Edgar Filing: Western Gas Partners LP

thousands

Property, plant and equipment

135,587

Asset retirement obligations

Total purchase price

135,413

Form 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 March 31, 2013

¨	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 105,109,682 common units outstanding as of April 26, 2013.

TABLE OF CONTENTS


PART I		FINANCIAL INFORMATION	PAGE

	Item 1.	Financial Statements

		Consolidated Statements of Income for the three months ended March 31, 2013 and 2012	4

		Consolidated Balance Sheets as of March 31, 2013, and December 31, 2012	5

		Consolidated Statement of Equity and Partners’ Capital for the three months ended March 31, 2013	6

		Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	7

		Notes to Consolidated Financial Statements	8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

		Cautionary Note Regarding Forward-Looking Statements	21

		Executive Summary	23

		Acquisitions	24

		Equity Offerings	25

		Results of Operations	26

		Operating Results	26

		Key Performance Metrics	31

		Liquidity and Capital Resources	34

		Contractual Obligations	39

		Off-Balance Sheet Arrangements	39

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40

	Item 4.	Controls and Procedures	41

PART II		OTHER INFORMATION

	Item 1.	Legal Proceedings	41

	Item 1A.	Risk Factors	41

	Item 6.	Exhibits	42

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 fractionation 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)


	Three Months Ended March 31,
thousands except per-unit and unit amounts	2013		2012 ⁽¹⁾
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	65,899	$	61,119
Natural gas, natural gas liquids and condensate sales		111,670		105,653
Equity income and other, net		3,981		4,001

Total revenues – affiliates		181,550		170,773
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		36,991		30,470
Natural gas, natural gas liquids and condensate sales		10,059		22,833
Other, net		1,147		600

Total revenues – third parties		48,197		53,903

Total revenues		229,747		224,676

Operating expenses
Cost of product ⁽²⁾		83,083		83,156
Operation and maintenance ⁽²⁾		36,739		32,121
General and administrative ⁽²⁾		7,664		10,274
Property and other taxes		5,785		4,837
Depreciation, amortization and impairments		32,440		27,067

Total operating expenses		165,711		157,455

Operating income		64,036		67,221
Interest income, net – affiliates		4,225		4,225
Interest expense ⁽³⁾		(11,811)		(9,581)
Other income (expense), net		674		458

Income before income taxes		57,124		62,323
Income tax expense		4,236		4,429

Net income		52,888		57,894
Net income attributable to noncontrolling interests		2,231		4,243

Net income attributable to Western Gas Partners, LP	$	50,657	$	53,651

Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	50,657	$	53,651
Pre-acquisition net (income) loss allocated to Anadarko		(5,401)		(5,488)
General partner interest in net (income) loss ⁽⁴⁾		(12,886)		(4,339)

Limited partners’ interest in net income ⁽⁴⁾	$	32,370	$	43,824
Net income per common unit – basic and diluted	$	0.31	$	0.48
Weighted average common units outstanding – basic and diluted		104,815		90,690

⁽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 $31.9 million and $33.4 million for the three months ended March 31, 2013 and 2012, respectively. Operation and maintenance includes charges from Anadarko of $13.4 million and $12.5 million for the three months ended March 31, 2013 and 2012, respectively. General and administrative includes charges from Anadarko of $5.9 million and $8.8 million for the three months ended March 31, 2013 and 2012, respectively. See Note 5.

⁽³⁾	Includes affiliate (as defined in Note 1) interest expense of zero and $1.3 million for the three months ended March 31, 2013 and 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.

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


thousands except number of units	March 31, 2013		December 31, 2012 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	63,516	$	419,981
Accounts receivable, net ⁽²⁾		28,507		50,233
Other current assets ⁽³⁾		8,490		6,998

Total current assets		100,513		477,212
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		3,733,690		3,432,392
Less accumulated depreciation		745,477		714,436

Net property, plant and equipment		2,988,213		2,717,956
Goodwill		105,336		105,336
Other intangible assets		55,159		55,490
Equity investments		109,940		106,130
Other assets		27,245		27,798

Total assets	$	3,646,406	$	3,749,922

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables ⁽⁴⁾	$	35,999	$	25,154
Accrued ad valorem taxes		17,727		11,949
Income taxes payable		630		552
Accrued liabilities ⁽⁵⁾		147,460		147,651

Total current liabilities		201,816		185,306
Long-term debt – third parties		1,553,319		1,168,278
Deferred income taxes		1,748		47,153
Asset retirement obligations and other		71,096		68,749

Total long-term liabilities		1,626,163		1,284,180

Total liabilities		1,827,979		1,469,486
Equity and partners’ capital
Common units (105,109,682 and 104,660,553 units issued and outstanding at March 31, 2013 and December 31, 2012, respectively)		1,692,173		1,957,066
General partner units (2,145,096 and 2,135,930 units issued and outstanding at March 31, 2013 and December 31, 2012, respectively)		54,918		52,752
Net investment by Anadarko		—		199,960

Total partners’ capital		1,747,091		2,209,778
Noncontrolling interests		71,336		70,658

Total equity and partners’ capital		1,818,427		2,280,436

Total liabilities, equity and partners’ capital	$	3,646,406	$	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 zero and $19.1 million as of March 31, 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 March 31, 2013 and December 31, 2012, respectively.

⁽⁴⁾	Accounts and natural gas imbalance payables includes amounts payable to affiliates of $6.2 million and $2.5 million as of March 31, 2013 and December 31, 2012, respectively.

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

See accompanying Notes to Consolidated Financial Statements.

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		5,401		32,370		12,886		2,231		52,888
Issuance of common and general partner units, net of offering expenses		—		—		500		—		500
Contributions from noncontrolling interest owners		—		—		—		1,097		1,097
Distributions to noncontrolling interest owners		—		—		—		(2,650)		(2,650)
Distributions to unitholders		—		(54,423)		(11,234)		—		(65,657)
Acquisition from affiliates		(221,930)		(243,570)		—		—		(465,500)
Contributions of equity-based compensation from Anadarko		—		660		14		—		674
Net pre-acquisition contributions from (distributions to) Anadarko		(29,961)		1		—		—		(29,960)
Elimination of net deferred tax liabilities		46,530		—		—		—		46,530
Other		—		69		—		—		69

Balance at March 31, 2013	$	—	$	1,692,173	$	54,918	$	71,336	$	1,818,427

⁽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.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Three Months Ended March 31,
thousands	2013		2012 ⁽¹⁾
Cash flows from operating activities
Net income	$	52,888	$	57,894
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		32,440		27,067
Non-cash equity-based compensation expense		804		914
Deferred income taxes		1,124		12,212
Debt-related amortization and other items, net		560		511
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		21,661		32,704
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net		21,287		(13,665)
Change in other items, net		(809)		1,083

Net cash provided by operating activities		129,955		118,720
Cash flows from investing activities
Capital expenditures		(166,463)		(75,837)
Acquisitions from affiliates		(465,721)		(463,232)
Acquisitions from third parties		(134,869)		—
Investments in equity affiliates		(4,835)		—

Net cash used in investing activities		(771,888)		(539,069)
Cash flows from financing activities
Borrowings, net of debt issuance costs		384,946		319,000
Repayments of debt		—		(40,000)
Increase (decrease) in outstanding checks		(2,808)		4,919
Proceeds from issuance of common and general partner units, net of offering expenses		500		—
Distributions to unitholders		(65,657)		(43,027)
Contributions from noncontrolling interest owners		1,097		9,849
Distributions to noncontrolling interest owners		(2,650)		(5,145)
Net contributions from (distributions to) Anadarko		(29,960)		(12,188)

Net cash provided by financing activities		285,468		233,408

Net increase (decrease) in cash and cash equivalents		(356,465)		(186,941)
Cash and cash equivalents at beginning of period		419,981		226,559

Cash and cash equivalents at end of period	$	63,516	$	39,618


Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets	$	(6)	$	3,000
Interest paid, net of capitalized interest	$	11,244	$	1,986
Taxes paid	$	—	$	72

⁽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.

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, Note 4 and Note 5). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”). “Equity investment throughput” refers to the Partnership’s 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as third-party producers and customers. As of March 31, 2013, the Partnership’s assets included ownership and operation of twelve gathering systems, seven natural gas treating facilities, seven natural gas processing facilities, one NGL pipeline, one interstate natural gas pipeline, one intrastate natural gas pipeline. In addition, the Partnership had interests in five non-operated gathering systems, three operated processing systems, one operated gathering system, and one NGL pipeline, with separate interests in Fort Union, White Cliffs and Rendezvous accounted for under the equity method. These assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming), north-central Pennsylvania, and the Mid-Continent (Kansas and Oklahoma). The Partnership also had facilities under construction in South Texas and Northeast Colorado at the end of the first quarter of 2013.

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

In December 2012, WGP completed its IPO of 19,758,150 common units representing limited partner interests in WGP 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 for general partnership purposes, including the funding of capital expenditures.

Basis of presentation. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). 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 non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 33.75% share of the assets, liabilities, revenues and expenses attributable to the Non-Operated Marcellus Interest and Anadarko-Operated Marcellus Interest (see Note 2) and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system in the accompanying consolidated financial statements.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

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 revision 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 three months ended March 31, 2012, operating cash inflows and investing cash outflows in the Partnership’s unaudited consolidated statements of cash flows include a reduction of $14.0 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 three months ended March 31, 2012, and has corrected the error within the unaudited statement of cash flows for the three months ended March 31, 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. 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 (the “Chipeta LLC agreement”). On August 1, 2012, the Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (the “additional Chipeta interest”). Prior to this transaction, the interests in Chipeta held by Anadarko and a third-party member were reflected as noncontrolling interests in the consolidated financial statements. The acquisition of Anadarko’s then remaining 24% interest was accounted for on a prospective basis as the Partnership acquired an additional interest in an already-consolidated entity. As such, effective August 1, 2012, 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 March 31, 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS

The following table presents the acquisitions completed by the Partnership during 2013 and 2012, 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⁾		01/13/12		100%	$	299,000	$	159,587		632,783		12,914
Chipeta ⁽²⁾		08/01/12		24%		—		128,250		151,235		3,086
Non-Operated Marcellus Interest⁽³⁾		03/01/13		33.75%		250,000		215,500		449,129		—
Anadarko-Operated Marcellus Interest⁽⁴⁾		03/08/13		33.75%		133,500		1,369		—		—

⁽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 issued 9,166 general partner units to the general partner for consideration of $0.5 million in order to maintain its 2.0% general partner interest in the Partnership.

⁽⁴⁾

The interest acquired from a third party includes 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 further information below, including the preliminary allocation of the purchase price as of March 31, 2013.

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS (CONTINUED)

The following table presents the impact to the historical consolidated statements of income attributable to the Non-Operated Marcellus Interest, including the elimination of intercompany activity between such assets:


	Three Months Ended March 31, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined

Revenues	$	212,242	$	12,434	$	224,676
Net income		52,406		5,488		57,894

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 a preliminary allocation of the purchase price as of March 31, 2013, including $0.5 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:

The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition. The fair values of the interests in the land, right-of-way contracts, and gathering systems were based on the market and income approaches. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The current purchase price allocation is preliminary and is subject to change pending post-closing purchase price adjustments; finalization of fair value estimates; and completion of evaluations of property, plant and equipment, asset retirement obligations, contractual arrangements and legal and environmental matters as additional information becomes available and is assessed by the Partnership.

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


	Three Months Ended March 31,
thousands except per unit amount	2013		2012
Revenues	$	231,001	$	225,453
Net income		53,032		56,880
Net income attributable to Western Gas Partners, LP		50,801		52,637
Net income per common unit - basic and diluted	$	0.32	$	0.47

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS (CONTINUED)

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 $0.7 million of revenues and $0.1 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 three months ended March 31, 2013. The pro forma adjustments reflect pre-acquisition results of the Anadarko-Operated Marcellus Interest including (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the purchase price allocated to property, plant and equipment and estimated useful lives; and (c) interest on the Partnership’s borrowings under its revolving credit facility to finance the Anadarko-Operated Marcellus Interest acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the Anadarko-Operated Marcellus Interest acquisition, nor any future acquisition related expenses.

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 its unitholders for the periods presented:


	Total Quarterly
thousands except per-unit amounts	Distribution	Total Cash	Date of
Quarters Ended	per Unit	Distribution	Distribution
March 31, 2012	$ 0.460	$ 46,053	May 2012
March 31, 2013 ⁽¹⁾	$ 0.540	$ 70,143	May 2013

⁽¹⁾

On April 17, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.54 per unit, or $70.1 million in aggregate, including incentive distributions. The cash distribution is payable on May 13, 2013, to unitholders of record at the close of business on April 30, 2013.

4. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. In June 2012, the Partnership closed a public offering of 5,000,000 common units at a price of $43.88 per unit. In connection with this offering, the Partnership issued 102,041 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds from the offering of $216.4 million were used for general partnership purposes, including the funding of capital expenditures.

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 three months ended March 31, 2013:

Common

General

Units

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

Balance at March 31, 2013

105,109,682

2,145,096

107,254,778

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Holdings of Partnership equity. As of March 31, 2013, WGP held 49,296,205 common units, representing a 46.0% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,145,096 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the Partnership’s IDRs. Also as of March 31, 2013, Anadarko Marcellus Midstream, L.L.C. (“AMM”), a subsidiary of Anadarko, held 449,129 common units, representing a 0.4% limited partner interest in the Partnership. As of March 31, 2013, the public held 55,364,348 common units, representing a 51.6% limited partner interest in the Partnership.

The Partnership’s net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 2) is allocated to the general partner and the limited partners consistent with actual cash distributions, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner and the limited partners in accordance with their respective ownership percentages.

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.

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

Note receivable from and amounts payable to Anadarko. 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 $326.0 million and $334.8 million at March 31, 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

In 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko, which was repaid in full in June 2012 using the proceeds from the issuance of 4.000% Senior Notes due 2022. See Note 8.

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

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the commodity price swap agreements are not specifically defined; instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold at the Granger, Hilight, Hugoton, Newcastle, MGR and Wattenberg assets, with various expiration dates through December 2016. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. The Partnership has not entered into any new commodity price swap agreements since the fourth quarter of 2011.

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of March 31, 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 March 31,
thousands	2013		2012
Gains (losses) on commodity price swap agreements related to sales: ⁽¹⁾
Natural gas sales	$	5,380	$	9,850
Natural gas liquids sales		21,305		354

Total		26,685		10,204
Losses on commodity price swap agreements related to purchases⁽²⁾		(19,854)		(17,192)

Net gains (losses) on commodity price swap agreements	$	6,831	$	(6,988)

⁽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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Gas gathering and processing agreements. The Partnership has significant gas gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. Approximately 60% and 66% of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended March 31, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 55% and 57% of the Partnership’s processing throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended March 31, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko.

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


	Three Months Ended March 31,
	Purchases
thousands	2013		2012
Cash consideration	$	221	$	4,468
Net carrying value		227		571

Partners’ capital adjustment	$	(6)	$	3,897

Long-term incentive plan. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”), primarily to the Chief Executive Officer and its independent directors. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized over the vesting period and was approximately $0.1 million for the three months ended March 31, 2013 and 2012.

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”).

For the three months ended March 31, 2013, and 2012, the Partnership’s general and administrative expenses include $0.7 million and $0.8 million, respectively, of equity-based compensation expense for awards granted to the executive officers of the general partner and other employees under the Anadarko Incentive Plans, which was allocated to the Partnership by Anadarko.

For the three months ended March 31, 2012, the Partnership’s general and administrative expenses include $3.3 million 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 March 31, 2012, were valued at $718.00 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.

Capital expenditures transfer. As described in Note receivable from and amounts payable to Anadarko within this Note 5, Anadarko incurred certain expenditures related to the construction of the Brasada and Lancaster gas processing facilities during 2011. These amounts, along with related capitalized interest, were transferred to the Partnership in the first quarter of 2012, and are included in the balance of property, plant and equipment as of March 31, 2013 and December 31, 2012. See Note 6.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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


	Three Months Ended March 31,
thousands	2013		2012
Revenues ⁽¹⁾	$	181,550	$	170,773
Cost of product ⁽¹⁾		31,929		33,426
Operation and maintenance ⁽²⁾		13,366		12,473
General and administrative ⁽³⁾		5,869		8,833

Operating expenses		51,164		54,732
Interest income, net ⁽⁴⁾		4,225		4,225
Interest expense ⁽⁵⁾		—		1,315
Distributions to unitholders ⁽⁶⁾		36,868		20,872
Contributions from noncontrolling interest owners ⁽⁷⁾		—		4,824
Distributions to noncontrolling interest owners ⁽⁷⁾		—		2,520

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

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

⁽³⁾

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

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

⁽⁵⁾

Represents interest expense recognized on the note payable to Anadarko (see Note 8) and, for the three months ended March 31, 2012, 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. In the fourth quarter of 2012, the Partnership repaid the note payable to Anadarko and the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants. See Note receivable from and amounts payable to Anadarko within this Note 5.

⁽⁶⁾	Represents distributions paid under the partnership agreement.

⁽⁷⁾

As described in Note 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.

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

March 31, 2013

December 31, 2012

Land

n/a

501

501

Gathering systems

3 to 47 years

3,158,042

2,911,572

Pipelines and equipment

15 to 45 years

91,542

91,126

Assets under construction

n/a

472,227

422,002

Other

3 to 25 years

11,378

7,191

Total property, plant and equipment

3,733,690

3,432,392

Accumulated depreciation

745,477

714,436

Net property, plant and equipment

2,988,213

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.

7. COMPONENTS OF WORKING CAPITAL

A summary of other current assets is as follows:


thousands	March 31, 2013		December 31, 2012
Natural gas liquids inventory	$	3,088	$	1,678
Natural gas imbalance receivables		2,569		1,663
Prepaid insurance		1,106		1,897
Other		1,727		1,760

Total other current assets	$	8,490	$	6,998

A summary of accrued liabilities is as follows:


thousands	March 31, 2013		December 31, 2012
Accrued capital expenditures	$	109,512	$	112,311
Accrued plant purchases		18,762		16,350
Accrued interest expense		15,875		15,868
Short-term asset retirement obligations		1,854		1,711
Short-term remediation and reclamation obligations		712		799
Other		745		612

Total accrued liabilities	$	147,460	$	147,651

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 March 31, 2013 and December 31, 2012:


	March 31, 2013						December 31, 2012
thousands	Principal		Carrying Value		Fair Value⁽¹⁾		Principal		Carrying Value		Fair Value⁽¹⁾
4.000% Senior Notes due 2022	$	670,000	$	673,533	$	669,933	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021		500,000		494,786		499,950		500,000		494,661		499,946
Revolving credit facility		385,000		385,000		385,000		—		—		—

Total debt outstanding	$	1,555,000	$	1,553,319	$	1,554,883	$	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 three months ended March 31, 2013:


thousands	Carrying Value
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings		385,000
Other and changes in debt discount or premium		41

Balance as of March 31, 2013	$	1,553,319

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

In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) at a price to the public of 98.778% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%.

At March 31, 2013, the Partnership was in compliance with all covenants under the indentures.

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

Revolving credit facility. In March 2011, the Partnership entered into an amended and restated $800.0 million senior unsecured RCF. The RCF matures in March 2016 and bears interest at London Interbank Offered Rate (“LIBOR”) plus applicable margins currently ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, in each case plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.70% and 1.71% at March 31, 2013 and December 31, 2012, 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 March 31, 2013 and December 31, 2012.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE (CONTINUED)

On June 13, 2012, following the receipt of a second investment grade rating as defined in the RCF, the Partnership is no longer subject to certain of the restrictive covenants associated with the RCF. As of March 31, 2013, the Partnership had $385.0 million of outstanding borrowings and $12.8 million in outstanding letters of credit issued under its $800.0 million RCF. At March 31, 2013, the Partnership was in compliance with all remaining covenants under the RCF.

The 2022 Notes, the 2021 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, the general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary has agreed to indemnify the Partnership’s general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. The 2013 Indemnification Agreement applies to such debt financings up to $385.0 million. 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.

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


	Three Months Ended March 31,
thousands	2013			2012
Third parties
Interest expense on long-term debt	$	13,939		$	7,915
Amortization of debt issuance costs and commitment fees⁽¹⁾		1,053			1,008
Capitalized interest⁽²⁾		(3,181	)		(657	)

Total interest expense – third parties		11,811			8,266

Affiliates
Interest expense on note payable to Anadarko⁽³⁾		—			1,234
Interest expense on affiliate balances⁽⁴⁾		—			81

Total interest expense – affiliates		—			1,315

Interest expense	$	11,811		$	9,581

⁽¹⁾

For the three months ended March 31, 2013, includes $0.3 million of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters’ fees. For the three months ended March 31, 2012, includes $0.2 million of amortization of the original issue discount and underwriters’ fees for the 2021 Notes.

⁽²⁾

For the three months ended March 31, 2013 and 2012, includes zero and $0.6 million, respectively, of capitalized interest associated with capital projects at Chipeta and $3.0 million and $0.1 million, respectively, of capitalized interest associated with the construction of the Brasada and Lancaster gas processing facilities. See Note 5.

⁽³⁾	In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 8.

⁽⁴⁾

Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada and Lancaster plants. In the fourth quarter of 2012, the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants was repaid. See Note 5.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

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 March 31, 2013, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of approximately $60.3 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 Brasada and Lancaster plants (see Note 5) and include 100% of obligations related to Chipeta, in which the Partnership has a 75% membership interest (see Note 1).

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations. The leases for the corporate offices and shared field offices extend through 2017 and 2018, respectively, and the lease for the warehouse extends through February 2014 and includes an early termination clause.

Rent expense associated with the office, warehouse and equipment leases was $0.7 million for both the three months ended March 31, 2013 and 2012.

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, which are included in Part I, Item 8 of our 2012 Form 10-K as filed with the Securities and Exchange Commission, or “SEC,” on February 28, 2013, and other public filings and press releases by Western Gas Partners, LP. 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”), and Rendezvous Gas Services, LLC (“Rendezvous”). “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;

•

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

•

changes in environmental and safety regulation; 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 between 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;

•

the 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.

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 March 31, 2013, our owned and operated assets consisted of twelve gathering systems, seven natural gas treating facilities, seven natural gas processing facilities, one NGL pipeline, one interstate natural gas pipeline, one intrastate natural gas pipeline. In addition, we had interests in five non-operated gathering systems, three operated processing systems, one operated gathering system, and one NGL pipeline, with separate interests accounted for under the equity method in two gas gathering systems and a crude oil pipeline.

Significant financial highlights during the first three months of 2013 include the following:

•

We completed the acquisition of Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems in north-central Pennsylvania. We also completed the acquisition of a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems from a third party, also in north-central Pennsylvania. See Acquisitions below.

•

We raised our distribution to $0.54 per unit for the first quarter of 2013, representing a 4% increase over the distribution for the fourth quarter of 2012, a 17% increase over the distribution for the first quarter of 2012, and our sixteenth consecutive quarterly increase.

Significant operational highlights during the first three months of 2013 include the following:

•

Throughput attributable to Western Gas Partners, LP totaled 2,906 MMcf/d for the three months ended March 31, 2013, representing a 7% increase compared to the three months ended March 31, 2012.

•

Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.55 per Mcf for both the three months ended March 31, 2013 and 2012.

ACQUISITIONS

Acquisitions. The following table presents our acquisitions during 2013 and 2012, 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⁾		01/13/12		100%	$	299,000	$	159,587		632,783		12,914
Chipeta ⁽²⁾		08/01/12		24%		—		128,250		151,235		3,086
Non-Operated Marcellus Interest⁽³⁾		03/01/13		33.75%		250,000		215,500		449,129		—
Anadarko-Operated Marcellus Interest⁽⁴⁾		03/08/13		33.75%		133,500		1,369		—		—

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

⁽²⁾

We acquired Anadarko’s then remaining 24% membership interest in Chipeta (as described in Note 1—Summary of Significant Accounting Policies 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, we issued 9,166 general partner units to the general partner 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 includes 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.

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by us, as of March 31, 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

Public equity offering. In June 2012, we completed a public offering of 5,000,000 common units representing limited partner interests in us, and issued 102,041 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. The price per unit was $43.88, generating proceeds of $216.4 million (net of $7.4 million for the underwriting discount and other offering expenses), including the general partner’s proportionate capital contribution. The net proceeds were used for general partnership purposes, including the funding of capital expenditures.

Other equity offerings. In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to $125.0 million of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of March 31, 2013, we had not issued any common units under this registration statement.

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 the 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. The net proceeds from this offering were used for general partnership purposes, including the funding of capital expenditures.

RESULTS OF OPERATIONS

OPERATING RESULTS

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


	Three Months Ended
	March 31,
thousands	2013		2012
Gathering, processing and transportation of natural gas and natural gas liquids	$	102,890	$	91,589
Natural gas, natural gas liquids and condensate sales		121,729		128,486
Equity income and other, net		5,128		4,601

Total revenues ⁽¹⁾		229,747		224,676
Total operating expenses ⁽¹⁾		165,711		157,455

Operating income		64,036		67,221
Interest income, net – affiliates		4,225		4,225
Interest expense		(11,811)		(9,581)
Other income (expense), net		674		458

Income before income taxes		57,124		62,323
Income tax expense		4,236		4,429

Net income		52,888		57,894
Net income attributable to noncontrolling interests		2,231		4,243

Net income attributable to Western Gas Partners, LP	$	50,657	$	53,651

Key performance metrics ⁽²⁾
Gross margin	$	146,664	$	141,520
Adjusted EBITDA attributable to Western Gas Partners, LP	$	95,929	$	94,680
Distributable cash flow	$	79,130	$	82,361

⁽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 March 31, 2013” refer to the comparison of the three months ended March 31, 2013, to the three months ended March 31, 2012.

Operating Statistics


	Three Months Ended March 31,
throughput in MMcf/d	2013		2012		D
Gathering, treating and transportation ⁽¹⁾		1,627		1,606		1%
Processing ⁽²⁾		1,233		1,150		7%
Equity investment ⁽³⁾		201		236		(15)%

Total throughput ⁽⁴⁾		3,061		2,992		2%
Throughput attributable to noncontrolling interests		155		270		(43)%

Total throughput attributable to Western Gas Partners, LP		2,906		2,722		7%

⁽¹⁾	Excludes average NGL pipeline volumes of 20 MBbls/d and 27 MBbls/d for the three months ended March 31, 2013 and 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 of 7 MBbls/d and 5 MBbls/d for the three months ended March 31, 2013 and 2012, respectively.

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

Gathering, treating and transportation throughput increased by 21 MMcf/d for the three months ended March 31, 2013, due to increased drilling behind the Non-Operated Marcellus Interest and the Wattenberg system. These increases were partially offset by decreases at the Haley, Pinnacle and Dew systems resulting from natural production declines in those areas; throughput decreases at MIGC due to the expiration of a firm transportation agreement in 2012; and throughput decreases at the Bison facility resulting from reduced drilling activity in the area.

Processing throughput increased by 83 MMcf/d for the three months ended March 31, 2013, primarily due to throughput increases at the Chipeta system resulting from increased drilling activity in the area, plus the completion of a pipeline connection which allowed additional throughput to flow into the plant.

Equity investment volumes decreased by 35 MMcf/d for the three months ended March 31, 2013, resulting from lower throughput at the Fort Union and Rendezvous systems due to production declines and decreased drilling activity in those areas.

Natural Gas Gathering, Processing and Transportation Revenues

Three Months Ended
March 31,

thousands except percentages

2013

2012

Gathering, processing and transportation of natural gas and natural gas liquids

102,890

91,589

12%

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $11.3 million for the three months ended March 31, 2013, primarily due to increases of $6.3 million and $3.3 million at the Non-Operated Marcellus Interest and the Chipeta system, respectively, both due to increased volumes, and increases of $3.5 million and $1.5 million at the Wattenberg and Platte Valley systems, respectively, due to increased gathering rates and volumes. These increases were partially offset by decreased revenue of $1.1 million at the Helper system due to a downward rate revision effective April 1, 2012, decreased revenue of $1.6 million due to decreased volumes at the Pinnacle, Dew, Haley and Hugoton systems as a result of natural production declines in the area, and decreased revenue of $0.7 million at MIGC due to the expiration of a firm transportation agreement in 2012.

Natural Gas, Natural Gas Liquids and Condensate Sales


thousands except percentages and per-unit amounts	Three Months Ended March 31,
thousands except percentages and per-unit amounts	2013		2012		D
Natural gas sales	$	25,517	$	25,558		—%
Natural gas liquids sales		87,217		93,642		(7)%
Drip condensate sales		8,995		9,286		(3)%

Total	$	121,729	$	128,486		(5)%

Average price per unit:
Natural gas (per Mcf)	$	4.21	$	4.30		(2)%
Natural gas liquids (per Bbl)	$	47.04	$	47.88		(2)%
Drip condensate (per Bbl)	$	74.56	$	76.09		(2)%

For the three months ended March 31, 2013, including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales decreased by $6.8 million, which consisted primarily of a $6.4 million decrease in NGLs sales and a $0.3 million decrease in drip condensate sales.

The decline in NGLs sales was primarily due to decreases of $5.2 million and $1.0 million at the Granger and Wattenberg systems, respectively, due to lower volumes sold.

The decline in drip condensate sales for the three months ended March 31, 2013, was primarily due to a $0.3 million decrease at the Wattenberg system and a $0.4 million decrease at the Hugoton and Haley systems, all as a result of lower condensate volumes sold. These decreases were partially offset by a $0.4 million increase at the Platte Valley system as a result of higher condensate volumes sold.

For the three months ended March 31, 2013 and 2012, average natural gas, NGL and drip condensate prices include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Newcastle, Hugoton and Wattenberg systems, and the MGR assets. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Equity Income and Other Revenues


	Three Months Ended March 31,
thousands except percentages	2013		2012		D
Equity income	$	3,980	$	3,613		10%
Other revenues, net		1,148		988		16%

Total	$	5,128	$	4,601		11%

Equity income increased by $0.4 million for the three months ended March 31, 2013, primarily due to an $0.8 million increase in income from White Cliffs as a result of increased volumes, partially offset by a $0.2 million decrease in income from Rendezvous and a $0.1 million decrease from Fort Union as a result of decreased volumes.

Other revenues, net increased by $0.2 million for the three months ended March 31, 2013, primarily due to changes in gas imbalance positions at the MIGC, Chipeta and Pinnacle systems.

Cost of Product and Operation and Maintenance Expenses


	Three Months Ended
	March 31,
thousands except percentages	2013		2012		D
Cost of product	$	83,083	$	83,156		—%
Operation and maintenance		36,739		32,121		14%

Total cost of product and operation and maintenance expenses	$	119,822	$	115,277		4%

Including the effects of commodity price swap agreements on purchases, cost of product expense decreased by $0.1 million for the three months ended March 31, 2013, primarily due to the following items:

• a $0.6 million net decrease in purchases of NGL volumes comprised of a decrease of $3.5 million at Chipeta (due to a combination of price decreases and volume increases), decreases of $1.7 million and $0.6 million at the Granger and Wattenberg systems, respectively (due to combinations of volume decreases partially offset by price increases), and increases of $3.7 million at the MGR assets and $0.9 million at the Platte Valley system (due to combinations of volume increases partially offset by price decreases);

• a $0.3 million net increase in purchases of residue volumes, comprised of increases of $1.8 million, $1.7 million, $0.4 million and $0.3 million at the MGR assets, the Platte Valley system, Chipeta and the Wattenberg system, respectively (due to a combination of price and volume increases), offset by a $2.1 million decrease in cost of product expense for residue purchases at the Granger system (due to a combination of volume decreases and price increases), and a $1.9 million decrease in cost of product expense for residue purchases at the Hilight system (due to a combination of price and volume decreases); and

• a $0.5 million net increase from other gathering purchases and changes in gas imbalance positions.

Cost of product expense for the three months ended March 31, 2013 and 2012, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and the MGR assets. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Operation and maintenance expense increased by $4.6 million for the three months ended March 31, 2013, primarily due to a $1.8 million increase in property, overhead and facility expense attributable to the Non-Operated Marcellus Interest, and a $2.7 million increase in contract labor expense, payroll taxes, electric expense and plant repairs, primarily at the Wattenberg and Hilight systems.

General and Administrative, Depreciation and Other Expenses


	Three Months Ended
	March 31,
thousands except percentages	2013		2012		D
General and administrative	$	7,664	$	10,274		(25)%
Property and other taxes		5,785		4,837		20%
Depreciation, amortization and impairments		32,440		27,067		20%

Total general and administrative, depreciation and other expenses	$	45,889	$	42,178		9%

General and administrative expenses decreased by $2.6 million for the three months ended March 31, 2013, due to a decrease of $3.3 million in non-cash compensation expenses primarily attributable to the awards outstanding under the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) at March 31, 2012, which were settled in December 2012 when the Incentive Plan terminated in conjunction with WGP’s IPO. The decrease was partially offset by a $0.4 million increase in consulting and audit fees and a $0.3 million increase in corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement.

Property and other taxes increased by $0.9 million for the three months ended March 31, 2013, primarily due to ad valorem tax increases at the Platte Valley system.

Depreciation, amortization and impairments increased by $5.4 million for the three months ended March 31, 2013, primarily attributable to $2.8 million of depreciation associated with capital projects completed at Wattenberg and Chipeta, a $1.2 million increase in depreciation associated with the Non-Operated Marcellus Interest acquisition and $0.4 million of depreciation for the Anadarko-Operated Marcellus Interest.

Interest Income, Net – Affiliates and Interest Expense


	Three Months Ended
	March 31,
thousands except percentages	2013		2012		D
Interest income on note receivable	$	4,225	$	4,225		—%

Interest income, net – affiliates	$	4,225	$	4,225		—%

Third parties
Interest expense on long-term debt	$	(13,939)	$	(7,915)		76%
Amortization of debt issuance costs and commitment fees⁽²⁾		(1,053)		(1,008)		4%
Capitalized interest⁽³⁾		3,181		657		nm⁽¹⁾
Affiliates
Interest expense on note payable to Anadarko⁽⁴⁾		—		(1,234)		(100)%
Interest expense, net on affiliate balances⁽⁵⁾		—		(81)		(100)%

Interest expense	$	(11,811)	$	(9,581)		23%

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

⁽²⁾

For the three months ended March 31, 2013, includes $0.3 million of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”), (ii) original issue discount for the $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) and (iii) underwriters’ fees. For the three months ended March 31, 2012, includes $0.2 million of amortization of the original issue discount and underwriters’ fees for the 2021 Notes.

⁽³⁾

⁽⁴⁾	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.

⁽⁵⁾

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, the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants was repaid. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Interest expense increased by $2.2 million for the three months ended March 31, 2013, primarily due to $6.7 million in interest expense incurred on the 2022 Notes, partially offset by an increase of $2.5 million of capitalized interest primarily associated with the construction of the Brasada and Lancaster plants, a decrease of $1.2 million in interest expense on the note payable to Anadarko, and a decrease of $0.7 million of interest expense on the RCF due to greater average outstanding borrowings in the prior period. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q).

Other Income (Expense), Net

Three Months Ended

March 31,

thousands except percentages

2013

2012

Other income (expense), net

674

458

47%

For the three months ended March 31, 2013 and 2012, other income (expense), net was primarily comprised of $0.4 million of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition. In addition, for the three months ended March 31, 2013, other income (expense), net included an increase of $0.2 million on interest earned on overnight investments.

Income Tax Expense


	Three Months Ended
	March 31,
thousands except percentages	2013		2012		D
Income before income taxes	$	57,124	$	62,323		(8)%
Income tax expense		4,236		4,429		(4)%
Effective tax rate		7%		7%

We are not a taxable entity for U.S. federal income tax purposes, although the portion of our income apportionable to Texas is subject to Texas margin tax. For the periods presented, our variance from the federal statutory rate, which is zero percent as a non-taxable entity, is primarily due to federal and state taxes on pre-acquisition income attributable to Partnership assets acquired from Anadarko and our share of Texas margin tax.

Income attributable to (a) the Non-Operated Marcellus Interest prior to and including March 2013 and (b) the MGR assets prior to and including January 2012 were 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 subject only to Texas margin tax on the portion of their incomes apportionable to Texas.

Noncontrolling Interests


	Three Months Ended
	March 31,
thousands except percentages	2013		2012		D
Net income attributable to noncontrolling interests	$	2,231	$	4,243	(47)%

For the three months ended March 31, 2013, net income attributable to noncontrolling interests decreased by $2.0 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.

KEY PERFORMANCE METRICS


	Three Months Ended
thousands except percentages and gross margin per Mcf	March 31,
thousands except percentages and gross margin per Mcf	2013		2012		D
Gross margin	$	146,664	$	141,520		4%
Gross margin per Mcf ⁽¹⁾		0.53		0.52		2%
Gross margin per Mcf attributable to Western Gas Partners, LP ^{(1) (2)}		0.55		0.55		—%
Adjusted EBITDA attributable to Western Gas Partners, LP ⁽³⁾		95,929		94,680		1%
Distributable cash flow ⁽³⁾	$	79,130	$	82,361		(4)%

⁽¹⁾

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

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

⁽³⁾

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

Gross margin and Gross margin per Mcf. Gross margin and gross margin per Mcf increased by $5.1 million and $0.01, respectively, for the three months ended March 31, 2013, primarily due to higher margins at the Non-Operated Marcellus Interest due to throughput increases.

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.

Adjusted EBITDA increased by $1.2 million for the three months ended March 31, 2013, primarily due to a $4.7 million increase in total revenues excluding equity income, a $2.0 million decrease in net income attributable to noncontrolling interest, a $0.6 million increase in distributions from equity investees and a $0.1 million decrease in cost of product. These amounts were offset by a $4.6 million increase in operation and maintenance expenses, a $0.9 million increase in property and other tax expense, and a $0.6 million increase in general and administrative expenses excluding non-cash equity-based compensation.

Distributable cash flow. We define “Distributable cash flow” as Adjusted EBITDA, plus interest income, less net cash paid for interest expense (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures, and income taxes. We compare Distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the Coverage ratio of estimated cash flows to planned cash distributions. We believe Distributable cash flow is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships.

While Distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period.

Distributable cash flow decreased by $3.2 million for the three months ended March 31, 2013, primarily due to a $4.8 million increase in net cash paid for interest expense offset by a $1.2 million increase in Adjusted EBITDA.

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.

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
	March 31,
thousands	2013		2012
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	95,929	$	94,680
Less:
Distributions from equity investees		5,006		4,441
Non-cash equity-based compensation expense		877		4,066
Interest expense		11,811		9,581
Income tax expense		4,236		4,429
Depreciation, amortization and impairments ⁽¹⁾		31,824		26,412
Add:
Equity income, net		3,980		3,613
Interest income, net – affiliates		4,225		4,225
Other income ^{(1) (2)}		277		62

Net income attributable to Western Gas Partners, LP	$	50,657	$	53,651


Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	95,929	$	94,680
Adjusted EBITDA attributable to noncontrolling interests		2,846		4,898
Interest income (expense), net		(7,586)		(5,356)
Non-cash equity based compensation expense		(73)		(3,152)
Debt-related amortization and other items, net		560		511
Current income tax expense		(3,112)		7,783
Other income (expense), net ⁽²⁾		278		62
Distributions from equity investees less than (in excess of) equity income, net		(1,026)		(828)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		20,754		32,827
Accounts payable, accrued liabilities and natural gas imbalance payable		21,287		(13,665)
Other		98		960

Net cash provided by operating activities	$	129,955	$	118,720


Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	129,955	$	118,720
Net cash used in investing activities		(771,888)		(539,069)
Net cash provided by financing activities		285,468		233,408

⁽¹⁾

Includes our 51% share for the three months ended March 31, 2012, and 75% share for the three months ended March 31, 2013, of depreciation, amortization and impairments 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 for each of the three months ended March 31, 2013 and 2012, 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.


	Three Months Ended
	March 31,
thousands except Coverage ratio	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	$	79,130		$	82,361
Less:
Distributions from equity investees		5,006			4,441
Non-cash equity-based compensation expense		877			4,066
Interest expense, net (non-cash settled)		—			81
Income tax expense		4,236			4,429
Depreciation, amortization and impairments ⁽¹⁾		31,824			26,412
Add:
Equity income, net		3,980			3,613
Cash paid for maintenance capital expenditures ⁽¹⁾		6,032			6,315
Capitalized interest		3,181			657
Cash paid for income taxes		—			72
Other income ^{(1) (2)}		277			62

Net income attributable to Western Gas Partners, LP	$	50,657		$	53,651

Distributions declared ⁽³⁾
Limited partners	$	56,759
General partner		13,384

Total	$	70,143

Coverage ratio		1.13	x

⁽¹⁾

Includes our 51% share for the three months ended March 31, 2012, and 75% share for the three months ended March 31, 2013, of depreciation, amortization and impairments; 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 for each of the three months ended March 31, 2013 and 2012, 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⁾	Reflects distributions of $0.54 per unit declared for the three months ended March 31, 2013.

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 March 31, 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 fund future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. On April 17, 2013, the board of directors of our general partner declared a cash distribution to our unitholders of $0.54 per unit, which equates to $70.1 million in aggregate including incentive distributions. The cash distribution is payable on May 13, 2013, to unitholders of record at the close of business on April 30, 2013.

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

Working capital. As of March 31, 2013, we had a $101.3 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 balance was a deficit as of March 31, 2013, primarily due to our use of approximately $215.5 million of cash on hand to fund the Non-Operated Marcellus Interest acquisition on March 1, 2013. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q. As of March 31, 2013, we had $402.2 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.

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:


	Three Months Ended
	March 31,
thousands	2013		2012
Acquisitions	$	600,590	$	463,232

Expansion capital expenditures	$	160,431	$	69,522
Maintenance capital expenditures		6,032		6,315

Total capital expenditures ⁽¹⁾	$	166,463	$	75,837

Capital incurred ⁽²⁾	$	163,663	$	104,732

⁽¹⁾

Capital expenditures for the three months ended March 31, 2013, included $3.2 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 three months ended March 31, 2012, included $33.6 million of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest acquisition.

⁽²⁾

Capital incurred for the three months ended March 31, 2013, included $3.2 million of capitalized interest. Capital incurred for the three months ended March 31, 2013 and 2012, included $8.8 million and $48.8 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 Anadarko-Operated Marcellus Interest acquisition and the Non-Operated Marcellus Interest acquisition in the first quarter of 2013, 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 $90.6 million for the three months ended March 31, 2013. Expansion capital expenditures increased by $90.9 million (including a $2.5 million increase in capitalized interest) for the three months ended March 31, 2013, primarily due to an increase of $72.3 million related to the construction of the Brasada and Lancaster gas processing facilities and a $30.7 million increase in expenditures at the Wattenberg system and the Red Desert complex. These increases were partially offset by a $13.3 million decrease at Chipeta and the Non-Operated Marcellus Interest. Maintenance capital expenditures decreased by $0.3 million, primarily as a result of decreased expenditures of $1.2 million at the Granger Complex, and the Newcastle and Pinnacle systems, partially offset by a $0.9 million increase at the Anadarko-Operated Marcellus Interest, and the Dew and Platte Valley systems.

Historical cash flow. The following table and discussion presents a summary of our net cash flows provided by (used in) operating activities, investing activities and financing activities:


	Three Months Ended
	March 31,
thousands	2013		2012
Net cash provided by (used in):
Operating activities	$	129,955	$	118,720
Investing activities		(771,888)		(539,069)
Financing activities		285,468		233,408

Net increase (decrease) in cash and cash equivalents	$	(356,465)	$	(186,941)

Operating Activities. For expanded discussion, refer to Operating Results within this Item 2 of this Form 10-Q. Net cash provided by operating activities increased by $11.2 million for the three months ended March 31, 2013, primarily due to the following items:

•

an increase of $22.0 million of working capital changes and other items, net, due to accruals of expected future operating cash receipts and cash payments;

•

a $4.7 million increase in revenues, excluding equity income, due to increased processing throughput as a result of increased drilling activity in certain of our operating areas;

•

a $2.5 million decrease in general and administrative expenses;

•

a $0.4 million increase in equity income; and

•

a $0.2 million increase in other income (expense), net.

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

•

a $10.9 million increase in current income tax expense, due to income earned by the Non-Operated Marcellus Interest being subject to higher federal and state income tax for the period prior to the acquisition by us that was subsequently contributed by Anadarko in March 2013;

•

a $4.6 million increase in operation and maintenance expense, due to additional expenses related to the acquisition of the Non-Operated Marcellus Interest from Anadarko and the acquisition of the Anadarko-Operated Marcellus Interest from a third party in March 2013;

•

a $2.2 million increase in interest expense, excluding debt-related amortization expense and other items, net, primarily due to the 2022 Notes offering in the second half of 2012; and

•

a $0.9 million increase in property and other taxes expense.

Investing Activities. Net cash used in investing activities for the three months ended March 31, 2013, included the following:

•

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

•

$166.5 million of capital expenditures;

•

$134.9 million of cash paid for the Anadarko-Operated Marcellus Interest acquisition; and

•

$4.8 million of cash paid related to a White Cliffs expansion project anticipated to be completed in the first half of 2014.

Net cash used in investing activities for the three months ended March 31, 2012, included the following:

•

$458.6 million of cash paid for the MGR acquisition;

•

$75.8 million of capital expenditures; and

•

$4.5 million of cash paid for equipment purchases from Anadarko.

Financing Activities. Net cash provided by financing activities for the three months ended March 31, 2013, included the following:

•

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

•

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

•

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

Net distributions to Anadarko attributable to intercompany balances were $30.0 million during 2013, representing intercompany transactions attributable to the Non-Operated Marcellus Interest acquisition.

Net cash provided by financing activities for the three months ended March 31, 2012, included $299.0 million of borrowings to fund the MGR acquisition. Net distributions to Anadarko attributable to intercompany balances were $12.2 million during 2012, representing intercompany transactions attributable to the Non-Operated Marcellus Interest acquisition and the Bison assets.

For the three months ended March 31, 2013 and 2012, we paid $65.7 million and $43.0 million, respectively, of cash distributions to our unitholders. Contributions to Chipeta from noncontrolling interest owners totaled $1.1 million and $9.8 million during the three months ended March 31, 2013 and 2012, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $2.7 million and $5.1 million for the three months ended March 31, 2013 and 2012, respectively, representing the distributions for the fourth quarter of each preceding year. Decreases in contributions to and distributions from Chipeta noncontrolling interest owners are also due to the August 2012 acquisition of Anadarko’s then remaining 24% membership interest in Chipeta.

Debt and credit facility. As of March 31, 2013, the carrying value of our outstanding debt consisted of $673.5 million of the 2022 Notes, $494.8 million of the 2021 Notes and $385.0 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 June 2012, we completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, we issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The additional notes were issued under the same indenture as, and as a single class of securities with, the June 2012 issuance. The notes issued in June 2012 and in October 2012 are collectively referred to as the “2022 Notes.” Including the effects of the issuance discount for the June 2012 offering, the issuance premium for the October 2012 offering, and underwriting discounts of $4.4 million, the effective interest rate of the 2022 Notes is 4.040%. Interest is paid semi-annually on January 1 and July 1 of each year. Proceeds (net of underwriting discounts and debt issuance costs) were used to repay all amounts then outstanding under our RCF and the $175.0 million note payable to Anadarko (see below), with the remaining net proceeds used for general partnership purposes.

In May 2011, we completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) at a price to the public of 98.778% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%.

At March 31, 2013, we were in compliance with all covenants under the indentures.

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 issuance of the 2022 Notes.

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

On June 13, 2012, following the receipt of a second investment grade rating as defined in the RCF, we are no longer subject to certain of the restrictive covenants associated with the RCF. As of March 31, 2013, we had $385.0 million of outstanding borrowings and $12.8 million in outstanding letters of credit issued under our $800.0 million RCF. At March 31, 2013, we were in compliance with all remaining covenants under the RCF.

The 2022 Notes, the 2021 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, our general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary agreed to indemnify our general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. The 2013 Indemnification Agreement applies to such debt financings up to $385.0 million. 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 $125.0 million of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of March 31, 2013, we had not issued any common units under this registration statement.

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

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

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

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

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 to Note 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 March 31, 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 2012 and three months ended March 31, 2013 were low compared to historic rates. As of March 31, 2013, we had $385.0 million of outstanding borrowings under our RCF (which bears interest at a rate based on LIBOR). If interest rates rise, our future financing costs could increase. For the three months ended March 31, 2013, a 10% change in LIBOR would have resulted in a nominal change in net income.

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.

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 March 31, 2013.

Changes in Internal Control Over Financial Reporting. There has been no change in our internal control over financial reporting during the quarter ended March 31, 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, or for which disclosure is otherwise required by Item 103 of Regulation S-K.

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.

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).


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		Fourth Supplemental Indenture, dated as of June 28, 2012, 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 June 28, 2012, 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).


10.1		Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
10.2		Third Amended and Restated Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
10.3		First Amendment to the Amended and Restated Revolving Credit Agreement, dated as of February 7, 2013, among Western Gas Partners, LP, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.16 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2013, File No. 001-34046).
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

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

May 2, 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)

May 2, 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)