Edgar Filing: Western Gas Partners LP

Form 10-Q for quarterly period ended March 31, 2012

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, 2012

¨	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 þ No ¨

There were 90,773,782 common units outstanding as of April 30, 2012.

TABLE OF CONTENTS


PART I		FINANCIAL INFORMATION	PAGE

	Item 1.	Financial Statements

		Consolidated Statements of Income for the three months ended March 31, 2012 and 2011	4

		Consolidated Balance Sheets as of March 31, 2012, and December 31, 2011	5

		Consolidated Statement of Equity and Partners’ Capital for the three months ended March 31, 2012	6

		Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011	7

		Notes to Consolidated Financial Statements	8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

		Cautionary Note Regarding Forward-Looking Statements	23

		Executive Summary	25

		Acquisitions	26

		Equity Offerings	27

		Results of Operations	27

		Operating Results	27

		Liquidity and Capital Resources	36

		Contractual Obligations	41

		Off-Balance Sheet Arrangements	41

		Recent Accounting Developments	41

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

	Item 4.	Controls and Procedures	43

PART II		OTHER INFORMATION

	Item 1.	Legal Proceedings	43

	Item 1A.	Risk Factors	43

	Item 6.	Exhibits	44

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.

MMBtu/d: One million British thermal units per day.

MMcf: One million cubic feet.

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.

Pounds per square inch, absolute: The pressure resulting from a one-pound force applied to an area of one square inch, including local atmospheric pressure. All volumes presented herein are based on a standard pressure base of 14.73 pounds per square inch, absolute.

Residue gas: 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 amounts	2012		2011 ⁽¹⁾
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	56,892	$	52,536
Natural gas, natural gas liquids and condensate sales		105,653		87,685
Equity income and other, net		4,001		2,946

Total revenues – affiliates		166,546		143,167
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		22,263		17,821
Natural gas, natural gas liquids and condensate sales		22,833		18,204
Other, net		600		1,650

Total revenues – third parties		45,696		37,675

Total revenues		212,242		180,842

Operating expenses
Cost of product ⁽²⁾		83,156		67,183
Operation and maintenance ⁽²⁾		29,898		26,861
General and administrative ⁽²⁾		9,924		7,862
Property and other taxes		4,837		4,321
Depreciation, amortization and impairments		26,586		23,643

Total operating expenses		154,401		129,870

Operating income		57,841		50,972
Interest income, net – affiliates		4,225		4,670
Interest expense ⁽³⁾		(9,581)		(6,111)
Other income (expense), net		458		2,152

Income before income taxes		52,943		51,683
Income tax expense		537		4,832

Net income		52,406		46,851
Net income attributable to noncontrolling interests		4,243		2,954

Net income attributable to Western Gas Partners, LP	$	48,163	$	43,897

Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	48,163	$	43,897
Pre-acquisition net (income) loss allocated to Parent		—		(8,913)
General partner interest in net (income) loss ⁽⁴⁾		(4,339)		(1,448)

Limited partners’ interest in net income ⁽⁴⁾	$	43,824	$	33,536
Net income per common unit – basic and diluted	$	0.48	$	0.43
Net income per subordinated unit – basic and diluted ⁽⁵⁾	$	—	$	0.41

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

⁽²⁾

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $33.4 million and $17.4 million for the three months ended March 31, 2012 and 2011, respectively. Operation and maintenance includes charges from Anadarko of $12.5 million and $11.9 million for the three months ended March 31, 2012 and 2011, respectively. General and administrative includes charges from Anadarko of $8.5 million and $6.2 million for the three months ended March 31, 2012 and 2011, respectively. See Note 5.

⁽³⁾	Includes Affiliate (as defined in Note 1) interest expense of $1.3 million and $1.2 million for the three months ended March 31, 2012 and 2011, respectively. See Note 7.

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

⁽⁵⁾	All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


thousands except number of units	March 31, 2012		December 31, 2011 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	39,618	$	226,559
Accounts receivable, net		19,978		22,703
Other current assets ⁽²⁾		7,070		7,186

Total current assets		66,666		256,448
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		2,741,828		2,638,013
Less accumulated depreciation		615,627		585,789

Net property, plant and equipment		2,126,201		2,052,224
Goodwill		82,136		82,136
Other intangible assets		52,589		52,858
Equity investments		108,989		109,817
Other assets		23,620		24,143

Total assets	$	2,720,201	$	2,837,626

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables ⁽³⁾	$	27,520	$	26,600
Accrued ad valorem taxes		12,485		8,186
Income taxes payable		484		495
Accrued liabilities ⁽⁴⁾		81,755		41,315

Total current liabilities		122,244		76,596
Long-term debt – third parties		773,296		494,178
Note payable – Anadarko		175,000		175,000
Deferred income taxes		1,350		107,377
Asset retirement obligations and other		68,288		67,169

Total long-term liabilities		1,017,934		843,724

Total liabilities		1,140,178		920,320
Equity and partners’ capital
Common units (90,773,782 and 90,140,999 units issued and outstanding at March 31, 2012, and December 31, 2011, respectively)		1,416,896		1,495,253
General partner units (1,852,527 and 1,839,613 units issued and outstanding at March 31, 2012, and December 31, 2011, respectively)		33,456		31,729
Parent net investment		—		269,600

Total partners’ capital		1,450,352		1,796,582
Noncontrolling interests		129,671		120,724

Total equity and partners’ capital		1,580,023		1,917,306

Total liabilities, equity and partners’ capital	$	2,720,201	$	2,837,626

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

⁽²⁾	Other current assets includes natural gas imbalance receivables from affiliates of $0.4 million and $0.5 million as of March 31, 2012, and December 31, 2011, respectively.

⁽³⁾	Accounts and natural gas imbalance payables includes amounts payable to affiliates of $5.3 million and $5.9 million as of March 31, 2012, and December 31, 2011, respectively.

⁽⁴⁾	Accrued liabilities include amounts payable to affiliates of $18.9 million and $0.3 million as of March 31, 2012, and December 31, 2011, respectively. 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	Parent Net Investment		Common Units		General Partner Units		Noncontrolling Interests		Total
Balance at December 31, 2011⁽¹⁾	$	269,600	$	1,495,253	$	31,729	$	120,724	$	1,917,306
Net income		—		43,824		4,339		4,243		52,406
Contributions from noncontrolling interest owners		—		—		—		9,849		9,849
Distributions to noncontrolling interest owners		—		—		—		(5,145)		(5,145)
Distributions to unitholders		—		(39,940)		(3,087)		—		(43,027)
Acquisition from affiliates		(482,701)		23,458		479		—		(458,764)
Contributions of equity-based compensation from Parent		—		1,095		22		—		1,117
Net pre-acquisition contributions from (distributions to) Parent		106,597		(106,597)		—		—		—
Net distributions of other assets to Parent		—		(2,972)		(28)		—		(3,000)
Elimination of net deferred tax liabilities		106,504		—		—		—		106,504
Non-cash equity-based compensation and other		—		2,775		2		—		2,777

Balance at March 31, 2012	$	—	$	1,416,896	$	33,456	$	129,671	$	1,580,023

⁽¹⁾	Financial information has been recast to include the financial position and results attributable to the MGR assets. 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	2012		2011 ⁽¹⁾
Cash flows from operating activities
Net income	$	52,406	$	46,851
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		26,586		23,643
Deferred income taxes		477		2,453
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		4,709		(9,911)
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net		9,245		7,308
Change in other items, net		1,143		1,626

Net cash provided by operating activities		94,566		71,970
Cash flows from investing activities
Capital expenditures		(61,071)		(21,010)
Acquisitions from affiliates		(463,232)		—
Acquisitions from third parties		—		(303,602)
Investments in equity affiliates		—		(93)
Proceeds from sale of assets to affiliates		—		153

Net cash used in investing activities		(524,303)		(324,552)
Cash flows from financing activities
Borrowings, net of debt issuance costs		319,000		556,340
Repayments of debt		(40,000)		(389,000)
Proceeds from issuance of common and general partner units, net of offering expenses		—		132,796
Distributions to unitholders		(43,027)		(30,564)
Contributions from noncontrolling interest owners		9,849		960
Distributions to noncontrolling interest owners		(5,145)		(4,364)
Net contributions from (distributions to) Parent		2,119		(9,819)

Net cash provided by financing activities		242,796		256,349

Net increase (decrease) in cash and cash equivalents		(186,941)		3,767
Cash and cash equivalents at beginning of period		226,559		27,074

Cash and cash equivalents at end of period	$	39,618	$	30,841


Supplemental disclosures
Elimination of net deferred tax liabilities	$	106,504	$	—
Transfer of Brasada and Lancaster capital expenditures	$	19,197	$	—
Increase (decrease) in accrued capital expenditures	$	17,752	$	(3,928)
Interest paid	$	1,986	$	5,009
Interest received	$	4,225	$	4,225
Taxes paid	$	72	$	—

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

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

General. Western Gas Partners, LP (the “Partnership”), which closed its initial public offering to become publicly traded in 2008, is a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to own, operate, acquire and develop midstream energy assets. As of March 31, 2012, the Partnership’s assets include thirteen gathering systems, seven natural gas treating facilities, ten natural gas processing facilities, two NGL pipelines, one interstate gas pipeline, one intrastate gas pipeline and interests accounted for under the equity method in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”). The Partnership’s assets are located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko Petroleum Corporation and its consolidated subsidiaries, as well as third-party producers and customers.

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

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

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement, as amended and restated (the “Chipeta LLC agreement”). As of March 31, 2012, Chipeta is owned 51% by the Partnership, 24% by Anadarko and 25% by a third-party member. The interests in Chipeta held by Anadarko and the third-party member are reflected as noncontrolling interests in the Partnership’s consolidated financial statements for all periods presented.

The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of financial position as of March 31, 2012, and December 31, 2011, results of operations for the three months ended March 31, 2012 and 2011, statement of equity and partners’ capital for the three months ended March 31, 2012, and statements of cash flows for the three months ended March 31, 2012 and 2011. The Partnership’s financial results for the three months ended March 31, 2012, are not necessarily indicative of the expected results for the full year ending December 31, 2012.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

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

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.

Certain information and note disclosures normally 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 2011 Form 10-K, as filed with the SEC on February 28, 2012. Management believes that the disclosures made are adequate to make the information not misleading. Certain prior-period amounts have been reclassified to conform to the current-year presentation.

Recently adopted accounting standard. In May 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU is to be applied prospectively and is effective for periods beginning after December 15, 2011. The Partnership adopted the ASU effective January 1, 2012. The adoption of the requirements of the ASU, which expanded disclosures, had no effect on the Partnership’s results of operations or financial position.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS

The following table presents the acquisitions completed by the Partnership during 2012 and 2011 and details the funding for those acquisitions through borrowings, cash on hand and/or the issuance of Partnership equity:


thousands except unit and percent amounts	Acquisition Date	Percentage Acquired		Borrowings		Cash On Hand	Common Units Issued	GP Units Issued
Platte Valley ⁽¹⁾	02/28/11	100%	$	303,000	$	602	—	—
Bison ⁽²⁾	07/08/11	100%		—		25,000	2,950,284	60,210
MGR ⁽³⁾	01/13/12	100%		299,000		159,587	632,783	12,914

⁽¹⁾

The assets acquired from a third party include (i) a natural gas gathering system and related compression and other ancillary equipment, and (ii) cryogenic gas processing facilities. These assets, located in the Denver-Julesburg Basin, are referred to collectively as the “Platte Valley assets” and the acquisition as the “Platte Valley acquisition.” An adjustment to intangible assets of $1.6 million was recorded in August 2011, representing the final allocation of the purchase price.

⁽²⁾

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

⁽³⁾

Mountain Gas Resources LLC (“MGR”), acquired from Anadarko, owns (i) the Red Desert Complex, located in the greater Green River Basin in southwestern Wyoming, including 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.” See further information below.

Platte Valley acquisition. The Platte Valley acquisition was accounted for under the acquisition method of accounting, whereby the Platte Valley assets and liabilities were recorded in the consolidated balance sheet at their estimated fair value as of the acquisition date. Results of operations attributable to the Platte Valley assets were included in the Partnership’s consolidated statements of income beginning on the acquisition date in the first quarter of 2011. The intangible asset balance in the Partnership’s consolidated balance sheets represents the fair value, net of amortization, related to the contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which dedicate certain customers’ field production to the acquired gathering and processing system.

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


	Three Months Ended
thousands except per-unit amount	March 31, 2011
Revenues	$	196,881
Net income		49,577
Net income attributable to Western Gas Partners, LP		46,623
Net income per common unit – basic and diluted	$	0.47

Bison and MGR acquisitions. As transfers 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 Bison and MGR assets as if the Partnership owned such assets for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

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 Bison and MGR assets, including the elimination of intercompany activity between such assets:


	Three Months Ended March 31, 2011
thousands	Partnership Historical		Bison Assets		MGR Assets		Eliminations		Combined
Revenues	$	135,993	$	5,592	$	39,271	$	(14)	$	180,842
Net income		37,938		1,627		7,286		—		46,851

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

3. PARTNERSHIP DISTRIBUTIONS

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


thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Cash Distribution		Date of Distribution
March 31, 2011	$	0.390	$	33,168	May 2011
March 31, 2012⁽¹⁾	$	0.460	$	46,053	May 2012

⁽¹⁾

On April 19, 2012, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.46 per unit, or $46.1 million in aggregate, including incentive distributions. The cash distribution is payable on May 14, 2012, to unitholders of record at the close of business on April 30, 2012.

4. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public equity offerings during 2011:


thousands except unit and per-unit amounts	Common Units Issued ⁽¹⁾		GP Units Issued ⁽²⁾		Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
March 2011 equity offering		3,852,813		78,629	$	35.15	$	5,621	$	132,569
September 2011 equity offering		5,750,000		117,347		35.86		7,655		202,748

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

⁽²⁾	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% interest.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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

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

Anadarko holdings of Partnership equity. As of March 31, 2012, Anadarko held 1,852,527 general partner units representing a 2.0% general partner interest in the Partnership, 40,422,004 common units representing a 43.6% limited partner interest, and 100% of the Partnership’s IDRs. The public held 50,351,778 common units, representing a 54.4% interest in the Partnership.

The Partnership’s net income for periods including and subsequent to the acquisition of the Partnership assets (as defined in Note 2) is allocated to the general partner and the limited partners consistent with actual cash distributions, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner and the limited partners in accordance with their respective ownership percentages (see Note 1).

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

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


	Three Months Ended March 31,
thousands except per-unit amounts	2012		2011
Net income attributable to Western Gas Partners, LP	$	48,163	$	43,897
Pre-acquisition net (income) loss allocated to Parent		—		(8,913)
General partner interest in net (income) loss		(4,339)		(1,448)

Limited partners’ interest in net income	$	43,824	$	33,536


Net income allocable to common units	$	43,824	$	22,587
Net income allocable to subordinated units		—		10,949

Limited partners’ interest in net income	$	43,824	$	33,536


Net income per unit – basic and diluted
Common units	$	0.48	$	0.43
Subordinated units	$	—	$	0.41

Weighted average units outstanding – basic and diluted
Common units		90,690		52,145
Subordinated units		—		26,536

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES

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

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

Note receivable from and amounts payable to Anadarko. Concurrent with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was approximately $308.2 million and $303.7 million at March 31, 2012, and December 31, 2011, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.

In addition, in December 2008, the Partnership entered into a term loan agreement with Anadarko. See Note 7.

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 Brasada and Lancaster plants. In February 2012, these expenditures were transferred to the Partnership and a corresponding current payable was established, which the Partnership expects to repay during 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 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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

Year Ended December 31,

per barrel except natural gas

2012

2013

2014

2015

2016

Ethane

$ 18.21 – 29.78

$ 18.32 – 30.10

$ 18.36 – 30.53

$ 18.41 – 23.41

23.11

Propane

$ 45.23 – 57.97

$ 45.90 – 55.84

$ 46.47 – 53.78

$ 47.08 – 52.99

52.90

Isobutane

$ 57.50 – 80.98

$ 60.44 – 77.66

$ 61.24 – 75.13

$ 62.09 – 74.02

73.89

Normal butane

$ 52.40 – 71.15

$ 53.20 – 68.24

$ 53.89 – 66.01

$ 54.62 – 65.04

64.93

Natural gasoline

$ 69.77 – 89.51

$ 70.89 – 92.23

$ 71.85 – 83.04

$ 72.88 – 81.82

81.68

Condensate

$ 72.73 – 89.51

$ 74.04 – 85.84

$ 75.22 – 83.04

$ 76.47 – 81.82

81.68

Natural gas (per MMbtu)

$ 3.62 – 5.97

$ 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	2012		2011
Gains (losses) on commodity price swap agreements related to sales: ⁽¹⁾
Natural gas sales	$	9,850	$	6,808
Natural gas liquids sales		354		(5,841)

Total		10,204		967
Losses on commodity price swap agreements related to purchases ⁽²⁾		(17,192)		(6,206)

Net gains (losses) on commodity price swap agreements	$	(6,988)	$	(5,239)

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

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

Gas gathering and processing agreements. The Partnership has significant gas gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. Approximately 76% and 74% of the Partnership’s gathering, transportation and treating throughput for the three months ended March 31, 2012 and 2011, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 57% and 65% of the Partnership’s processing throughput for the three months ended March 31, 2012 and 2011, respectively, was attributable to natural gas production owned or controlled by Anadarko.

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

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) Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) and (ii) the Anadarko Petroleum Corporation 1999 Stock Incentive Plan and the Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”).

Under the Incentive Plan, participants are granted Unit Value Rights (“UVRs”), Unit Appreciation Rights (“UARs”) and Dividend Equivalent Rights (“DERs”). UVRs and UARs granted under the Incentive Plan in 2012 and 2011 were collectively valued at $718.00 per unit and $634.00 per unit as of March 31, 2012, and December 31, 2011, respectively. The Partnership’s general and administrative expense for the three months ended March 31, 2012 and 2011 included approximately $4.1 million and $2.0 million, respectively, of allocated equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Equipment purchase. In March 2012, the Partnership purchased equipment with a net carrying value of $0.6 million from Anadarko for $4.5 million in cash, with the difference recorded as an adjustment to Partners’ capital.

During 2011, as described in Note receivable from and amounts payable to Anadarko above, Anadarko purchased equipment related to the construction of the Brasada and Lancaster gas processing facilities. In the first quarter of 2012, this equipment was transferred to the Partnership and is included in the balance of property, plant and equipment as of March 31, 2012. See Note 6.

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	2012		2011
Revenues ⁽¹⁾	$	166,546	$	143,167
Cost of product ⁽¹⁾		33,426		17,391
Operation and maintenance ⁽²⁾		12,473		11,938
General and administrative ⁽³⁾		8,483		6,200

Operating expenses		54,382		35,529
Interest income, net ⁽⁴⁾		4,225		4,670
Interest expense ⁽⁵⁾		1,315		1,234
Distributions to unitholders ⁽⁶⁾		20,872		15,085
Contributions from noncontrolling interest owners		4,824		960
Distributions to noncontrolling interest owners		2,520		3,014

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

⁽²⁾

Represents expenses incurred under the services and secondment agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to Partnership assets prior to the acquisition of such assets by the Partnership.

⁽³⁾

Represents general and administrative expense incurred under the omnibus agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership assets, as well as a management services fee not within the scope of the omnibus agreement for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership.

⁽⁴⁾

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

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

⁽⁶⁾	Represents distributions paid under the partnership agreement.

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

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, 2012

December 31, 2011

Land

n/a

364

364

Gathering systems

5 to 47 years

2,463,764

2,437,152

Pipelines and equipment

15 to 45 years

90,961

90,883

Assets under construction

n/a

181,206

104,687

Other

3 to 25 years

5,533

4,927

Total property, plant and equipment

2,741,828

2,638,013

Accumulated depreciation

615,627

585,789

Net property, plant and equipment

2,126,201

2,052,224

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. Assets under construction includes $18.9 million related to the transfer of the Brasada and Lancaster gas processing facilities (see Note 5), and $0.3 million of related capitalized interest. In addition, property, plant and equipment cost and third-party accrued liability balances in the Partnership’s consolidated balance sheets each include $32.7 million and $15.0 million of accrued capital as of March 31, 2012, and December 31, 2011, respectively, representing estimated capital expenditures for which invoices had not yet been processed.

7. DEBT AND INTEREST EXPENSE

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


	March 31, 2012						December 31, 2011
thousands	Principal		Carrying Value		Fair Value		Principal		Carrying Value		Fair Value
Revolving credit facility	$	279,000	$	279,000	$	279,000	$	—	$	—	$	—
5.375% Senior Notes due 2021		500,000		494,296		499,950		500,000		494,178		499,950
Note payable to Anadarko		175,000		175,000		175,181		175,000		175,000		174,528

Total debt outstanding ⁽¹⁾	$	954,000	$	948,296	$	954,131	$	675,000	$	669,178	$	674,478

⁽¹⁾	The Partnership’s consolidated balance sheets include accrued interest expense of $9.7 million and $2.7 million as of March 31, 2012, and December 31, 2011, respectively, which is included in accrued liabilities.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7. DEBT AND INTEREST EXPENSE (CONTINUED)

Fair value of debt. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. Accordingly, the fair value of the debt instruments in the table above 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, 2012:


thousands	Carrying Value
Balance as of December 31, 2011	$	669,178
Revolving credit facility borrowings		319,000
Repayment of revolving credit facility		(40,000)
Other and changes in debt discount		118

Balance as of March 31, 2012	$	948,296

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

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Partnership’s wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees will be released if the Subsidiary Guarantors are released from their obligations under the Partnership’s revolving credit facility. See Note 9 for the condensed financial statements of the Subsidiary Guarantors. At March 31, 2012, the Partnership was in compliance with all covenants under the Notes.

The Notes and obligations under the revolving credit facility (“RCF”) are recourse to the Partnership’s general partner. In turn, the Partnership’s general partner has been indemnified by a wholly owned Affiliate of Anadarko against any claims made against the general partner under the Notes and RCF. The foregoing description is qualified in its entirety by reference to the full text of the Indemnity Agreement, a copy of which is filed with this Form 10-Q as Exhibit 10.1, and is incorporated herein by reference.

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

The provisions of the five-year term loan agreement contain customary events of default, including (i) non-payment of principal when due or non-payment of interest or other amounts within three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to the Partnership and (iii) a change of control. At March 31, 2012, the Partnership was in compliance with all covenants under this agreement.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7. DEBT AND INTEREST EXPENSE (CONTINUED)

Revolving credit facility. In March 2011, the Partnership entered into an amended and restated $800.0 million senior unsecured RCF which matures in March 2016 and bears interest at London Interbank Offered Rate (“LIBOR”) plus applicable margins currently ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.74% and 1.80% at March 31, 2012, and December 31, 2011, respectively. The Partnership is required to pay a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon the Partnership’s senior unsecured debt rating. The facility fee rate was 0.25% at March 31, 2012, and December 31, 2011. All amounts due under the RCF are unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. As of March 31, 2012, $279.0 million was outstanding under the RCF ($521.0 million available for borrowing) and the Partnership was in compliance with all covenants under the RCF. As discussed above in the paragraph describing the Notes, the Partnership’s obligations under the RCF are recourse to the Partnership’s general partner.

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

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

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


	Three Months Ended March 31,
thousands	2012		2011
Third Parties
Interest expense on long-term debt	$	7,915	$	2,676
Amortization of debt issuance costs and commitment fees ⁽¹⁾		1,008		2,201
Capitalized interest		(657)		—

Total interest expense – third parties		8,266		4,877

Affiliates
Interest expense on note payable to Anadarko		1,234		1,234
Interest expense, net on affiliate balances		81		—

Total interest expense – affiliates		1,315		1,234

Interest expense	$	9,581	$	6,111

⁽¹⁾	For the three months ended March 31, 2012, includes $0.2 million of amortization of the original issue discount and underwriters’ fees related to the Notes.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. 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 October 2013. 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.

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations. The leases for the shared field offices extend through 2018, and the lease for the warehouse extends through February 2014 and includes an early termination clause. During 2011, Anadarko entered into a lease agreement for the Partnership’s corporate offices that extends through March 2017. Anadarko, on behalf of the Partnership, continues to lease certain other compression equipment under leases expiring through January 2015.

Rent expense associated with the office, warehouse and equipment leases was approximately $0.7 million and $1.0 million for the three months ended March 31, 2012 and 2011, respectively.

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

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

Western Gas Partners, LP’s and the Subsidiary Guarantors’ investment in and equity income from their subsidiaries are presented in accordance with the equity method of accounting in which the equity income from subsidiaries includes the results of operations of the Partnership assets for periods including and subsequent to the Partnership’s acquisition of the Partnership assets.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

Statement of Income
Three Months Ended March 31, 2012

thousands

Western
Gas
Partners, LP

Subsidiary
Guarantors

Non-
Guarantor
Subsidiary

Eliminations

Consolidated

Revenues

10,204

180,774

21,264

—

212,242

Operating expenses

26,475

115,319

12,607

—

154,401

Operating income (loss)

(16,271)

65,455

8,657

—

57,841

Interest income, net – affiliates

4,225

—

4,225

Interest expense

(9,506)

(75)

—

(9,581)

Other income (expense), net

394

—

458

Equity income

69,653

4,416

—

(74,069)

—

Income before income taxes

48,162

70,190

8,660

(74,069)

52,943

Income tax expense

—

537

—

537

Net income

48,162

69,653

8,660

(74,069)

52,406

Net income attributable to noncontrolling interests

—

4,243

—

4,243

Net income attributable to Western Gas Partners, LP

48,162

65,410

8,660

(74,069)

48,163


	Statement of Income Three Months Ended March 31, 2011
thousands	Western Gas Partners, LP		Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations		Consolidated
Revenues	$	967	$	167,082	$	12,793	$	—	$	180,842
Operating expenses		12,613		110,490		6,767		—		129,870

Operating income (loss)		(11,646)		56,592		6,026		—		50,972
Interest income, net – affiliates		4,225		455		—		(10)		4,670
Interest expense		(6,121)		—		—		10		(6,111)
Other income (expense), net		1,749		401		2		—		2,152
Equity income		46,777		3,074		—		(49,851)		—

Income before income taxes		34,984		60,522		6,028		(49,851)		51,683
Income tax expense		—		4,832		—		—		4,832

Net income		34,984		55,690		6,028		(49,851)		46,851
Net income attributable to noncontrolling interests		—		2,954		—		—		2,954

Net income attributable to Western Gas Partners, LP	$	34,984	$	52,736	$	6,028	$	(49,851)	$	43,897

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

Balance Sheet
March 31, 2012

thousands

Western
Gas
Partners, LP

Subsidiary
Guarantors

Non-
Guarantor
Subsidiary

Eliminations

Consolidated

Current assets

17,877

137,310

27,567

(116,088)

66,666

Note receivable – Anadarko

260,000

—

260,000

Investment in consolidated subsidiaries

1,390,368

139,746

—

(1,530,114)

—

Net property, plant and equipment

963

1,862,290

262,948

—

2,126,201

Other long-term assets

7,740

259,594

—

267,334

Total assets

1,676,948

2,398,940

290,515

(1,646,202)

2,720,201

Current liabilities

148,692

70,532

19,108

(116,088)

122,244

Long-term debt

948,296

—

948,296

Deferred income taxes

—

1,350

—

1,350

Asset retirement obligations and other

490

65,678

2,120

—

68,288

Total liabilities

1,097,478

137,560

21,228

(116,088)

1,140,178

Partners’ capital

579,470

2,131,709

269,287

(1,530,114)

1,450,352

Noncontrolling interests

—

129,671

—

129,671

Total liabilities, equity and partners’ capital

1,676,948

2,398,940

290,515

(1,646,202)

2,720,201


	Balance Sheet December 31, 2011
thousands	Western Gas Partners, LP		Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations		Consolidated
Current assets	$	207,913	$	110,619	$	25,977	$	(88,061)	$	256,448
Note receivable – Anadarko		260,000		—		—		—		260,000
Investment in consolidated subsidiaries		1,232,245		130,396		—		(1,362,641)		—
Net property, plant and equipment		735		1,812,275		239,214		—		2,052,224
Other long-term assets		8,164		260,790		—		—		268,954

Total assets	$	1,709,057	$	2,314,080	$	265,191	$	(1,450,702)	$	2,837,626

Current liabilities	$	95,817	$	56,762	$	12,078	$	(88,061)	$	76,596
Long-term debt		669,178		—		—		—		669,178
Deferred income taxes		—		107,377		—		—		107,377
Asset retirement obligations and other		104		64,980		2,085		—		67,169

Total liabilities		765,099		229,119		14,163		(88,061)		920,320
Partners’ capital		943,958		1,964,237		251,028		(1,362,641)		1,796,582
Noncontrolling interests		—		120,724		—		—		120,724

Total liabilities, equity and partners’ capital	$	1,709,057	$	2,314,080	$	265,191	$	(1,450,702)	$	2,837,626

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

Statement of Cash Flows
Three Months Ended March 31, 2012

thousands

Western
Gas
Partners, LP

Subsidiary
Guarantors

Non-
Guarantor
Subsidiary

Eliminations

Consolidated

Net income

48,162

69,653

8,660

(74,069)

52,406

Adjustments to reconcile net income to net cash provided by operating activities:

Equity income

(69,653)

(4,416)

—

74,069

—

Depreciation, amortization and impairments

25,228

1,339

—

26,586

Change in other items, net

58,386

(43,945)

1,133

—

15,574

Net cash provided by (used in) operating activities

36,914

46,520

11,132

—

94,566

Net cash used in investing activities

(459,222)

(57,218)

(18,114)

10,251

(524,303)

Net cash provided by (used in) financing activities

232,749

10,698

9,600

(10,251)

242,796

Net increase (decrease) in cash and cash equivalents

(189,559)

—

2,618

—

(186,941)

Cash and cash equivalents at beginning of period

205,264

—

21,295

—

226,559

Cash and cash equivalents at end of period

15,705

—

23,913

—

39,618


	Statement of Cash Flows Three Months Ended March 31, 2011
thousands	Western Gas Partners, LP		Subsidiary Guarantors		Non- Guarantor Subsidiary		Eliminations		Consolidated
Net income	$	34,984	$	55,690	$	6,028	$	(49,851)	$	46,851
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income		(46,777)		(3,074)		—		49,851		—
Depreciation, amortization and impairments		14		22,191		1,438		—		23,643
Change in other items, net		(259,049)		257,984		2,541		—		1,476

Net cash provided by operating activities		(270,828)		332,791		10,007		—		71,970
Net cash used in investing activities		—		(326,122)		(470)		2,040		(324,552)
Net cash provided by (used in) financing activities		269,175		(6,669)		(4,117)		(2,040)		256,349

Net increase (decrease) in cash and cash equivalents		(1,653)		—		5,420		—		3,767
Cash and cash equivalents at beginning of period		21,480		—		5,594		—		27,074

Cash and cash equivalents at end of period	$	19,827	$	—	$	11,014	$	—	$	30,841

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 2011 Form 10-K as filed with the Securities and Exchange Commission, or “SEC,” on February 28, 2012, 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” refers to Western Gas Partners, LP and its subsidiaries, including the financial results of the Partnership assets (described below) from their respective date acquired by entities under common control, for all periods presented. For ease of reference, we also refer to the historical financial results of the Partnership assets prior to our acquisitions as being “our” historical financial results. “Anadarko” or “Parent” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner. Our “general partner” refers to Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko and the general partner of the Partnership. “Affiliates” refers to Anadarko and its wholly owned and partially owned subsidiaries, excluding the Partnership, and also refers to Fort Union Gas Gathering, LLC, or “Fort Union,” White Cliffs Pipeline, LLC, or “White Cliffs,” and Rendezvous Gas Services, LLC, or “Rendezvous.” References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of March 31, 2012.

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 Partnership 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 prove to have been correct.

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 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;

•

the 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;

•

the supply of and demand for, and the prices of, oil, natural gas, NGLs and other products or services;

•

the weather;

•

inflation;

•

the availability of goods and services;

•

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

•

changes in environmental and safety regulations; 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 our sponsor, Anadarko, including changes as a result of remaining claims related to the Deepwater Horizon events for which Anadarko is not indemnified;

•

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

•

our commitments to capital projects and the ability to complete such projects on time and within budget expectations;

•

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

•

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

•

our ability to repay debt;

•

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; and

•

other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” included in our 2011 Form 10-K, our quarterly reports on Form 10-Q and 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 master limited partnership (“MLP”) organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently own assets located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), 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 third-party producers and customers. As of March 31, 2012, our assets consist of thirteen gathering systems, seven natural gas treating facilities, ten natural gas processing facilities, two NGL pipelines, one interstate gas pipeline, one intrastate gas pipeline and interests 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 2012 include the following:

•

We completed the January acquisition of Anadarko’s MGR assets located in southwestern Wyoming. See Acquisitions below.

•

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

•

Our stable operating cash flow enabled us to raise our distribution to $0.46 per unit for the first quarter of 2012, representing a 5% increase over the distribution for the fourth quarter of 2011, an 18% increase over the distribution for the first quarter of 2011, and our twelfth consecutive quarterly increase.

Significant operational highlights during the first three months of 2012 include the following:

•

Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.56 per Mcf for the three months ended March 31, 2012, representing a 2% increase compared to the three months ended March 31, 2011.

•

Throughput attributable to Western Gas Partners, LP totaled 2,414 MMcf/d for the three months March 31, 2012, representing a 10% increase compared to the same period in 2011.

ACQUISITIONS

Acquisitions. The following table presents our acquisitions completed during 2012 and 2011 and details the funding for those acquisitions through borrowings, cash on hand and/or the issuance of equity:


thousands except unit and percent amounts	Acquisition Date	Percentage Acquired		Borrowings		Cash On Hand	Common Units Issued	GP Units Issued
Platte Valley ⁽¹⁾	02/28/11	100%	$	303,000	$	602	—	—
Bison ⁽²⁾	07/08/11	100%		—		25,000	2,950,284	60,210
MGR ⁽³⁾	01/13/12	100%		299,000		159,587	632,783	12,914

⁽¹⁾

The assets acquired from a third party include (i) a processing plant with initial cryogenic capacity of 84 MMcf/d, (ii) two fractionation trains, (iii) an initial 1,098-mile natural gas gathering system that delivers gas to the Platte Valley plant either directly or through our Wattenberg gathering system, and (iv) related equipment. These assets, located in the Denver-Julesburg Basin, are referred to collectively as the “Platte Valley assets” or “Platte Valley system” and the acquisition as the “Platte Valley acquisition.” An adjustment to intangible assets of $1.6 million was recorded in August 2011, representing the final allocation of the purchase price. In connection with the acquisition, we entered into long-term fee-based agreements with the seller to gather and process its existing gas production, as well as to expand the existing gathering systems and processing capacity. We financed the Platte Valley acquisition with borrowings under our RCF. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽²⁾

The Bison gas treating facility that we acquired from Anadarko is located in the Powder River Basin in northeastern Wyoming, and includes (i) three amine treating units with a combined CO₂ treating capacity of 450 MMcf/d, (ii) three compressor units with combined compression of 5,230 horsepower, and (iii) five generators with combined power output of 6.5 megawatts. These assets are referred to collectively as the “Bison assets” and the acquisition as the “Bison acquisition.” The Bison assets are the only treating and delivery point into the third-party owned Bison pipeline. Anadarko began construction of the Bison assets in 2009 and placed them in service in June 2010.

⁽³⁾

Mountain Gas Resources LLC (“MGR”), acquired from Anadarko, owns (i) the Red Desert Complex, located in the greater Green River Basin in southwestern Wyoming, including the Patrick Draw processing plant with a capacity of 125 MMcf/d, the Red Desert processing plant with a capacity of 48 MMcf/d, 1,295 miles of gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, 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.

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of March 31, 2012. Because of Anadarko’s control of the Partnership through its ownership of our general partner, each acquisition of Partnership assets through March 31, 2012, except for the acquisitions of the Platte Valley assets and the 9.6% interest in White Cliffs from third parties, was considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko are initially recorded at Anadarko’s historic carrying value, the value of which does not correlate to the total acquisition price paid by the Partnership (see Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q). Further, after each acquisition of assets from Anadarko, we are required to recast our financial statements to include the activities of the Partnership assets as of the date of common control. As such, our historical financial statements previously filed with the SEC have been recast in this Form 10-Q to include the results attributable to the Bison and MGR assets as if we owned such assets for all periods presented. The consolidated financial statements for periods prior to our acquisition of the Partnership assets have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported.

EQUITY OFFERINGS

Equity offerings. We completed the following public equity offerings during 2011:


thousands except unit and per-unit amounts	Common Units Issued ⁽¹⁾		GP Units Issued ⁽²⁾		Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
March 2011 equity offering		3,852,813		78,629	$	35.15	$	5,621	$	132,569
September 2011 equity offering		5,750,000		117,347		35.86		7,655		202,748

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

⁽²⁾	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% interest.

RESULTS OF OPERATIONS

OPERATING RESULTS

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


	Three Months Ended March 31,
thousands	2012		2011
Gathering, processing and transportation of natural gas and natural gas liquids	$	79,155	$	70,357
Natural gas, natural gas liquids and condensate sales		128,486		105,889
Equity income and other, net		4,601		4,596

Total revenues ⁽¹⁾		212,242		180,842
Total operating expenses ⁽¹⁾		154,401		129,870

Operating income		57,841		50,972
Interest income, net – affiliates		4,225		4,670
Interest expense		(9,581)		(6,111)
Other income (expense), net		458		2,152

Income before income taxes		52,943		51,683
Income tax expense		537		4,832

Net income		52,406		46,851
Net income attributable to noncontrolling interests		4,243		2,954

Net income attributable to Western Gas Partners, LP	$	48,163	$	43,897

Key Performance Metrics ⁽²⁾
Gross margin	$	129,086	$	113,659
Adjusted EBITDA attributable to Western Gas Partners, LP	$	84,819	$	74,908
Distributable cash flow	$	73,051	$	67,458

⁽¹⁾

Revenues include affiliate amounts earned by the Partnership from services provided to our affiliates, as well as from the sale of residue gas, condensate and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽²⁾

Gross margin, Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) and Distributable cash flow are defined under the caption Operating Results within this Item 2. Such caption also includes reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable 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, 2012” refer to the comparison of the three months ended March 31, 2012, to the three months ended March 31, 2011.

Operating Statistics


	Three Months Ended March 31,
throughput in MMcf/d	2012		2011		D
Gathering, treating and transportation ⁽¹⁾		1,298		1,366	(5)%
Processing ⁽²⁾		1,150		851	35%
Equity investment ⁽³⁾		236		187	26%

Total throughput ⁽⁴⁾		2,684		2,404	12%
Throughput attributable to noncontrolling interests		270		218	24%

Total throughput attributable to Western Gas Partners, LP		2,414		2,186	10%

⁽¹⁾	Excludes average NGL pipeline volumes from the Chipeta assets of 27 MBbls/d and 22 MBbls/d for the three months ended March 31, 2012 and 2011, respectively.

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

⁽³⁾	Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes and excludes 5 MBbls/d and 3 MBbls/d of oil pipeline volumes for the three months ended March 31, 2012 and 2011, respectively, representing our 10% share of average White Cliffs pipeline volumes.

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

Gathering, treating and transportation throughput decreased by 68 MMcf/d for the three months ended March 31, 2012, resulting from throughput decreases at Bison due to lower third-party volumes and facility optimization, and throughput decreases at the Haley, Pinnacle, Hugoton and Dew systems resulting from natural production declines and reduced drilling activity in those areas, partially offset by throughput increases at Wattenberg due to increased drilling behind the system.

Processing throughput increased by 299 MMcf/d for the three months ended March 31, 2012, primarily due to the additional throughput from the Platte Valley system beginning in March 2011; throughput increases at the Chipeta system, resulting from increased drilling activity in these areas driven by the relatively high liquid content of the gas volumes produced; and volumes from a plant included in the MGR acquisition, following the commencement of a new processing agreement at that plant beginning in May 2011.

Equity investment volumes increased by 49 MMcf/d for the three months ended March 31, 2012, resulting from higher throughput at the Fort Union and Rendezvous systems due to producers choosing to route additional gas through the systems.

Natural Gas Gathering, Processing and Transportation Revenues

Three Months Ended
March 31,

thousands except percentages

2012

2011

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

79,155

70,357

13%

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $8.8 million for the three months ended March 31, 2012, due to the acquisition of the Platte Valley system in February 2011 and increased drilling activity in the Chipeta and Wattenberg areas. These increases were partially offset by decreased revenue at Granger due to diverted volumes.

Natural Gas, Natural Gas Liquids and Condensate Sales


	Three Months Ended March 31,
thousands except percentages and per-unit amounts	2012		2011		D

Natural gas sales	$	25,558	$	26,595	(4)%
Natural gas liquids sales		91,516		71,041	29%
Drip condensate sales		11,412		8,253	38%

Total	$	128,486	$	105,889	21%

Average price per unit:
Natural gas (per Mcf)	$	4.28	$	5.35	(20)%
Natural gas liquids (per Bbl)	$	48.07	$	46.35	4%
Drip condensate (per Bbl)	$	76.09	$	73.08	4%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $22.6 million for the three months ended March 31, 2012, which consisted of a $20.5 million increase in NGLs sales and a $3.2 million increase in drip condensate sales, partially offset by a $1.0 million decrease in natural gas sales.

The increase in NGLs sales was primarily due to a 16% increase in volumes sold resulting from the acquisition of the Platte Valley system in February 2011 and higher throughput at the Granger, Wattenberg, Hilight and Chipeta systems. The increase in NGL sales was also attributable to a 4% increase in NGLs sales prices.

The increase in drip condensate sales for the three months ended March 31, 2012, was primarily due to higher average sales price and volumes at the Wattenberg system, along with Platte Valley sales beginning March 2011.

The decrease in natural gas sales was due to a 20% decrease in natural gas sales prices, partially offset by a 20% increase in volumes sold.

The average natural gas and NGLs prices for the three months ended March 31, 2012, include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and the Red Desert complex. The average natural gas and NGLs prices for the three months ended March 31, 2011, include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Equity Income and Other Revenues


	Three Months Ended March 31,
thousands except percentages	2012		2011		D

Equity income	$	3,613	$	2,283	58%
Other revenues, net		988		2,313	(57)%

Total	$	4,601	$	4,596	—

Equity income increased by $1.3 million for the three months ended March 31, 2012, due to the increase in income from White Cliffs, Fort Union and Rendezvous due to increased volumes.

Other revenues decreased by $1.3 million for the three months ended March 31, 2012, primarily due to a change in gas imbalance positions at the Wattenberg system and indemnity fees received in the prior year at the Red Desert complex for not meeting volume requirements, with no comparable activity in the current period.

Cost of Product and Operation and Maintenance Expenses


	Three Months Ended March 31,
thousands except percentages	2012		2011		D
Cost of product	$	83,156	$	67,183		24%
Operation and maintenance		29,898		26,861		11%

Total cost of product and operation and maintenance expenses	$	113,054	$	94,044		20%

Including the effects of commodity price swap agreements on purchases, cost of product expense increased by $16.0 million for the three months ended March 31, 2012, primarily consisting of a $11.6 million increase due to increased throughput at the Chipeta, Granger and Wattenberg systems, and a $5.1 million increase due to the acquisition of the Platte Valley system in February 2011.

Cost of product expense for the three months ended March 31, 2012, include the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and at the Red Desert complex. Cost of product expense for the three months ended March 31, 2011, include the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle, and Wattenberg systems. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Operation and maintenance expense increased by $3.0 million for the three months ended March 31, 2012, primarily due to the acquisition of the Platte Valley system and increased maintenance expenses incurred at the Wattenberg system, partially offset by reduced variable operating expenses at the Red Desert complex resulting from decreased throughput activity compared to the same period in the prior year.

General and Administrative, Depreciation and Other Expenses


	Three Months Ended March 31,
thousands except percentages	2012		2011		D
General and administrative	$	9,924	$	7,862		26%
Property and other taxes		4,837		4,321		12%
Depreciation, amortization and impairments		26,586		23,643		12%

Total general and administrative, depreciation and other expenses	$	41,347	$	35,826		15%

General and administrative expenses increased by $2.1 million for three months ended March 31, 2012, due to an increase of $2.8 million in noncash payroll expenses primarily due to an increase in the value of equity-based awards and an increase of $1.4 million in corporate and management personnel costs allocated to us pursuant to the omnibus agreement. These increases were partially offset by a decrease of $1.8 million in management fees allocated to the Bison and MGR assets and discontinued effective the respective date of contribution. Property and other taxes increased by $0.5 million for the three months ended March 31, 2012, primarily due to the ad valorem tax for the Platte Valley and Wattenberg assets. Depreciation, amortization and impairments increased by $2.9 million for the three months ended March 31, 2012, primarily attributable to the addition of the Platte Valley assets, and depreciation associated with capital projects completed at the Wattenberg, Granger and Hilight systems, and at the Red Desert complex.

Interest Income, Net – Affiliates and Interest Expense


	Three Months Ended March 31,
thousands except percentages	2012		2011		D
Interest income on note receivable	$	4,225	$	4,225		—	%
Interest income, net on affiliate balances⁽²⁾		—		445		(100	)%

Interest income, net – affiliates	$	4,225	$	4,670		(10	)%


Third Parties
Interest expense on long-term debt	$	(7,915)	$	(2,676)		196	%
Amortization of debt issuance costs and commitment fees⁽³⁾		(1,008)		(2,201)		(54	)%
Capitalized interest		657		—		nm	⁽¹⁾
Affiliates
Interest expense on notes payable to Anadarko		(1,234)		(1,234)		—	%
Interest expense, net on affiliate balances		(81)		—		nm

Interest expense	$	(9,581)	$	(6,111)		57	%

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

⁽²⁾

Incurred on affiliate balances related to the Bison and MGR assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Bison and MGR assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

⁽³⁾	For the three months ended March 31, 2012, includes $0.2 million of amortization of the original issue discount and underwriters’ fees related to the Notes.

Interest expense increased by $3.5 million for the three months ended March 31, 2012, due to interest expense incurred on the Notes issued in May 2011. The increase was partially offset by lower interest expense resulting from the early repayment of the Wattenberg term loan in March 2011 and the related $1.3 million of accelerated amortization expense recognized in March 2011 (described in Liquidity and Capital Resources below).

See Note 7. 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

2012

2011

Other income (expense), net

458

2,152

(79)%

Other income (expense), net includes $0.4 million for each of the three months ended March 31, 2012 and 2011, of interest income related to a capital lease. In addition, other income (expense), net for the three months ended March 31, 2011, includes a $1.7 million unrealized gain for a forward-starting interest-rate swap agreement entered into in March 2011. See Note 2—Acquisitions and Note 7—Debt and Interest Expense included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Form 10-Q.

Income Tax Expense


	Three Months Ended March 31,
thousands except percentages	2012		2011		D
Income before income taxes	$	52,943	$	51,683		2	%
Income tax expense		537		4,832		(89	)%
Effective tax rate		1%		9%

We are not a taxable entity for U.S. federal income tax purposes, although the portion of our income apportionable to Texas is subject to Texas margin tax. Income attributable to (a) the MGR assets prior to and including January 2012 and (b) the Bison assets prior to and including June 2011 were subject to federal and state income tax, resulting in the lower income tax expense for the three months ended March 31, 2012. Income earned by the Bison and MGR assets for periods subsequent to June 2011 and January 2012, respectively, was subject only to Texas margin tax on the portion of their incomes apportionable to Texas.

For 2012 and 2011, our variance from the federal statutory rate, which is zero percent as a non-taxable entity, is primarily attributable to federal and state taxes on income attributable to Partnership assets pre-acquisition and our share of Texas margin tax.

Noncontrolling Interests

Three Months Ended
March 31,

thousands except percentages

2012

2011

Net income attributable to noncontrolling interests

4,243

2,954

44%

For the three months ended March 31, 2012, net income attributable to noncontrolling interests increased by $1.3 million primarily due to the higher volumes at the Chipeta system.

Key Performance Metrics


thousands except percentages	Three Months Ended March 31,
and gross margin per Mcf	2012		2011		D
Gross margin	$	129,086	$	113,659		14%
Gross margin per Mcf ⁽¹⁾		0.53		0.53		—
Gross margin per Mcf attributable to Western Gas Partners, LP⁽²⁾		0.56		0.55		2%
Adjusted EBITDA attributable to Western Gas Partners, LP⁽³⁾		84,819		74,908		13%
Distributable cash flow⁽³⁾	$	73,051	$	67,458		8%

⁽¹⁾

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

⁽²⁾

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

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

Gross margin and Gross margin per Mcf. Gross margin increased by $15.4 million for the three months ended March 31, 2012, primarily due to higher margins at the Wattenberg, Chipeta and Granger systems, due to an increase in volumes (and/or including the impact of commodity price swap agreements at the Wattenberg and Granger systems); the execution of a new gas processing agreement at a plant included in the MGR acquisition; and the acquisition of the Platte Valley system in February 2011. These increases were partially offset by lower gross margins at the Red Desert complex due to decreased volumes resulting from natural production declines in the area. For the three months ended March 31, 2012, gross margin per Mcf attributable to Western Gas Partners, LP increased by 2%, primarily due to increased volumes at the Chipeta system.

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

•

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

•

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

•

the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities

Adjusted EBITDA increased by $9.9 million for the three months ended March 31, 2012, primarily due to a $30.1 million increase in total revenues excluding equity income and a $0.5 million increase in distributions from equity investees, partially offset by a $16.0 million increase in cost of product, a $3.0 million increase in operation and maintenance expenses, a $1.3 million increase in net income attributable to noncontrolling interests, and a $0.5 million increase in property and other taxes expense.

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

Distributable cash flow should not be considered an alternative to net income, earnings per unit, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Furthermore, while Distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period.

Distributable cash flow increased by $5.6 million for the three months ended March 31, 2012, primarily due to the $9.9 million increase in Adjusted EBITDA, partially offset by a $4.0 million increase in net cash paid for interest expense, a $0.2 million increase in cash paid for maintenance capital expenditures and a $0.1 million increase in cash paid for income taxes.

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

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	2012			2011
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	84,819		$	74,908
Less:
Distributions from equity investees		4,441			3,909
Non-cash equity-based compensation expense		4,066			1,928
Interest expense		9,581			6,111
Income tax expense		537			4,832
Depreciation, amortization and impairments ⁽¹⁾		25,931			22,938
Add:
Equity income, net		3,613			2,283
Interest income, net – affiliates		4,225			4,670
Other income ^{(1) (2)}		62			1,754

Net income attributable to Western Gas Partners, LP	$	48,163		$	43,897


Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	84,819		$	74,908
Adjusted EBITDA attributable to noncontrolling interests		4,898			3,658
Interest income (expense), net		(5,356	)		(1,441	)
Non-cash equity-based compensation expense		(4,066	)		(1,928	)
Current income tax expense		(60	)		(2,379	)
Other income (expense), net⁽²⁾		62			1,755
Distributions from equity investees less than (in excess of) equity income, net		(828	)		(1,626	)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		4,832			(10,022	)
Accounts payable, accrued liabilities and natural gas imbalance payable		9,245			7,308
Other		1,020			1,737

Net cash provided by operating activities	$	94,566		$	71,970

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

⁽²⁾	Excludes income of $0.4 million for each of the three months ended March 31, 2012 and 2011, related to a component of a gas processing agreement accounted for as a capital lease. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.


	Three Months Ended March 31,
thousands except Coverage ratio	2012			2011

Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP
Distributable cash flow	$	73,051		$	67,458
Less:
Distributions from equity investees		4,441			3,909
Non-cash equity-based compensation expense		4,066			1,928
Interest expense, net (non-cash settled)		81			—
Income tax expense		537			4,832
Depreciation, amortization and impairments ⁽¹⁾		25,931			22,938
Add:
Equity income, net		3,613			2,283
Cash paid for maintenance capital expenditures ⁽¹⁾		5,764			5,564
Capitalized interest		657			—
Cash paid for income taxes		72			—
Other income^{(1) (2)}		62			1,754
Interest income, net (non-cash settled)		—			445

Net income attributable to Western Gas Partners, LP	$	48,163		$	43,897


Distribution declared for the three months ended March 31, 2012 ⁽³⁾
Limited partners		41,756
General partner		4,297

Total	$	46,053

Coverage ratio		1.59	x

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

⁽²⁾	Excludes income of $0.4 million for each of the three months ended March 31, 2012 and 2011, related to a component of a gas processing agreement accounted for as a capital lease. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽³⁾	Reflects distributions of $0.46 per unit declared for the three months ended March 31, 2012.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and other capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owners. Our sources of liquidity as of March 31, 2012, include 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 the sources above will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders and have increased our quarterly distribution each quarter since the second quarter of 2009. On April 19, 2012, the board of directors of our general partner declared a cash distribution to our unitholders of $0.46 per unit, or $46.1 million in aggregate, including incentive distributions. The cash distribution is payable on May 14, 2012, to unitholders of record at the close of business on April 30, 2012.

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

Working capital. As of March 31, 2012, we had a $55.6 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 is a deficit as of March 31, 2012, primarily due to our repayment of $40 million of debt on our revolving credit facility in March 2012 and the $18.9 million cost reimbursement agreement related to the Brasada and Lancaster plants described in Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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	2012		2011
Acquisitions	$	463,232	$	303,602

Expansion capital expenditures	$	55,307	$	15,446
Maintenance capital expenditures		5,764		5,564

Total capital expenditures ⁽¹⁾	$	61,071	$	21,010

Capital incurred ⁽²⁾	$	97,765	$	17,083

⁽¹⁾

Capital expenditures for the three months ended March 31, 2011, includes $7.0 million of pre-acquisition capital expenditures for the MGR and Bison assets and includes the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners. Capital expenditures for the three months ended March 31, 2012, excludes $0.7 million of capitalized interest.

⁽²⁾	Capital incurred for the three months ended March 31, 2011, includes $3.8 million of pre-acquisition capital incurred for the MGR and Bison assets and includes the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

Acquisitions include the MGR, Bison and Platte Valley acquisitions as outlined 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 $40.1 million for the three months ended March 31, 2012. Expansion capital expenditures increased by $39.9 million for the three months ended March 31, 2012, primarily due to an increase of $29.0 million in expenditures at our Chipeta, Wattenberg and Platte Valley systems, and $15.5 million related to the construction of the Brasada and Lancaster gas processing facilities. These increases were partially offset by a $5.3 million decrease related to the Bison assets, due to the continued startup costs incurred in early 2011. Maintenance capital expenditures increased by $0.2 million, primarily as a result of higher well connects at the Platte Valley, Granger and Hilight systems, partially offset by improvements at the Hugoton and Dew systems, completed during 2011.

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


	Three Months Ended March 31,
thousands	2012		2011
Net cash provided by (used in):
Operating activities	$	94,566	$	71,970
Investing activities		(524,303)		(324,552)
Financing activities		242,796		256,349

Net increase (decrease) in cash and cash equivalents	$	(186,941)	$	3,767

Operating Activities. Net cash provided by operating activities increased by $22.6 million for the three months ended March 31, 2012, primarily due to the following items:

•

a $30.1 million increase in revenues, excluding equity income;

•

a $14.6 million increase due to changes in accounts receivable balances; and

•

a $2.3 million decrease in current income tax expense.

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

•

a $16.0 million increase in cost of product expense;

•

a $3.5 million increase in interest expense;

•

a $3.0 million increase in operation and maintenance expenses;

•

a $1.5 million decrease due to changes in accounts payable balances and other items; and

•

a $0.5 million increase in property and other taxes expense.

Investing Activities. 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;

•

$61.1 million of capital expenditures; and

•

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

Net cash used in investing activities for the three months ended March 31, 2011, included the following:

•

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

•

$21.0 million of capital expenditures.

Financing Activities. Net cash provided by financing activities for the three months ended March 31, 2012, included the following:

•

$299.0 million of borrowings to fund the MGR acquisition.

Net contributions from Parent attributable to intercompany balances were $2.1 million during 2012, representing the settlement of intercompany transactions attributable to the Bison assets.

Net cash provided by financing activities for the three months ended March 31, 2011, included the following:

•

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

•

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

•

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

Proceeds from our March 2011 equity offering were used in the repayment of amounts outstanding under our RCF.

Net distributions to Parent attributable to pre-acquisition intercompany balances were $9.8 million during 2011, representing the net non-cash settlement of intercompany transactions attributable to the MGR and Bison assets.

For the three months ended March 31, 2012 and 2011, we paid $43.0 million and $30.6 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $9.8 million and $1.0 million during the three months ended March 31, 2012 and 2011, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $5.1 million and $4.4 million for the three months ended March 31, 2012 and 2011, respectively, representing the distributions for the fourth quarter of each preceding year.

Debt and credit facilities. As of March 31, 2012, our outstanding debt consisted of $279.0 million outstanding under our RCF, $494.3 million of the Notes and the $175.0 million note payable to Anadarko. See Note 7—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees will be released if the Subsidiary Guarantors are released from their obligations under our RCF. At March 31, 2012, we were in compliance with all covenants under the Notes.

The Notes and obligations under the RCF are recourse to our general partner. In turn, our general partner has been indemnified by a wholly owned Affiliate of Anadarko against any claims made against the general partner under the Notes and RCF. The foregoing description is qualified in its entirety by reference to the full text of the Indemnity Agreement, a copy of which is filed with this Form 10-Q as Exhibit 10.1, and is incorporated herein by reference.

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

The provisions of the five-year term loan agreement contain customary events of default, including (i) non-payment of principal when due or non-payment of interest or other amounts within three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to the Partnership and (iii) a change of control. At March 31, 2012, we were in compliance with all covenants under this agreement.

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

All amounts due under the RCF are unconditionally guaranteed by our wholly owned subsidiaries. As of March 31, 2012, $279.0 million was outstanding under the RCF, and $521.0 million was available for borrowing. At March 31, 2012, we were in compliance with all covenants under the RCF. As discussed above in the paragraph describing the Notes, our obligations under the RCF are recourse to our general partner.

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

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

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

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

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

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

CONTRACTUAL OBLIGATIONS

Our contractual obligations include, among other things, a note payable to Anadarko, a revolving credit facility, other third-party long-term debt, a corporate office lease and warehouse lease, for which information is provided in Note 7—Debt and Interest Expense and Note 8—Commitments and Contingencies included in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q. Our contractual obligations have not changed significantly since December 31, 2011.

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 8—Commitments and Contingencies included in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

RECENT ACCOUNTING DEVELOPMENTS

Recently adopted accounting standard. In May 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU is to be applied prospectively and is effective for periods beginning after December 15, 2011. We adopted the ASU effective January 1, 2012. The adoption of the requirements of the ASU, which expanded disclosures, had no effect on our results of operations or financial position.

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 fixed-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% change in natural gas or NGL prices to have a material direct 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 2011 and the three months ended March 31, 2012 were low compared to historic rates. As of March 31, 2012, we owed $279.0 million under our RCF at a variable rate based on LIBOR. If interest rates rise, our future financing costs could increase if we incur borrowings under our RCF. For the three months ended March 31, 2012, a 10% change in LIBOR would have resulted in a nominal change in net income.

We may incur additional 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, 2012.

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, 2012, 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, 2011, together with all of the other information included in this document; the Partnership’s Form 10-K; and in our other public filings, press releases, and 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, 2011, Anadarko’s quarterly reports on Form 10-Q and Anadarko’s other public filings, press releases and 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.

Recently approved final rules regulating air emissions from natural gas processing operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA approved final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. Among other things, the rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering and boosting stations and processing plants together with dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering and boosting stations. In addition, the rules establish new requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500 parts per million in concentration. We are currently reviewing this new rule and assessing its potential impacts. Compliance with these requirements may require modifications to certain of our operations, including the installation of new equipment to control emissions from our compressors that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

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).
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		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).
3.11		Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated as of May 14, 2008 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, 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).
10.1*		Indemnification Agreement dated May 18, 2011, between Western Gas Holdings, LLC and Western Gas Resources, Inc.
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.

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 3, 2012

		/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 3, 2012

		/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)