of Unit Value Rights, Unit Appreciation Rights (“UARs”) and Distribution Equivalent Rights 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. Awards outstanding under the Incentive Plan at September 30, 2012, were valued at $1,053 per UAR. WGP’s IPO in December 2012 resulted in the vesting of all then unvested Incentive Plan awards and the effective termination of the Incentive Plan.

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:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
thousands	2013		2012		2013		2012
Revenues (1)	$	217,624	$	180,605	$	603,214	$	519,460
Cost of product (1)	33,753		42,839		97,801		115,603
Operation and maintenance (2)	13,469		12,638		41,021		38,040
General and administrative (3)	5,867		14,227		17,325		30,811
Operating expenses	53,089		69,704		156,147		184,454
Interest income, net (4)	4,225		4,225		12,675		12,675
Interest expense (5)	—		81		—		2,684
Distributions to unitholders (6)	44,378		25,852		121,493		69,615
Contributions from noncontrolling interest owners (7)	—		2,148		—		12,588
Distributions to noncontrolling interest owners (7)	—		1,464		—		6,528

⁽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 Equity incentive plan and Anadarko incentive plans within this Note 5).

⁽⁴⁾  Represents interest income recognized on the note receivable from Anadarko.

⁽⁵⁾  For the three and nine months ended September 30, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 8) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. 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 and Lancaster plants in the fourth quarter of 2012. See Note receivable from and amounts payable to Anadarko within this Note 5.

⁽⁶⁾  Represents distributions paid under the partnership agreement.

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

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

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012
Cash flows from operating activities
Net income	$ 196,724		$ 155,495	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	106,551		83,263	[1]
Non-cash equity-based compensation expense	2,564		2,769	[1]
Deferred income taxes	1,207		21,565	[1]
Debt-related amortization and other items, net	1,756		1,728	[1]
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(27,387)		47,272	[1]
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	6,818		29,261	[1]
Change in other items, net	836		2,234	[1]
Net cash provided by operating activities	289,069		343,587	[1]
Cash flows from investing activities
Capital expenditures	(469,678)		(403,949)	[1]
Investments in equity affiliates	(45,126)		(147)	[1]
Other	(1,524)		0	[1]
Net cash used in investing activities	(1,226,404)		(1,009,296)	[1]
Cash flows from financing activities
Borrowings, net of debt issuance costs	842,566		885,291	[1]
Repayments of debt	(495,000)		(549,000)	[1]
Increase (decrease) in outstanding checks	(3,335)		2,534	[1]
Proceeds from issuance of common and general partner units, net of offering expenses	427,848		216,462	[1]
Distributions to unitholders	(215,115)		(141,505)	[1]
Contributions from noncontrolling interest owners	2,247		26,888	[1]
Distributions to noncontrolling interest owners	(8,001)		(14,303)	[1]
Net contributions from Anadarko	4,508		60,277	[1]
Net cash provided by financing activities	555,718		486,644	[1]
Net increase (decrease) in cash and cash equivalents	(381,617)		(179,065)	[1]
Cash and cash equivalents at beginning of period	419,981	[1]	226,559	[1]
Cash and cash equivalents at end of period	38,364		47,494	[1]
Supplemental disclosures
Net distributions to Anadarko of other assets	4,080		10,790	[1]
Interest paid, net of capitalized interest	34,974		16,460	[1]
Taxes paid	0		495	[1]
Affiliated Entity [Member]
Cash flows from investing activities
Acquisitions	(469,884)		(605,960)	[1]
Proceeds from sale of assets	82		760	[1]
Third Parties [Member]
Cash flows from investing activities
Acquisitions	$ (240,274)		$ 0	[1]

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

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Debt and Interest Expense - Debt Outstanding Table (details) (USD $)	Sep. 30, 2013		Dec. 31, 2012		Sep. 30, 2013 Revolving Credit Facility [Member]		Dec. 31, 2012 Revolving Credit Facility [Member]		Sep. 30, 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]	Sep. 30, 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]	Sep. 30, 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	$ 1,520,000,000		$ 1,170,000,000		$ 100,000,000		$ 0		$ 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	1,518,110,000		1,168,278,000	[1]	100,000,000		0		673,363,000		673,617,000				495,042,000		494,661,000			249,705,000			0
Fair Value	$ 1,531,924,000	[2]	$ 1,169,874,000	[2]	$ 100,000,000	[2]	$ 0	[2]	$ 651,580,000	[2]	$ 669,928,000	[2]			$ 531,210,000	[2]	$ 499,946,000	[2]		$ 249,134,000	[2]		$ 0	[2]

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

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

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Partnership Distributions - Cash Distributions Table (details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012
Distributions Made to Members or Limited Partners [Abstract]
Total Quarterly Distribution per Unit	$ 0.580	[1]	$ 0.560	$ 0.540	$ 0.500	$ 0.480	$ 0.460
Total Quarterly Cash Distribution	$ 83,986	[1]	$ 79,315	$ 70,143	$ 56,346	$ 52,425	$ 46,053

[1] On October 16, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.58 per unit, or $84.0 million in aggregate, including incentive distributions. The cash distribution is payable on November 12, 2013, to unitholders of record at the close of business on October 31, 2013.

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Acquisitions (tables)

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

Acquisitions Table

The following table presents the acquisitions completed by the Partnership during 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
MGR (1)	01/13/2012	100	%	$	299,000	$	159,587	632,783	12,914
Chipeta (2)	08/01/2012	24	%	—		128,250		151,235	3,086
Non-Operated Marcellus Interest(3)	03/01/2013	33.75	%	250,000		215,500		449,129	—
Anadarko-Operated Marcellus Interest(4)	03/08/2013	33.75	%	133,500		—		—	—
Mont Belvieu JV(5)	06/05/2013	25	%	—		78,129		—	—
OTTCO(6)	09/03/2013	100	%	27,500		—		—	—

⁽¹⁾  The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”

⁽²⁾  The Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (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.

⁽³⁾  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. See Non-Operated Marcellus Interest acquisition below for further information.

⁽⁴⁾  The interest acquired from a third party consisted of 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. 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 as of September 30, 2013.

⁽⁵⁾  The acquisition from a third party consisted of a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. 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.

⁽⁶⁾  The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline which connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming. The assets acquired are referred to as the “OTTCO pipeline” and the acquisition as the “OTTCO acquisition.”

Impact to Historical Consolidated Statement of Income Table

The following table presents the revenue and net income impact of the Non-Operated Marcellus Interest on revenue and net income as presented in the Partnership’s historical consolidated statements of income:

	Three Months Ended September 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	219,020	$	15,714	$	234,734
Net income	42,940		7,062		50,002

	Nine Months Ended September 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	636,603	$	43,117	$	679,720
Net income	135,913		19,582		155,495

Purchase Price Allocation Table

The following is the final allocation of the purchase price as of September 30, 2013, 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 the pro forma condensed financial information of the Partnership as if the Anadarko-Operated Marcellus Interest acquisition had occurred on January 1, 2012:

	Nine Months Ended   September 30,
thousands except per-unit amounts	2013		2012
Revenues	$	764,128	$	682,820
Net income	196,872		153,423
Net income attributable to Western Gas Partners, LP	189,405		141,467
Net income per common unit - basic and diluted	$	1.26	$	1.12

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Debt and Interest Expense

9 Months Ended

Sep. 30, 2013

Debt Instruments [Abstract]

Debt and Interest Expense

8. DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt as of September 30, 2013, and December 31, 2012:

	September 30, 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	$	673,363	$	651,580	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021	500,000		495,042		531,210		500,000		494,661		499,946
Revolving credit facility	100,000		100,000		100,000		—		—		—
2.600% Senior Notes due 2018	250,000		249,705		249,134		—		—		—
Total debt outstanding	$	1,520,000	$	1,518,110	$	1,531,924	$	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 nine months ended September 30, 2013:

thousands	Carrying Value
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings	595,000
Repayments of revolving credit facility	(495,000		)
Issuance of 2.600% Senior Notes due 2018	250,000
Other	(168		)
Balance as of September 30, 2013	$	1,518,110

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 will be paid semi-annually on February 15 and August 15 of each year, commencing on February 15, 2014. The 2018 Notes will mature on August 15, 2018, unless redeemed, in whole or in part, prior to maturity. 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”).

In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, the Partnership issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The 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”) at a price to the public of 98.778% of the face amount.

At September 30, 2013, the Partnership was in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes and the 2018 Notes.

8. DEBT AND INTEREST EXPENSE (CONTINUED)

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.

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. At September 30, 2013, and December 31, 2012, the interest rate on the RCF was 1.68% 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 September 30, 2013, and December 31, 2012.

At September 30, 2013, the Partnership had $100.0 million of outstanding borrowings, $12.8 million in outstanding letters of credit issued and $687.2 million available for borrowing under the RCF. At September 30, 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, and as of December 31, 2012, the Partnership’s general partner was indemnified by a wholly owned subsidiary of Anadarko, Western Gas Resources, Inc. (“WGRI”), against any claims made against the general partner under the 2022 Notes, the 2021 Notes and/or the RCF.

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. As of September 30, 2013, the 2013 Indemnification Agreement applied to the $250.0 million of 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.

8. DEBT AND INTEREST EXPENSE (CONTINUED)

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Third parties
Interest expense on long-term debt	$	14,994		$	11,919		$	43,783		$	28,036
Amortization of debt issuance costs and commitment fees (1)	1,135			1,201			3,252			3,225
Capitalized interest	(3,111		)	(2,224		)	(9,552		)	(3,827		)
Total interest expense – third parties	13,018			10,896			37,483			27,434
Affiliates
Interest expense on note payable to Anadarko (2)	—			—			—			2,440
Interest expense on affiliate balances (3)	—			81			—			244
Total interest expense – affiliates	—			81			—			2,684
Interest expense	$	13,018		$	10,977		$	37,483		$	30,118

⁽¹⁾  For the three and nine months ended September 30, 2013, includes $0.3 million and $0.8 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 2018 Notes and (iii) underwriters’ fees. For the three and nine months ended September 30, 2012, includes $0.4 million and $0.8 million, respectively, of amortization of the original issue discount and underwriters’ fees for the 2022 Notes issued in June 2012 and the 2021 Notes.

⁽²⁾  In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 8.

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

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Transactions With Affiliates (tables)

9 Months Ended

Sep. 30, 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 September 30, 2013:

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

Gains (Losses) on Commodity Price Swap Agreements Table

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
thousands	2013			2012			2013			2012
Gains (losses) on commodity price swap agreements related to sales: (1)
Natural gas sales	$	6,923		$	9,132		$	14,707		$	30,728
Natural gas liquids sales	27,541			25,986			83,049			46,020
Total	34,464			35,118			97,756			76,748
Losses on commodity price swap agreements related to purchases (2)	(23,902		)	(25,803		)	(66,613		)	(70,342		)
Net gains (losses) on commodity price swap agreements	$	10,562		$	9,315		$	31,143		$	6,406

⁽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.

Equipment Purchase and Sale

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

	Nine Months Ended September 30,
	2013		2012		2013		2012
thousands	Purchases				Sales
Consideration (1)	$	6,167	$	18,946	$	82	$	760
Net carrying value	2,039		6,765		34		392
Partners’ capital adjustment	$	4,128	$	12,181	$	48	$	368

⁽¹⁾ Includes a payable of $1.8 million for pipe and equipment purchased in September 2013.

Summary of Affiliate Transactions Table

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

	Three Months Ended   September 30,				Nine Months Ended   September 30,
thousands	2013		2012		2013		2012
Revenues (1)	$	217,624	$	180,605	$	603,214	$	519,460
Cost of product (1)	33,753		42,839		97,801		115,603
Operation and maintenance (2)	13,469		12,638		41,021		38,040
General and administrative (3)	5,867		14,227		17,325		30,811
Operating expenses	53,089		69,704		156,147		184,454
Interest income, net (4)	4,225		4,225		12,675		12,675
Interest expense (5)	—		81		—		2,684
Distributions to unitholders (6)	44,378		25,852		121,493		69,615
Contributions from noncontrolling interest owners (7)	—		2,148		—		12,588
Distributions to noncontrolling interest owners (7)	—		1,464		—		6,528

⁽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 Equity incentive plan and Anadarko incentive plans within this Note 5).

⁽⁴⁾  Represents interest income recognized on the note receivable from Anadarko.

⁽⁵⁾  For the three and nine months ended September 30, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 8) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. 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 and Lancaster plants in the fourth quarter of 2012. See Note receivable from and amounts payable to Anadarko within this Note 5.

⁽⁶⁾  Represents distributions paid under the partnership agreement.

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

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Partnership Distributions (tables)

9 Months Ended

Sep. 30, 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
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
2013
March 31	$	0.540	$	70,143	May 2013
June 30	$	0.560	$	79,315	August 2013
September 30(1)	$	0.580	$	83,986	November 2013

⁽¹⁾  On October 16, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.58 per unit, or $84.0 million in aggregate, including incentive distributions. The cash distribution is payable on November 12, 2013, to unitholders of record at the close of business on October 31, 2013.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 04, 2013
Document And Entity Information [Abstract]
Entity Registrant Name	WESTERN GAS PARTNERS LP
Entity Central Index Key	0001414475
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		112,380,764

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Equity and Partners' Capital (tables)

9 Months Ended

Sep. 30, 2013

Partners' Capital Notes [Abstract]

Equity Offerings Table

The Partnership completed the following public offerings of its common units during 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
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

⁽¹⁾  Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

⁽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 nine months ended September 30, 2013:

	Common Units	General Partner Units	Total
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	6,879	140	7,019
May 2013 equity offering	7,015,000	143,163	7,158,163
Continuous Offering Program	43,350	174	43,524
Balance at September 30, 2013	112,174,911	2,288,573	114,463,484