Edgar Filing: Western Gas Partners LP

Form 10-Q for quarterly period ended June 30, 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 June 30, 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		77380
The Woodlands, Texas		(Zip Code)
(Address of principal executive offices)

(832) 636-6000

(Registrant’s telephone number, including area code)

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

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

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


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

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

There were 95,783,116 common units outstanding as of July 31, 2012.

TABLE OF CONTENTS


PART I		FINANCIAL INFORMATION	PAGE

	Item 1.	Financial Statements

		Consolidated Statements of Income for the three and six months ended June 30, 2012 and 2011	4

		Consolidated Balance Sheets as of June 30, 2012, and December 31, 2011	5

		Consolidated Statement of Equity and Partners’ Capital for the six months ended June 30, 2012	6

		Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	7

		Notes to Consolidated Financial Statements	8

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

		Cautionary Note Regarding Forward-Looking Statements	21

		Executive Summary	23

		Acquisitions	24

		Equity Offerings	25

		Results of Operations	26

		Operating Results	26

		Liquidity and Capital Resources	35

		Contractual Obligations	40

		Off-Balance Sheet Arrangements	40

		Recent Accounting Developments	40

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41

	Item 4.	Controls and Procedures	41

PART II		OTHER INFORMATION

	Item 1.	Legal Proceedings	42

	Item 1A.	Risk Factors	42

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42

	Item 6.	Exhibits	43

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 June 30,				Six Months Ended June 30,
thousands except per-unit amounts	2012		2011 ⁽¹⁾		2012		2011 ⁽¹⁾
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	56,110	$	54,578	$	113,002	$	107,114
Natural gas, natural gas liquids and condensate sales		104,008		104,813		209,661		192,498
Equity income and other, net		4,133		3,672		8,134		6,618

Total revenues – affiliates		164,251		163,063		330,797		306,230
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		22,365		21,811		44,628		39,632
Natural gas, natural gas liquids and condensate sales		18,218		23,238		41,051		41,442
Other, net		507		1,568		1,107		3,218

Total revenues – third parties		41,090		46,617		86,786		84,292

Total revenues		205,341		209,680		417,583		390,522

Operating expenses
Cost of product ⁽²⁾		82,456		83,916		165,612		151,099
Operation and maintenance ⁽²⁾		33,882		29,225		63,780		56,086
General and administrative ⁽²⁾		9,755		8,171		19,679		16,033
Property and other taxes		4,833		4,352		9,670		8,673
Depreciation, amortization and impairments		27,156		25,835		53,742		49,478

Total operating expenses		158,082		151,499		312,483		281,369

Operating income		47,259		58,181		105,100		109,153
Interest income, net – affiliates		4,225		5,749		8,450		10,419
Interest expense ⁽³⁾		(9,560)		(6,697)		(19,141)		(12,808)
Other income (expense), net		(1,267)		(3,305)		(809)		(1,153)

Income before income taxes		40,657		53,928		93,600		105,611
Income tax expense		90		6,064		627		10,896

Net income		40,567		47,864		92,973		94,715
Net income attributable to noncontrolling interests		4,290		2,838		8,533		5,792

Net income attributable to Western Gas Partners, LP	$	36,277	$	45,026	$	84,440	$	88,923

Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	36,277	$	45,026	$	84,440	$	88,923
Pre-acquisition net (income) loss allocated to Parent		—		(11,087)		—		(20,000)
General partner interest in net (income) loss ⁽⁴⁾		(6,127)		(1,842)		(10,466)		(3,290)

Limited partners’ interest in net income ⁽⁴⁾	$	30,150	$	32,097	$	73,974	$	65,633
Net income per common unit – basic and diluted	$	0.33	$	0.40	$	0.81	$	0.83
Net income per subordinated unit – basic and diluted ⁽⁵⁾	$	—	$	0.38	$	—	$	0.79

⁽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 $39.3 million and $72.8 million for the three and six months ended June 30, 2012, respectively, and $19.5 million and $36.9 million for the three and six months ended June 30, 2011, respectively. Operation and maintenance includes charges from Anadarko of $12.9 million and $25.4 million for the three and six months ended June 30, 2012, respectively, and $13.1 million and $25.1 million for the three and six months ended June 30, 2011, respectively. General and administrative includes charges from Anadarko of $7.2 million and $15.7 million for the three and six months ended June 30, 2012, respectively, and $6.3 million and $12.5 million for the three and six months ended June 30, 2011, respectively. See Note 5.

⁽³⁾	Includes Affiliate (as defined in Note 1) interest expense of $1.3 million and $2.6 million for the three and six months ended June 30, 2012, respectively, and $1.2 million and $2.5 million for the three and six months ended June 30, 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	June 30, 2012		December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	258,052	$	226,559
Accounts receivable, net		19,674		22,703
Other current assets ⁽¹⁾		5,732		7,186

Total current assets		283,458		256,448
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		2,866,566		2,638,013
Less accumulated depreciation		642,253		585,789

Net property, plant and equipment		2,224,313		2,052,224
Goodwill		82,136		82,136
Other intangible assets		52,320		52,858
Equity investments		107,446		109,817
Other assets		26,526		24,143

Total assets	$	3,036,199	$	2,837,626

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables ⁽²⁾	$	40,461	$	26,600
Accrued ad valorem taxes		9,717		8,186
Income taxes payable		548		495
Accrued liabilities ⁽³⁾		107,635		41,315

Total current liabilities		158,361		76,596
Long-term debt – third parties		1,010,228		494,178
Note payable – Anadarko		—		175,000
Deferred income taxes		1,375		107,377
Asset retirement obligations and other		69,048		67,169

Total long-term liabilities		1,080,651		843,724

Total liabilities		1,239,012		920,320
Equity and partners’ capital
Common units (95,783,116 and 90,140,999 units issued and outstanding at June 30, 2012, and December 31, 2011, respectively)		1,617,196		1,495,253
General partner units (1,954,759 and 1,839,613 units issued and outstanding at June 30, 2012, and December 31, 2011, respectively)		39,758		31,729
Parent net investment		—		269,600

Total partners’ capital		1,656,954		1,796,582
Noncontrolling interests		140,233		120,724

Total equity and partners’ capital		1,797,187		1,917,306

Total liabilities, equity and partners’ capital	$	3,036,199	$	2,837,626

⁽¹⁾	Other current assets includes natural gas imbalance receivables from affiliates of $0.3 million and $0.5 million as of June 30, 2012, and December 31, 2011, respectively.

⁽²⁾	Accounts and natural gas imbalance payables includes amounts payable to affiliates of $23.2 million and $5.9 million as of June 30, 2012, and December 31, 2011, respectively.

⁽³⁾	Accrued liabilities include amounts payable to affiliates of $18.9 million and $0.3 million as of June 30, 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	$	269,600	$	1,495,253	$	31,729	$	120,724	$	1,917,306
Net income		—		73,974		10,466		8,533		92,973
Issuance of common and general partner units, net of offering expenses		—		212,096		4,478		—		216,574
Contributions from noncontrolling interest owners		—		—		—		21,315		21,315
Distributions to noncontrolling interest owners		—		—		—		(10,339)		(10,339)
Distributions to unitholders		—		(81,697)		(7,383)		—		(89,080)
Acquisition from affiliates		(482,701)		23,458		479		—		(458,764)
Contributions of equity-based compensation from Parent		—		1,896		39		—		1,935
Net pre-acquisition contributions from (distributions to) Parent		106,597		(106,597)		—		—		—
Net distributions of other assets to Parent		—		(4,046)		(50)		—		(4,096)
Elimination of net deferred tax liabilities		106,504		—		—		—		106,504
Non-cash equity-based compensation and other		—		2,859		—		—		2,859

Balance at June 30, 2012	$	—	$	1,617,196	$	39,758	$	140,233	$	1,797,187

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Six Months Ended June 30,
thousands	2012			2011 ⁽¹⁾
Cash flows from operating activities
Net income	$	92,973		$	94,715
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		53,742			49,478
Deferred income taxes		502			5,491
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		5,803			(20,313)
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net		8,820			14,058
Change in other items, net		4,250			4,809

Net cash provided by operating activities		166,090			148,238
Cash flows from investing activities
Capital expenditures		(147,058)			(38,150)
Acquisitions from affiliates		(465,507)			—
Acquisitions from third parties		—			(303,602)
Investments in equity affiliates		—			(93)
Proceeds from sale of assets to affiliates		—			242

Net cash used in investing activities		(612,565	)		(341,603	)
Cash flows from financing activities
Borrowings, net of debt issuance costs		886,369			1,045,939
Repayments of debt		(549,000)			(859,000)
Proceeds from issuance of common and general partner units, net of offering expenses		216,574			132,569
Distributions to unitholders		(89,080)			(63,732)
Contributions from noncontrolling interest owners		21,315			7,389
Distributions to noncontrolling interest owners		(10,339)			(7,495)
Net contributions from (distributions to) Parent		2,129			(26,684)

Net cash provided by financing activities		477,968			228,986

Net increase (decrease) in cash and cash equivalents		31,493			35,621
Cash and cash equivalents at beginning of period		226,559			27,074

Cash and cash equivalents at end of period	$	258,052		$	62,695

Supplemental disclosures
Elimination of net deferred tax liabilities	$	106,504		$	—
Transfer of Brasada and Lancaster capital expenditures	$	19,197		$	—
Net distributions of other assets to Parent	$	4,096		$	—
Increase (decrease) in accrued capital expenditures	$	54,171		$	2,885
Interest paid	$	18,186		$	8,271
Interest received	$	8,450		$	8,450
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 June 30, 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 for 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 of June 30, 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. See Note 9.

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 June 30, 2012, and December 31, 2011, results of operations for the three and six months ended June 30, 2012 and 2011, statement of equity and partners’ capital for the six months ended June 30, 2012, and statements of cash flows for the six months ended June 30, 2012 and 2011. The Partnership’s financial results for the three and six months ended June 30, 2012, are not necessarily indicative of the expected results for the full year ending December 31, 2012.

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, utilizing historical experience and other methods considered reasonable under the particular circumstances. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates.

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, certain sections of which have been recast to reflect the results of the MGR assets (as defined in Note 2) in the Partnership’s Current Report on Form 8-K, as filed with the SEC on May 22, 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.

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.

Chipeta acquisition. Subsequent to June 30, 2012, the Partnership acquired Anadarko’s remaining 24% membership interest in Chipeta, bringing its total membership interest in Chipeta to 75%. See Note 9.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2.	ACQUISITIONS (CONTINUED)

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:


thousands except per-unit amount	Six Months Ended June 30, 2011
Revenues	$	406,561
Net income		97,441
Net income attributable to Western Gas Partners, LP		91,649
Net income per common unit – basic and diluted	$	0.87

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.

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 June 30, 2011
thousands	Partnership Historical		Bison Assets		MGR Assets		Eliminations		Combined
Revenues	$	161,748	$	5,314	$	42,699	$	(81)	$	209,680
Net income		36,777		1,154		9,933		—		47,864

	Six Months Ended June 30, 2011
thousands	Partnership Historical		Bison Assets		MGR Assets		Eliminations		Combined
Revenues	$	297,741	$	10,906	$	81,970	$	(95)	$	390,522
Net income		74,715		2,781		17,219		—		94,715

MGR acquisition. Other assets on the Partnership’s consolidated balance sheets include a receivable of $0.6 million and $0.7 million as of June 30, 2012, and December 31, 2011, respectively, 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. For all periods presented, 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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
2011
March 31	$ 0.390	$ 33,168	May 2011
June 30	$ 0.405	$ 36,063	August 2011
2012
March 31	$ 0.460	$ 46,053	May 2012
June 30⁽¹⁾	$ 0.480	$ 52,425	August 2012

⁽¹⁾

On July 19, 2012, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.48 per unit, or $52.4 million in aggregate, including incentive distributions. The cash distribution is payable on August 13, 2012, to unitholders of record at the close of business on July 31, 2012.

4.	EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public equity offerings during 2011 and 2012:


thousands except unit and per-unit amounts	Common Units Issued ⁽¹⁾		GP Units Issued ⁽²⁾		Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
March 2011 equity offering		3,852,813		78,629	$	35.15	$	5,621	$	132,569
September 2011 equity offering		5,750,000		117,347		35.86		7,655		202,748
June 2012 equity offering		5,000,000		102,041		43.88		7,304		216,574

⁽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.

Common and general partner units. The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.” The following table summarizes common and general partner units issued during the six months ended June 30, 2012:

Common
Units

General
Partner Units

Total

Balance at December 31, 2011

90,140,999

1,839,613

91,980,612

MGR acquisition

632,783

12,914

645,697

Long-Term Incentive Plan Awards

9,334

191

9,525

June 2012 equity offering

5,000,000

102,041

5,102,041

Balance at June 30, 2012

95,783,116

1,954,759

97,737,875

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4.	EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Conversion of subordinated units. Upon payment of the cash distribution for the second quarter of 2011, the requirements for the conversion of all subordinated units were satisfied under the partnership agreement. As a result, the 26,536,306 subordinated units were converted 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 June 30, 2012, Anadarko indirectly held 1,954,759 general partner units representing a 2.0% general partner interest in the Partnership, 40,422,004 common units representing a 41.4% limited partner interest, and 100% of the Partnership’s incentive distribution rights. The public held 55,361,112 common units, representing a 56.6% 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 June 30,				Six Months Ended June 30,
thousands except per-unit amounts	2012		2011		2012		2011
Net income attributable to Western Gas Partners, LP	$	36,277	$	45,026	$	84,440	$	88,923
Pre-acquisition net (income) loss allocated to Parent		—		(11,087)		—		(20,000)
General partner interest in net (income) loss		(6,127)		(1,842)		(10,466)		(3,290)

Limited partners’ interest in net income	$	30,150	$	32,097	$	73,974	$	65,633


Net income allocable to common units	$	30,150	$	22,028	$	73,974	$	44,615
Net income allocable to subordinated units		—		10,069		—		21,018

Limited partners’ interest in net income	$	30,150	$	32,097	$	73,974	$	65,633


Net income per unit – basic and diluted
Common units	$	0.33	$	0.40	$	0.81	$	0.83
Subordinated units	$	—	$	0.38	$	—	$	0.79

Weighted average units outstanding – basic and diluted
Common units		91,272		54,896		90,981		53,528
Subordinated units		—		26,536		—		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. Chipeta cash settles transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

Note receivable from and amounts payable to Anadarko. Concurrent with the closing of the Partnership’s May 2008 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 $261.6 million and $303.7 million at June 30, 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, which was repaid in full in June 2012 using the proceeds from the 4.000% Senior Notes due 2022 (the “2022 Notes”). 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 June 30, 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 June 30,				Six Months Ended June 30,
thousands	2012		2011		2012		2011
Gains (losses) on commodity price swap agreements related to sales: ⁽¹⁾
Natural gas sales	$	11,746	$	8,992	$	21,596	$	15,800
Natural gas liquids sales		19,680		(10,677)		20,034		(16,518)

Total		31,426		(1,685)		41,630		(718)
Losses on commodity price swap agreements related to purchases ⁽²⁾		(27,347)		(6,670)		(44,539)		(12,876)

Net gains (losses) on commodity price swap agreements	$	4,079	$	(8,355)	$	(2,909)	$	(13,594)

⁽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 75% of the Partnership’s gathering, transportation and treating throughput for the three months ended June 30, 2012 and 2011, respectively, and 76% and 74% for the six months ended June 30, 2012 and 2011, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 59% and 64% of the Partnership’s processing throughput for the three months ended June 30, 2012 and 2011, respectively, and 59% and 64% for the six months ended June 30, 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) the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) and (ii) the Anadarko Petroleum Corporation 1999 Stock Incentive Plan and the Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”).

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5.	TRANSACTIONS WITH AFFILIATES (CONTINUED)

Under the Incentive Plan, participants are granted Unit Value Rights (“UVRs”), Unit Appreciation Rights (“UARs”) and Dividend Equivalent Rights (“DERs”). UVRs and UARs outstanding under the Incentive Plan were collectively valued at $757.00 per unit and $634.00 per unit as of June 30, 2012, and December 31, 2011, respectively. The Partnership’s general and administrative expense included approximately $2.9 million and $7.0 million for the three and six months ended June 30, 2012, respectively, and $1.9 million and $3.9 million for the three and six months ended June 30, 2011, respectively, of allocated equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans.

Equipment purchase. In June 2012, the Partnership purchased equipment with a net carrying value of $1.2 million from Anadarko for $2.2 million in cash, with the difference recorded as an adjustment to Partners’ capital. 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 June 30, 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
June 30,

Six Months Ended
June 30,

thousands

2012

2011

2012

2011

Revenues ⁽¹⁾

164,251

163,063

330,797

306,230

Cost of product ⁽¹⁾

39,338

19,517

72,764

36,908

Operation and maintenance ⁽²⁾

12,929

13,127

25,402

25,065

General and administrative ⁽³⁾

7,196

6,315

15,679

12,515

Operating expenses

59,463

38,959

113,845

74,488

Interest income, net ⁽⁴⁾

4,225

5,749

8,450

10,419

Interest expense ⁽⁵⁾

1,288

1,233

2,603

2,467

Distributions to unitholders ⁽⁶⁾

22,891

15,779

43,763

30,864

Contributions from noncontrolling interest owners

5,616

2,659

10,440

3,619

Distributions to noncontrolling interest owners

2,544

1,533

5,064

4,547

⁽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. In June 2012, the note payable to Anadarko was repaid in full. See Note 7.

⁽⁶⁾	Represents distributions paid under the partnership agreement.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5.	TRANSACTIONS WITH AFFILIATES (CONTINUED)

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.

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

June 30, 2012

December 31, 2011

Land

n/a

501

364

Gathering systems

5 to 47 years

2,483,617

2,437,152

Pipelines and equipment

15 to 45 years

91,011

90,883

Assets under construction

n/a

284,882

104,687

Other

3 to 25 years

6,555

4,927

Total property, plant and equipment

2,866,566

2,638,013

Accumulated depreciation

642,253

585,789

Net property, plant and equipment

2,224,313

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 $69.1 million and $15.0 million of accrued capital as of June 30, 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 June 30, 2012, and December 31, 2011:


	June 30, 2012						December 31, 2011
thousands	Principal		Carrying Value		Fair Value		Principal		Carrying Value		Fair Value
4.000% Senior Notes due 2022	$	520,000	$	515,812	$	519,951	$	—	$	—	$	—
5.375% Senior Notes due 2021		500,000		494,416		499,950		500,000		494,178		499,950
Note payable to Anadarko		—		—		—		175,000		175,000		174,528

Total debt outstanding ⁽¹⁾	$	1,020,000	$	1,010,228	$	1,019,901	$	675,000	$	669,178	$	674,478

⁽¹⁾	The Partnership’s consolidated balance sheets include accrued interest expense of $2.4 million and $2.7 million as of June 30, 2012, and December 31, 2011, respectively, which is included in accrued liabilities.

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7.	DEBT AND INTEREST EXPENSE (CONTINUED)

Debt activity. The following table presents the debt activity of the Partnership for the six months ended June 30, 2012:


thousands	Carrying Value
Balance as of December 31, 2011	$	669,178
Revolving credit facility borrowings		374,000
Issuance of 4.000% Senior Notes due 2022		520,000
Repayment of revolving credit facility		(374,000)
Repayment of Note payable to Anadarko		(175,000)
Revolving credit facility borrowings – Swingline		20,000
Repayment of revolving credit facility – Swingline		(20,000)
Other and changes in debt discount		(3,950)

Balance as of June 30, 2012	$	1,010,228

4.000% Senior Notes due 2022. In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of the 2022 Notes at a price to the public of 99.194% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 4.189%. Interest will be paid semi-annually on January 1 and July 1 of each year, commencing on January 1, 2013. The 2022 Notes will mature on July 1, 2022, unless redeemed, in whole or in part, at any time prior to maturity, at a redemption price that includes a make-whole premium. Proceeds (net of underwriting discount of $3.4 million and debt issuance costs) were used to repay all amounts then outstanding under the Partnership’s revolving credit facility (“RCF”) and the $175.0 million note payable to Anadarko (see below).

The 2022 Notes indenture contains customary events of default including, among others, (i) default for 30 days in the payment of interest when due on the 2022 Notes; (ii) default in payment, when due, of principal of or premium, if any, on the 2022 Notes at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency. The 2022 Notes indenture also contains covenants that limit, among other things, the Partnership’s ability, as well as that of certain of its subsidiaries, to (i) create liens on its principal properties; (ii) engage in sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease or transfer substantially all of its properties or assets to another entity. At June 30, 2012, the Partnership was in compliance with all covenants under the 2022 Notes.

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 “2021 Notes”) at a price to the public of 98.778% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%.

Upon issuance, the 2021 Notes were fully and unconditionally guaranteed on a senior unsecured basis by each of the Partnership’s wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees were immediately released on June 13, 2012, upon the Subsidiary Guarantors becoming released from their obligations under the RCF, as discussed below. At June 30, 2012, the Partnership was in compliance with all covenants under the 2021 Notes.

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

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 1.75% and 1.80% at June 30, 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 June 30, 2012, and December 31, 2011.

On June 13, 2012, following the receipt of a second investment grade rating as defined in the RCF, the guarantees provided by the Partnership’s wholly owned subsidiaries were released, and the Partnership is no longer subject to certain of the restrictive covenants associated with the RCF, including the maintenance of an interest coverage ratio and adherence to covenants that limit, among other things, the Partnership’s, and certain of the Partnership’s subsidiaries’ ability to dispose of assets and make certain investments or payments. As of June 30, 2012, there were no outstanding borrowings under the RCF and $800.0 million was available for borrowing. At June 30, 2012, the Partnership was in compliance with all remaining covenants under the RCF.

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

Wattenberg term loan. In connection with the Wattenberg acquisition, in August 2010 the Partnership borrowed $250.0 million under a three-year term loan from a group of banks (“Wattenberg term loan”). The Wattenberg term loan incurred interest at LIBOR plus a margin ranging from 2.50% to 3.50% depending on the Partnership’s consolidated leverage ratio as defined in the Wattenberg term loan agreement. The Partnership repaid the Wattenberg term loan in 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 agreements. In May 2012, the Partnership entered into U.S. Treasury Rate lock agreements to mitigate the risk of rising interest rates prior to the issuance of the 2022 Notes. The rate lock agreements were settled simultaneously with the issuance of the 2022 Notes in June 2012, realizing a loss of $1.7 million, which is included in other income (expense), net in the Partnership’s consolidated statements of income.

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7.	DEBT AND INTEREST EXPENSE (CONTINUED)

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


	Three Months Ended June 30,				Six Months Ended June 30,
thousands	2012		2011		2012		2011
Third Parties
Interest expense on long-term debt	$	8,202	$	4,474	$	16,117	$	7,150
Amortization of debt issuance costs and commitment fees⁽¹⁾		1,016		1,003		2,024		3,204
Capitalized interest		(946)		(13)		(1,603)		(13)

Total interest expense – third parties		8,272		5,464		16,538		10,341

Affiliates
Interest expense on note payable to Anadarko⁽²⁾		1,206		1,233		2,440		2,467
Interest expense, net on affiliate balances		82		—		163		—

Total interest expense – affiliates		1,288		1,233		2,603		2,467

Interest expense	$	9,560	$	6,697	$	19,141	$	12,808

⁽¹⁾

Amortization of the original issue discount and underwriters’ fees related to the 2022 Notes and 2021 Notes was $0.2 million and $0.4 million for the three and six months ended June 30, 2012, respectively, and related to the 2021 Notes was $0.1 million for both the three and six months ended June 30, 2011.

⁽²⁾	In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 7.

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.

Other commitments. The Partnership has short-term payment obligations, or commitments, related to capital spending programs of the Partnership, as well as its unconsolidated affiliates. As of June 30, 2012, the Partnership had unconditional payment obligations for services to be rendered, or products to be delivered in connection with its capital projects of approximately $56.6 million, primarily related to the construction of a second cryogenic train at the Chipeta plant and the continued construction of the Brasada and Lancaster plants, a majority of which will be spent in 2012. See Note 5.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8.	COMMITMENTS AND CONTINGENCIES (CONTINUED)

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations. The leases for the 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 $0.8 million and $1.5 million for the three and six months ended June 30, 2012, respectively, and $1.0 million and $2.0 million for the three and six months ended June 30, 2011, respectively.

9.	SUBSEQUENT EVENT

On August 1, 2012, the Partnership closed on the acquisition of Anadarko’s remaining 24% membership interest in Chipeta, with the Partnership receiving distributions related to the additional interest beginning July 1, 2012. Subsequent to the acquisition, the Partnership held a 75% interest in Chipeta, with 25% held by a third-party member. Consideration paid for the 24% membership interest consisted of: (i) $128.3 million of cash on hand and (ii) the issuance of 151,235 common units and 3,086 general partner units. In connection with the acquisition, the Partnership also entered into Amendment No. 8 to the First Amended and Restated Agreement of Limited Partnership, effective August 1, 2012. As with previous acquisitions from Anadarko, the amendment permits the Partnership to make a special one-time cash distribution to an affiliate of Anadarko in an amount equal to the cash consideration. The foregoing description is qualified in its entirety by reference to the full text of the partnership agreement amendment, a copy of which is filed with this Quarterly Report on Form 10-Q as Exhibit 3.10.

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 have been recast to reflect the results of the acquisition of Mountain Gas Resources, LLC in our Current Report on Form 8-K, as filed with the Securities and Exchange Commission, or “SEC,” on May 22, 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 June 30, 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, the demand for, and the prices of, oil, natural gas, NGLs and other products or services;

•

the weather;

•

inflation;

•

the availability of goods and services, including downstream transportation and fractionation capacity;

•

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;

•

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

•

other factors discussed below, in “Risk Factors” included in our 2011 Form 10-K, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” included in our Current Report on Form 8-K filed May 22, 2012, our quarterly reports on Form 10-Q and elsewhere in our other public filings and press releases.

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

EXECUTIVE SUMMARY

We are a growth-oriented 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 its consolidated subsidiaries, as well as for third-party producers and customers. As of June 30, 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 six months of 2012 include the following:

•

We issued $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”). Net proceeds from this issuance were used to repay all amounts then outstanding under our revolving credit facility and the note payable to Anadarko, with the remaining net proceeds used for general partnership purposes. See Liquidity and Capital Resources below.

•

We issued 5,000,000 common units to the public, generating net proceeds of $216.6 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds will be used for general partnership purposes, including the funding of capital expenditures. See Equity Offerings below.

•

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.

•

We raised our distribution to $0.48 per unit for the second quarter of 2012, representing a 4% increase over the distribution for the first quarter of 2012, a 19% increase over the distribution for the second quarter of 2011, and our thirteenth consecutive quarterly increase.

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

•

Throughput attributable to Western Gas Partners, LP totaled 2,381 MMcf/d and 2,398 MMcf/d for the three and six months ended June 30, 2012, respectively, representing a 6% and 8% increase, respectively, compared to the same periods in 2011.

•

Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.54 per Mcf and $0.55 per Mcf for the three and six months ended June 30, 2012, respectively, representing an 8% and 4% decrease, respectively, compared to the same periods 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.

Chipeta acquisition. On August 1, 2012, we acquired Anadarko’s remaining 24% membership interest in Chipeta Processing LLC (“Chipeta”), bringing our total membership interest in Chipeta to 75%. Consideration paid for the 24% membership interest consisted of $128.3 million of cash on hand and the issuance of 151,235 common units to an affiliate of Anadarko and 3,086 general partner units to our general partner. In connection with the acquisition, we also entered into Amendment No. 8 to the First Amended and Restated Agreement of Limited Partnership, effective August 1, 2012. As with previous acquisitions from Anadarko, the partnership agreement amendment permits us to make a special one-time cash distribution to an affiliate of Anadarko in an amount equal to the cash consideration. The foregoing description is qualified in its entirety by reference to the full text of the partnership agreement amendment, a copy of which is filed with this Quarterly Report on Form 10-Q as Exhibit 3.10. See Note 9—Subsequent Event in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of June 30, 2012. Because of Anadarko’s control of the Partnership through its ownership of our general partner, each acquisition of Partnership assets through June 30, 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 and 2012:


thousands except unit and per-unit amounts	Common Units Issued ⁽¹⁾		GP Units Issued ⁽²⁾		Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
March 2011 equity offering		3,852,813		78,629	$	35.15	$	5,621	$	132,569
September 2011 equity offering		5,750,000		117,347		35.86		7,655		202,748
June 2012 equity offering		5,000,000		102,041		43.88		7,304		216,574

⁽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 June 30,				Six Months Ended June 30,
thousands	2012		2011		2012		2011
Gathering, processing and transportation of natural gas and natural gas liquids	$	78,475	$	76,389	$	157,630	$	146,746
Natural gas, natural gas liquids and condensate sales		122,226		128,051		250,712		233,940
Equity income and other, net		4,640		5,240		9,241		9,836

Total revenues ⁽¹⁾		205,341		209,680		417,583		390,522
Total operating expenses ⁽¹⁾		158,082		151,499		312,483		281,369

Operating income		47,259		58,181		105,100		109,153
Interest income, net – affiliates		4,225		5,749		8,450		10,419
Interest expense		(9,560)		(6,697)		(19,141)		(12,808)
Other income (expense), net		(1,267)		(3,305)		(809)		(1,153)

Income before income taxes		40,657		53,928		93,600		105,611
Income tax expense		90		6,064		627		10,896

Net income		40,567		47,864		92,973		94,715
Net income attributable to noncontrolling interests		4,290		2,838		8,533		5,792

Net income attributable to Western Gas Partners, LP	$	36,277	$	45,026	$	84,440	$	88,923

Key Performance Metrics ⁽²⁾
Gross margin	$	122,885	$	125,764	$	251,971	$	239,423
Adjusted EBITDA attributable to Western Gas Partners, LP	$	75,033	$	84,120	$	159,852	$	159,028
Distributable cash flow	$	59,874	$	76,921	$	132,925	$	144,379

⁽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 June 30, 2012” refer to the comparison of the three months ended June 30, 2012, to the three months ended June 30, 2011; any increases or decreases “for the six months ended June 30, 2012” refer to the comparison of the six months ended June 30, 2012, to the six months ended June 30, 2011; and any increases or decreases “for the three and six months ended June 30, 2012” refer to both the comparison for the three months ended June 30, 2012, and to the comparison for the six months ended June 30, 2012.

Operating Statistics


	Three Months Ended June 30,						Six Months Ended June 30,
throughput in MMcf/d	2012		2011		D		2012		2011		D
Gathering, treating and transportation ⁽¹⁾		1,267		1,341		(6)%		1,283		1,353		(5)%
Processing ⁽²⁾		1,170		957		22 %		1,160		904		28 %
Equity investment ⁽³⁾		234		173		35 %		235		180		31 %


Total throughput ⁽⁴⁾		2,671		2,471		8 %		2,678		2,437		10 %
Throughput attributable to noncontrolling interests		290		234		24 %		280		226		24 %


Total throughput attributable to Western Gas Partners, LP		2,381		2,237		6 %		2,398		2,211		8 %

⁽¹⁾	Excludes average NGL pipeline volumes from the Chipeta assets of 26 MBbls/d and 23 MBbls/d for the three months ended June 30, 2012 and 2011, respectively, and 26 MBbls/d and 22 MBbls/d for the six months ended June 30, 2012 and 2011, respectively.

⁽²⁾	Consists of 100% of Chipeta, Granger, Hilight and Red Desert complex 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 our 10% share of average White Cliffs pipeline volumes consisting of 6 MBbls/d for both the three and six months ended June 30, 2012, and 3 MBbls/d for both the three and six months ended June 30, 2011.

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

Gathering, treating and transportation throughput decreased by 74 MMcf/d and 70 MMcf/d for the three and six months ended June 30, 2012, respectively, resulting from throughput decreases at the Haley, Pinnacle, Hugoton, Dew and an MGR gathering system resulting from natural production declines and reduced drilling activity in those areas, partially offset by a throughput increase at Wattenberg due to increased drilling behind the system. In addition, during the six months ended June 30, 2012, throughput decreased at Bison due to lower third-party volumes and facility optimization.

Processing throughput increased by 213 MMcf/d and 256 MMcf/d for the three and six months ended June 30, 2012, respectively, primarily due to throughput increases at the Chipeta system, resulting from increased drilling activity; volumes from a plant included in the MGR acquisition, following the commencement of a new processing agreement at that plant beginning in May 2011; and the additional throughput from the Platte Valley system beginning in March 2011.

Equity investment volumes increased by 61 MMcf/d and 55 MMcf/d for the three and six months ended June 30, 2012, respectively, resulting from higher throughput at the Fort Union system due to producers choosing to route additional gas to reach desired end markets and at the Rendezvous system due to increased third-party drilling activity.

Natural Gas Gathering, Processing and Transportation Revenues


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
Gathering, processing and transportation of natural gas and natural gas liquids	$	78,475	$	76,389		3%	$	157,630	$	146,746		7%

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $2.1 million for the three months ended June 30, 2012, primarily due to increased drilling activity in the areas around the Chipeta, Wattenberg and Platte Valley systems. These increases were partially offset by decreased affiliate revenue at the Granger system due to diverted volumes, decreased revenue at the Helper system due to a downward rate revision effective April 1, 2012, decreased revenue at the Red Desert complex due to a May 2011 contractual rate adjustment, and decreased throughput at the Pinnacle, Dew and Hugoton systems as a result of natural production declines in the area.

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $10.9 million for the six months ended June 30, 2012, primarily due to the acquisition of the Platte Valley system in February 2011 and increased drilling activity in the areas around the Chipeta and Wattenberg systems. These increases were partially offset by decreased affiliate revenue at the Granger system due to diverted volumes, decreased revenue at the Helper system due to a downward rate revision effective April 1, 2012, decreased revenue at MIGC due to the expiration of firm transportation agreements, and decreased throughput at the Pinnacle, Dew and Hugoton systems as a result of natural production declines in the area.

Natural Gas, Natural Gas Liquids and Condensate Sales


thousands except percentages and	Three Months Ended June 30,							Six Months Ended June 30,
per-unit amounts	2012		2011		D			2012		2011		D
Natural gas sales	$	23,743	$	35,664		(33	)%	$	49,301	$	62,259		(21	)%
Natural gas liquids sales		92,527		85,608		8	%		186,169		157,936		18	%
Drip condensate sales		5,956		6,779		(12	)%		15,242		13,745		11	%

Total	$	122,226	$	128,051		(5	)%	$	250,712	$	233,940		7	%

Average price per unit:
Natural gas (per Mcf)	$	4.06	$	5.48		(26	)%	$	4.18	$	5.43		(23	)%
Natural gas liquids (per Bbl)	$	46.94	$	46.06		2	%	$	47.41	$	46.07		3	%
Drip condensate (per Bbl)	$	76.03	$	74.00		3	%	$	76.07	$	73.53		3	%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales decreased by $5.8 million for the three months ended June 30, 2012, which consisted of an $11.9 million decrease in natural gas sales and a $0.8 million decrease in drip condensate sales, partially offset by a $6.9 million increase in NGLs sales.

For the three months ended June 30, 2012, the decrease in natural gas sales was due to a 26% decrease in natural gas sales prices and a 10% decrease in volumes, which was primarily due to a decrease in throughput at the Red Desert complex, a decrease in volumes sold at the Wattenberg system due to volumes used to adjust imbalance positions, and changes in affiliate contract terms at the Platte Valley system allowing the producer to take its product in kind. The increase in NGLs sales was primarily due to an increase in throughput at the Chipeta and Granger systems, partially offset by a decrease in revenue due to changes in affiliate contract terms at the Platte Valley system allowing the producer to take its product in kind. The decrease in drip condensate sales was primarily due to a decrease in volumes as a result of lower throughput at the Hugoton system.

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $16.8 million for the six months ended June 30, 2012, which consisted of a $28.2 million increase in NGLs sales and a $1.5 million increase in drip condensate sales, partially offset by a $13.0 million decrease in natural gas sales.

For the six months ended June 30, 2012, the increase in NGLs sales was primarily due to an increase in throughput at the Chipeta, Granger and Wattenberg systems and the execution of a new gas processing agreement at a plant included in the MGR acquisition, partially offset by a decrease in throughput at the Red Desert complex. The increase in drip condensate sales was primarily due to an increase in throughput at the Wattenberg system and the acquisition of the Platte Valley system in February 2011, partially offset by a decrease in volumes at the Hugoton system. The decrease in natural gas sales was due to a 23% decrease in natural gas sales prices, and a decrease in throughput, primarily at the Hilight system and the Red Desert complex.

The average natural gas and NGLs prices for the three and six months ended June 30, 2012, include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and the MGR assets. The average natural gas and NGLs prices for the three and six months ended June 30, 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 June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
Equity income	$	3,335	$	2,739		22 %	$	6,948	$	5,022		38 %
Other revenues, net		1,305		2,501		(48)%		2,293		4,814		(52)%

Total	$	4,640	$	5,240		(11)%	$	9,241	$	9,836		(6)%

Equity income increased by $0.6 million and $1.9 million for the three and six months ended June 30, 2012, respectively, due to the increase in income from White Cliffs and Rendezvous as a result of increased volumes.

Other revenues decreased by $1.2 million and $2.5 million for the three and six months ended June 30, 2012, respectively, 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, with no comparable activity in the current periods.

Cost of Product and Operation and Maintenance Expenses


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
Cost of product	$	82,456	$	83,916		(2)%	$	165,612	$	151,099		10%
Operation and maintenance		33,882		29,225		16 %		63,780		56,086		14%

Total cost of product and operation and maintenance expenses	$	116,338	$	113,141		3 %	$	229,392	$	207,185		11%

Including the effects of commodity price swap agreements on purchases, cost of product expense decreased by $1.5 million for the three months ended June 30, 2012, primarily due to a decrease of $7.0 million attributable to decreased residue prices at the Platte Valley, Hilight and Granger systems, and at the Red Desert complex; decreased throughput at the Hilight system and changes in gas imbalance positions. Partially offsetting the decrease was an increase of $5.8 million attributable to higher throughput at the Chipeta system. Cost of product expense increased by $14.5 million for the six months ended June 30, 2012, primarily due to a $17.7 million increase due to higher throughput at the Chipeta, Wattenberg, Granger, and Platte Valley systems, partially offset by a decrease of $3.9 million attributable to lower throughput at the Hilight system, decreased residue prices at the Hilight system, and at the Red Desert complex and changes in gas imbalance positions.

Cost of product expense for the three and six months ended June 30, 2012, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and for the MGR assets. Cost of product expense for the three and six months ended June 30, 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 $4.7 million and $7.7 million for the three and six months ended June 30, 2012, respectively, primarily due to increased maintenance expenses incurred at the Wattenberg and Hilight systems and the acquisition of the Platte Valley system. These increases were partially offset by reduced variable operating expenses at the Red Desert complex resulting from decreased throughput activity compared to the same periods in the prior year.

General and Administrative, Depreciation and Other Expenses


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
General and administrative	$	9,755	$	8,171		19%	$	19,679	$	16,033		23%
Property and other taxes		4,833		4,352		11%		9,670		8,673		11%
Depreciation, amortization and impairments		27,156		25,835		5%		53,742		49,478		9%

Total general and administrative, depreciation and other expenses	$	41,744	$	38,358		9%	$	83,091	$	74,184		12%

General and administrative expenses increased by $1.6 million and $3.6 million for three and six months ended June 30, 2012, respectively, due to an increase in noncash compensation expenses primarily due to an increase in the value of equity-based awards and an increase in corporate and management personnel costs allocated to us pursuant to the omnibus agreement. These increases were partially offset by a decrease in management fees allocated to the Bison and MGR assets, the agreements for which were discontinued as of the respective dates of contribution.

Property and other taxes increased by $0.5 million and $1.0 million for the three and six months ended June 30, 2012, respectively, primarily due to ad valorem tax increases at the Platte Valley and Wattenberg assets.

Depreciation, amortization and impairments increased by $1.3 million and $4.3 million for the three and six months ended June 30, 2012, respectively, primarily attributable to the addition of the Platte Valley assets, and depreciation associated with capital projects completed at the Wattenberg and Hilight systems, and the Red Desert complex.

Interest Income, Net – Affiliates and Interest Expense


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
Interest income on note receivable	$	4,225	$	4,225		—	$	8,450	$	8,450		—
Interest income, net on affiliate balances⁽²⁾		—		1,524		(100)%		—		1,969		(100)%

Interest income, net – affiliates	$	4,225	$	5,749		(27)%	$	8,450	$	10,419		(19)%


Third Parties
Interest expense on long-term debt	$	(8,202)	$	(4,474)		83 %	$	(16,117)	$	(7,150)		125 %
Amortization of debt issuance costs and commitment fees⁽³⁾		(1,016)		(1,003)		1 %		(2,024)		(3,204)		(37)%
Capitalized interest		946		13		nm⁽¹⁾		1,603		13		nm⁽¹⁾
Affiliates
Interest expense on note payable to Anadarko⁽⁴⁾		(1,206)		(1,233)		(2)%		(2,440)		(2,467)		(1)%
Interest expense, net on affiliate balances		(82)		—		nm		(163)		—		nm

Interest expense	$	(9,560)	$	(6,697)		43 %	$	(19,141)	$	(12,808)		49 %

⁽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⁾

Amortization of the original issue discount and underwriters’ fees related to the 2022 Notes and 2021 Notes (as defined in Note 7—Debt and Interest Expense) was $0.2 million and $0.4 million for the three and six months ended June 30, 2012, respectively, and related to the 2021 Notes was $0.1 million for both the three and six months ended June 30, 2011.

⁽⁴⁾	In June 2012, we repaid in full the note payable to Anadarko.

Interest expense increased by $2.9 million and $6.3 million for the three and six months ended June 30, 2012, respectively, primarily due to interest expense incurred on the $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) that were issued in May 2011. The increases were partially offset by reductions resulting from the early repayment of the Wattenberg term loan in March 2011, the related $1.3 million of accelerated amortization expense recognized in March 2011 (described in Liquidity and Capital Resources below) and increased capitalized interest associated with the construction of a second cryogenic train at the Chipeta plant.

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 June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
Other income (expense), net	$	(1,267)	$	(3,305)		(62)%	$	(809)	$	(1,153)		(30)%

Other income (expense), net includes $0.4 million and $0.8 million for each of the three and six months ended June 30, 2012 and 2011, respectively, of interest income related to a capital lease.

In addition, other income (expense), net for the three and six months ended June 30, 2012, includes a realized loss of $1.7 million resulting from U.S. Treasury Rate lock agreements settled simultaneously with our June 2012 issuance of the 2022 Notes. Other income (expense), net for the three and six months ended June 30, 2011, includes the reversal of an unrealized gain of $1.7 million, previously recorded in March 2011, and a realized loss of $1.9 million, upon termination of the interest-rate swap agreement in May 2011 concurrent with the issuance of the 2021 Notes. See Note 2—Acquisitions and Note 7—Debt and Interest Expense included in the Notes to Consolidated Financial Statements included under Item 1 of this Form 10-Q.

Income Tax Expense


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
Income before income taxes	$	40,657	$	53,928		(25)%	$	93,600	$	105,611		(11)%
Income tax expense		90		6,064		(99)%		627		10,896		(94)%
Effective tax rate		—%		11%				1%		10%

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 and six months ended June 30, 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 pre-acquisition income attributable to Partnership assets and our share of Texas margin tax.

Noncontrolling Interests


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2012		2011		D		2012		2011		D
Net income attributable to noncontrolling interests	$	4,290	$	2,838		51%	$	8,533	$	5,792		47%

For the three and six months ended June 30, 2012, net income attributable to noncontrolling interests increased by $1.5 million and $2.7 million, respectively, primarily due to the higher volumes at the Chipeta system.

Key Performance Metrics


thousands except percentages	Three Months Ended June 30,						Six Months Ended June 30,
and gross margin per Mcf	2012		2011		D		2012		2011		D
Gross margin	$	122,885	$	125,764		(2)%	$	251,971	$	239,423		5 %
Gross margin per Mcf ⁽¹⁾		0.51		0.56		(9)%		0.52		0.54		(4)%
Gross margin per Mcf attributable to Western Gas Partners, LP⁽²⁾		0.54		0.59		(8)%		0.55		0.57		(4)%
Adjusted EBITDA attributable to Western Gas Partners, LP⁽³⁾		75,033		84,120		(11)%		159,852		159,028		1 %
Distributable cash flow⁽³⁾	$	59,874	$	76,921		(22)%	$	132,925	$	144,379		(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 decreased by $2.9 million for the three months ended June 30, 2012, primarily due to lower margins at the Red Desert complex and decreased volumes at the Hilight system, which were partially offset by increased margins at the Wattenberg and Chipeta systems, due to an increase in volumes (including the impact of commodity price swap agreements at the Wattenberg system).

Gross margin increased by $12.5 million for the six months ended June 30, 2012, primarily due to higher margins at the Wattenberg, Chipeta, Platte Valley 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). 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 and six months ended June 30, 2012, gross margin per Mcf decreased by 9% and 4%, respectively, and gross margin per Mcf attributable to Western Gas Partners, LP decreased by 8% and 4%, respectively, primarily due to lower revenue at the Red Desert complex as a result of commodity price declines and, to a lesser extent, lower volumes at the Red Desert complex.

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 decreased by $9.1 million for the three months ended June 30, 2012, primarily due to a $4.9 million decrease in total revenues excluding equity income, a $4.7 million increase in operation and maintenance expenses, a $1.5 million increase in net income attributable to noncontrolling interests, a $0.5 million increase in general and administrative expenses excluding non-cash equity-based compensation, and a $0.5 million increase in property and other taxes expense, partially offset by a $1.5 million decrease in cost of product and a $1.5 million increase in distributions from equity investees.

Adjusted EBITDA increased by $0.8 million for the six months ended June 30, 2012, primarily due to a $25.1 million increase in total revenues excluding equity income and a $2.0 million increase in distributions from equity investees, partially offset by a $14.5 million increase in cost of product, a $7.7 million increase in operation and maintenance expenses, a $2.7 million increase in net income attributable to noncontrolling interests, a $1.0 million increase in property and other taxes expense and a $0.4 million increase in general and administrative expenses excluding non-cash equity-based compensation.

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

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 decreased by $17.0 million for the three months ended June 30, 2012, primarily due to the $9.1 million decrease in Adjusted EBITDA, a $4.2 million increase in cash paid for maintenance capital expenditures and a $3.7 million increase in net cash paid for interest expense.

Distributable cash flow decreased by $11.5 million for the six months ended June 30, 2012, primarily due to a $7.8 million increase in net cash paid for interest expense and a $4.4 million increase in cash paid for maintenance capital expenditures, partially offset by the $0.8 million increase in Adjusted EBITDA.

Reconciliation to GAAP measures. Adjusted EBITDA and Distributable cash flow are not defined in GAAP. The GAAP measures most directly comparable to Adjusted EBITDA are net income attributable to Western Gas Partners, LP and net cash provided by operating activities, and the GAAP measure most directly comparable to Distributable cash flow is net income attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted EBITDA and Distributable cash flow should not be considered as alternatives to the GAAP measures of net income attributable to Western Gas Partners, LP 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 June 30,				Six Months Ended June 30,
thousands	2012		2011		2012		2011
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	75,033	$	84,120	$	159,852	$	159,028
Less:
Distributions from equity investees		5,578		4,091		10,019		8,000
Non-cash equity-based compensation expense		2,924		1,918		6,990		3,846
Interest expense		9,560		6,697		19,141		12,808
Income tax expense		90		6,064		627		10,896
Depreciation, amortization and impairments ⁽¹⁾		26,499		25,129		52,430		48,067
Other expense ⁽¹⁾		1,665		3,683		1,665		3,683
Add:
Equity income, net		3,335		2,739		6,948		5,022
Interest income, net – affiliates		4,225		5,749		8,450		10,419
Other income ^{(1) (2)}		—		—		62		1,754

Net income attributable to Western Gas Partners, LP	$	36,277	$	45,026	$	84,440	$	88,923


Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	75,033	$	84,120	$	159,852	$	159,028
Adjusted EBITDA attributable to noncontrolling interests		4,945		3,542		9,843		7,200
Interest income (expense), net		(5,335)		(948)		(10,691)		(2,389)
Non-cash equity-based compensation expense		(2,924)		(1,918)		(6,990)		(3,846)
Current income tax expense		(65)		(3,026)		(125)		(5,405)
Other income (expense), net ⁽²⁾		(1,663)		(3,681)		(1,601)		(1,926)
Distributions from equity investees less than (in excess of) equity income, net		(2,243)		(1,352)		(3,071)		(2,978)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		834		(10,794)		5,666		(20,816)
Accounts payable, accrued liabilities and natural gas imbalance payable		(425)		6,750		8,820		14,058
Other		3,367		3,575		4,387		5,312

Net cash provided by operating activities	$	71,524	$	76,268	$	166,090	$	148,238

⁽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 and $0.8 million for each of the three and six months ended June 30, 2012 and 2011, respectively, related to a component of a gas processing agreement accounted for as a capital lease. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.


	Three Months Ended June 30,					Six Months Ended June 30,
thousands except Coverage ratio	2012			2011		2012			2011
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	59,874		$	76,921	$	132,925		$	144,379
Less:
Distributions from equity investees		5,578			4,091		10,019			8,000
Non-cash equity-based compensation expense		2,924			1,918		6,990			3,846
Interest expense, net (non-cash settled)		82			—		163			—
Income tax expense		90			6,064		627			10,896
Depreciation, amortization and impairments ⁽¹⁾		26,499			25,129		52,430			48,067
Other expense ⁽¹⁾		1,665			3,683		1,665			3,683
Add:
Equity income, net		3,335			2,739		6,948			5,022
Cash paid for maintenance capital expenditures ^{(1) (2)}		8,960			4,714		14,724			10,278
Capitalized interest		946			13		1,603			13
Cash paid for income taxes		—			—		72			—
Other income ^{(1) (3)}		—			—		62			1,754
Interest income, net (non-cash settled)		—			1,524		—			1,969

Net income attributable to Western Gas Partners, LP	$	36,277		$	45,026	$	84,440		$	88,923


Distributions declared⁽⁴⁾
Limited partners	$	45,976				$	87,732
General partner		6,449					10,746

Total	$	52,425				$	98,478

Coverage ratio		1.14	x				1.35	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⁾	Net of a prior period adjustment reclassifying approximately $1.0 million and $0.7 million from capital expenditures to operating expenses for the three and six months ended June 30, 2012, respectively.

⁽³⁾

⁽⁴⁾	Reflects distributions of $0.48 and $0.94 per unit declared for the three and six months ended June 30, 2012, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and other capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owners. Our sources of liquidity as of June 30, 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 these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders and have increased our quarterly distribution each quarter since the second quarter of 2009. On July 19, 2012, the board of directors of our general partner declared a cash distribution to our unitholders of $0.48 per unit, or $52.4 million in aggregate, including incentive distributions. The cash distribution is payable on August 13, 2012, to unitholders of record at the close of business on July 31, 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 Part II, Item 1A—Risk Factors of this Form 10-Q.

Working capital. As of June 30, 2012, we had $125.1 million of working capital, which we define as the amount by which current assets exceed current liabilities. Working capital is an indication of our liquidity and potential need for short-term funding. Our working-capital requirements are driven by changes in accounts receivable and accounts payable and factors such as credit extended to, and the timing of collections from, our customers and the level and timing of our spending for maintenance and expansion activity.

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:


	Six Months Ended June 30,
thousands	2012		2011
Acquisitions	$	465,507	$	303,602

Expansion capital expenditures	$	131,587	$	27,832
Maintenance capital expenditures		15,471		10,318

Total capital expenditures ⁽¹⁾	$	147,058	$	38,150

Capital incurred ⁽²⁾	$	219,458	$	41,034

⁽¹⁾

Capital expenditures for the six months ended June 30, 2011, includes $8.2 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 six months ended June 30, 2012, excludes $1.6 million of capitalized interest.

⁽²⁾	Capital incurred for the six months ended June 30, 2011, includes $6.8 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. On August 1, 2012, we closed on the acquisition of Anadarko’s remaining 24% membership in Chipeta, bringing our total membership interest in Chipeta to 75%. Consideration required for the acquisition was $128.3 million in cash, 151,235 common units of the Partnership and 3,086 general partner units to be issued to the general partner. See Note 9—Subsequent Event in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Capital expenditures, excluding acquisitions, increased by $108.9 million for the six months ended June 30, 2012. Expansion capital expenditures increased by $103.8 million for the six months ended June 30, 2012, primarily due to an increase of $69.4 million in expenditures at our Chipeta, Wattenberg and Platte Valley systems, and $41.5 million related to the construction of the Brasada and Lancaster gas processing facilities. These increases were partially offset by a $5.6 million decrease related to the Bison assets, due to the continued startup costs incurred in early 2011, and a $1.6 million decrease at the Hilight system. Maintenance capital expenditures increased by $5.2 million, primarily as a result of higher well connects at the Platte Valley, Wattenberg, and Haley systems, partially offset by a prior period adjustment of $0.7 million recorded during the six months ended June 30, 2012, and 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.


	Six Months Ended June 30,
thousands	2012		2011
Net cash provided by (used in):
Operating activities	$	166,090	$	148,238
Investing activities		(612,565)		(341,603)
Financing activities		477,968		228,986

Net increase (decrease) in cash and cash equivalents	$	31,493	$	35,621

Operating Activities. Net cash provided by operating activities increased by $17.9 million for the six months ended June 30, 2012, primarily due to the following items:

•

a $26.1 million increase due to changes in accounts receivable balances;

•

a $25.1 million increase in revenues, excluding equity income; and

•

a $5.3 million decrease in current income tax expense.

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

•

a $14.5 million increase in cost of product expense;

•

an $8.3 million increase in interest expense, net;

•

a $7.7 million increase in operation and maintenance expenses;

•

a $5.8 million decrease due to changes in accounts and natural gas imbalance payable and accrued liabilities, net; and

•

a $1.0 million increase in property and other taxes expense.

Investing Activities. Net cash used in investing activities for the six months ended June 30, 2012, included the following:

•

$458.6 million of cash paid for the MGR acquisition;

•

$147.1 million of capital expenditures; and

•

$6.7 million of cash paid for equipment purchases from Anadarko.

Net cash used in investing activities for the six months ended June 30, 2011, included the following:

•

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

•

$38.2 million of capital expenditures.

Financing Activities. Net cash provided by financing activities for the six months ended June 30, 2012, included the following:

•

$512.4 million of net proceeds from our 2022 Notes offering in June 2012, after underwriting and original issue discounts and offering costs;

•

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

•

$216.6 million of net proceeds from our June 2012 equity offering.

Proceeds from our 2022 Notes offering were used in the repayment of amounts outstanding under our RCF and our note payable to Anadarko. 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 six months ended June 30, 2011, included the following:

•

$489.7 million of net proceeds from our 2021 Notes offering in May 2011, after underwriting and original issue discounts and offering costs;

•

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

•

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

•

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

Proceeds from our 2021 Notes offering and our March 2011 equity offering were used in the repayment of amounts outstanding under our RCF.

Net distributions to Parent attributable to pre-acquisition intercompany balances were $26.7 million during 2011, representing the net non-cash settlement of intercompany transactions attributable to the MGR and Bison assets.

For the six months ended June 30, 2012 and 2011, we paid $89.1 million and $63.7 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $21.3 million and $7.4 million during the six months ended June 30, 2012 and 2011, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $10.3 million and $7.5 million for the six months ended June 30, 2012 and 2011, respectively, representing the distributions for the two preceding quarterly periods ended March 31^st of the respective year.

Debt and credit facilities. As of June 30, 2012, our outstanding debt consisted of $515.8 million of the 2022 Notes and $494.4 million of the 2021 Notes. See Note 7—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

4.000% Senior Notes due 2022. In June 2012, we completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”) at a price to the public of 99.194% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 4.189%. Interest will be paid semi-annually on January 1 and July 1 of each year, commencing on January 1, 2013. The 2022 Notes will mature on July 1, 2022, unless redeemed, in whole or in part, at any time prior to maturity, at a redemption price that includes a make-whole premium. Proceeds (net of underwriting discount of $3.4 million and debt issuance costs) were used to repay all amounts then outstanding under our RCF and the $175.0 million note payable to Anadarko (see below).

The 2022 Notes indenture contains customary events of default including, among others, (i) default for 30 days in the payment of interest when due on the 2022 Notes; (ii) default in payment, when due, of principal of or premium, if any, on the 2022 Notes at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency. The 2022 Notes indenture also contains covenants that limit, among other things, our ability, as well as that of certain of our subsidiaries, to (i) create liens on our principal properties; (ii) engage in sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease or transfer substantially all of our properties or assets to another entity. At June 30, 2012, we were in compliance with all covenants under the 2022 Notes.

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

Upon issuance, the 2021 Notes were fully and unconditionally guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees were immediately released on June 13, 2012, upon the Subsidiary Guarantors becoming released from their obligations under our RCF, as discussed below. At June 30, 2012, we were in compliance with all covenants under the 2021 Notes.

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

Revolving credit facility. In March 2011, we entered into an amended and restated $800.0 million senior unsecured RCF and borrowed $250.0 million under the RCF to repay the Wattenberg term loan (described below). The RCF 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.

On June 13, 2012, following the receipt of a second investment grade rating, as defined in our RCF, the guarantees provided by our wholly owned subsidiaries were released, and we are no longer subject to certain of the restrictive covenants associated with the RCF, including the maintenance of an interest coverage ratio and adherence to covenants that limit, among other things, our ability, and that of certain of our subsidiaries, to dispose of assets and make certain investments or payments. As of June 30, 2012, we had no borrowings under our RCF and $800.0 million was available for borrowing. At June 30, 2012, we were in compliance with all remaining covenants under the RCF.

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

Wattenberg term loan. In connection with the Wattenberg acquisition, in August 2010 we borrowed $250.0 million under a three-year term loan from a group of banks (“Wattenberg term loan”). The Wattenberg term loan incurred interest at LIBOR plus a margin ranging from 2.50% to 3.50% depending on our consolidated leverage ratio as defined in the Wattenberg term loan agreement. We repaid the Wattenberg term loan in 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 revolving credit facility, other third-party long-term debt, capital obligations related to our expansion projects and various operating leases. Refer to Note 7—Debt and Interest Expense, Note 8—Commitments and Contingencies and Note 9—Subsequent Event in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q for an update to our contractual obligations as of June 30, 2012, including, but not limited to, the issuance of the 2022 Notes, the repayment of our note payable to Anadarko, increases in committed capital and our contribution agreement with Anadarko for the acquisition of Anadarko’s remaining 24% membership interest in Chipeta.

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 six months ended June 30, 2012 were low compared to historic rates. As of June 30, 2012, we had no borrowings outstanding under our RCF, which bears interest 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 June 30, 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 June 30, 2012.

Changes in Internal Control Over Financial Reporting. There has been no change in our internal control over financial reporting during the quarter ended June 30, 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, certain sections of which have been recast to reflect the results of the MGR assets (as defined in Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q) in our Current Report on Form 8-K, as filed with the SEC on May 22, 2012; 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 2. Unregistered Sales of Equity Securities and Use of Proceeds

In connection with our June 2012 equity offering, our general partner purchased an additional 102,041 general partner units to maintain its 2.0% general partner interest in us for $4.5 million in cash. Proceeds from the June 2012 equity offering, including from the sale of the general partner units, will be used primarily for general partnership purposes, including the funding of capital expenditures. Also, as part of the consideration for our acquisition of a 24% membership interest in Chipeta Processing LLC from Anadarko, we issued 151,235 common units to an affiliate of Anadarko and 3,086 general partner units to our general partner on August 1, 2012. These common units and general partner units were issued in reliance on an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended.

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*		Amendment No. 8 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 1, 2012.
3.11		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).
3.12		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).
4.5		Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
4.6		Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
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

August 2, 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)



August 2, 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)