Edgar Filing: Western Gas Partners LP

e10vq

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, 2011


o		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		(I.R.S. Employer
incorporation or organization)		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 o

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 o

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 o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a 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 o No þ

There were 57,854,693 common units outstanding as of July 29, 2011.

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, 2011 and 2010		4

		Consolidated Balance Sheets as of June 30, 2011, and December 31, 2010		5

		Consolidated Statement of Equity and Partners’ Capital for the six months ended June 30, 2011		6

		Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010		7

		Notes to Consolidated Financial Statements		8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

		Cautionary Note Regarding Forward-Looking Statements		26

		Executive Summary		28

		Acquisitions		29

		Equity Offerings		30

		Results of Operations		31

		Operating Results		31

		Liquidity and Capital Resources		40

		Contractual Obligations		45

		Off-Balance Sheet Arrangements		45

		Recent Accounting Developments		45

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		45

	Item 4.	Controls and Procedures		46

PART II		OTHER INFORMATION

	Item 1.	Legal Proceedings		46

	Item 1A.	Risk Factors		46

	Item 6.	Exhibits		47

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.

Bcf: One billion cubic feet.

Bcf/d: One billion cubic feet per day.

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						Six Months Ended
	June 30,						June 30,
thousands except per-unit amounts	2011			2010⁽¹⁾			2011			2010⁽¹⁾
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	50,580		$	45,290		$	99,190		$	90,758
Natural gas, natural gas liquids and condensate sales		67,320			59,576			120,521			119,254
Equity income and other, net		3,579			1,444			6,287			3,042

Total revenues – affiliates		121,479			106,310			225,998			213,054
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		16,929			10,201			29,449			21,648
Natural gas, natural gas liquids and condensate sales		23,237			7,457			41,441			17,651
Other, net		103			1,015			853			1,566

Total revenues – third parties		40,269			18,673			71,743			40,865

Total revenues		161,748			124,983			297,741			253,919

Operating expenses
Cost of product ⁽²⁾		62,317			38,506			109,137			80,479
Operation and maintenance ⁽²⁾		23,639			22,205			44,501			44,596
General and administrative ⁽²⁾		7,082			5,455			13,780			11,523
Property and other taxes		3,974			3,649			7,933			7,268
Depreciation, amortization and impairments		21,711			17,613			41,269			35,332

Total operating expenses		118,723			87,428			216,620			179,198

Operating income		43,025			37,555			81,121			74,721
Interest income – affiliates		4,225			4,232			8,450			8,462
Interest expense ⁽³⁾		(6,697	)		(3,598	)		(12,808	)		(7,126	)
Other expense, net		(3,682	)		(2,393	)		(1,922	)		(2,373	)

Income before income taxes		36,871			35,796			74,841			73,684
Income tax expense		94			3,419			126			8,975

Net income		36,777			32,377			74,715			64,709
Net income attributable to noncontrolling interests		2,838			3,371			5,792			5,265

Net income attributable to Western Gas Partners, LP	$	33,939		$	29,006		$	68,923		$	59,444

Limited partner interest in net income:
Net income attributable to Western Gas Partners, LP	$	33,939		$	29,006		$	68,923		$	59,444
Pre-acquisition net income allocated to Parent		—			(5,595	)		—			(11,901	)
General partner interest in net income ⁽⁴⁾		(1,842	)		(519	)		(3,290	)		(1,002	)

Limited partner interest in net income ⁽⁴⁾	$	32,097		$	22,892		$	65,633		$	46,541
Net income per common unit – basic and diluted	$	0.40		$	0.35		$	0.83		$	0.72
Net income per subordinated unit – basic and diluted	$	0.38		$	0.35		$	0.79		$	0.72
Net income per limited partner unit – basic and diluted	$	0.39		$	0.35		$	0.82		$	0.72


⁽¹⁾		Financial information for 2010 has been revised to include results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1.

⁽²⁾		Cost of product includes product purchases from Anadarko (as defined in Note 1) of $18.1 million and $33.6 million for the three and six months ended June 30, 2011, respectively, and $16.1 million and $32.8 million for the three and six months ended June 30, 2010, respectively. Operation and maintenance includes charges from Anadarko of $10.5 million and $20.2 million for the three and six months ended June 30, 2011, respectively, and $8.9 million and $20.5 million for the three and six months ended June 30, 2010, respectively. General and administrative includes charges from Anadarko of $5.2 million and $10.3 million for the three and six months ended June 30, 2011, respectively, and $4.4 million and $8.9 million for the three and six months ended June 30, 2010, respectively. See Note 4.

⁽³⁾		Includes affiliate interest expense of $1.2 million and $2.5 million for the three and six months ended June 30, 2011, respectively, and $1.8 million and $3.6 million for the three and six months ended June 30, 2010, 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 also Note 3.

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


	June 30,		December 31,
thousands except number of units	2011		2010
ASSETS
Current assets
Cash and cash equivalents	$	62,695	$	27,074
Accounts receivable, net ⁽¹⁾		28,104		10,890
Other current assets		3,701		5,220

Total current assets		94,500		43,184
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		2,025,652		1,727,231
Less accumulated depreciation		406,956		367,881

Net property, plant and equipment		1,618,696		1,359,350
Goodwill and other intangible assets		115,266		60,236
Equity investments		39,742		40,406
Other assets		9,017		2,361

Total assets	$	2,137,221	$	1,765,537

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables ⁽²⁾	$	20,343	$	15,175
Accrued ad valorem taxes		7,806		5,986
Income taxes payable		326		160
Accrued liabilities ⁽³⁾		30,144		20,873

Total current liabilities		58,619		42,194
Long-term debt – third parties		493,946		299,000
Note payable – Anadarko		175,000		175,000
Asset retirement obligations and other		61,514		44,275

Total long-term liabilities		730,460		518,275

Total liabilities		789,079		560,469
Equity and partners’ capital
Common units (54,904,409 and 51,036,968 units issued and outstanding at June 30, 2011, and December 31, 2010, respectively)		943,973		810,717
Subordinated units (26,536,306 units issued and outstanding at June 30, 2011, and December 31, 2010)		282,969		282,384
General partner units (1,661,757 and 1,583,128 units issued and outstanding at June 30, 2011, and December 31, 2010, respectively)		25,052		21,505

Total partners’ capital		1,251,994		1,114,606
Noncontrolling interests		96,148		90,462

Total equity and partners’ capital		1,348,142		1,205,068

Total liabilities, equity and partners’ capital	$	2,137,221	$	1,765,537


⁽¹⁾		Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $11.2 million and $1.8 million as of June 30, 2011, and December 31, 2010, respectively.
⁽²⁾		Accounts and natural gas imbalances payables includes amounts payable to affiliates of $1.4 million and $1.5 million as of June 30, 2011, and December 31, 2010, respectively.
⁽³⁾		Accrued liabilities include amounts payable to affiliates of $0.3 million and $0.6 million as of June 30, 2011, and December 31, 2010, respectively.

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(UNAUDITED)


	Partners’ Capital
	Limited Partners						General			Noncontrolling
thousands	Common			Subordinated			Partner			Interests			Total
Balance at December 31, 2010	$	810,717		$	282,384		$	21,505		$	90,462		$	1,205,068
Net income		44,615			21,018			3,290			5,792			74,715
Issuance of common and general partner units, net of offering expenses		129,805			—			2,764			—			132,569
Contributions from noncontrolling interest owners		—			—			—			7,389			7,389
Distributions to noncontrolling interest owners		—			—			—			(7,495	)		(7,495	)
Distributions to unitholders		(40,801	)		(20,433	)		(2,498	)		—			(63,732	)
Non-cash equity-based compensation and other		(363	)		—			(9	)		—			(372	)

Balance at June 30, 2011	$	943,973		$	282,969		$	25,052		$	96,148		$	1,348,142

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Six Months Ended
	June 30,
thousands	2011			2010⁽¹⁾
Cash flows from operating activities
Net income	$	74,715		$	64,709
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		41,269			35,332
Deferred income taxes		(41	)		(2,633	)
Changes in assets and liabilities:
Increase in accounts receivable, net		(17,741	)		(6,352	)
Increase in accounts and natural gas imbalance payables and accrued liabilities, net		12,189			8,106
Change in other items, net		2,962			564

Net cash provided by operating activities		113,353			99,726
Cash flows from investing activities
Capital expenditures		(29,956	)		(50,189	)
Acquisition from affiliates		—			(241,680	)
Acquisition from third parties		(303,602	)		—
Investments in equity affiliates		(93	)		(310	)
Proceeds from sale of assets to affiliate		242			—

Net cash used in investing activities		(333,409	)		(292,179	)
Cash flows from financing activities
Borrowings, net of issuance costs		1,045,939			209,987
Repayments of debt		(859,000	)		(100,000	)
Proceeds from issuance of common and general partner units		132,569			99,311
Distributions to unitholders		(63,732	)		(43,435	)
Contributions from noncontrolling interest owners		7,389			2,053
Distributions to noncontrolling interest owners		(7,495	)		(6,383	)
Net contributions from Parent		7			25,338

Net cash provided by financing activities		255,677			186,871

Net increase (decrease) in cash and cash equivalents		35,621			(5,582	)
Cash and cash equivalents at beginning of period		27,074			69,984

Cash and cash equivalents at end of period	$	62,695		$	64,402


Supplemental disclosures
Contribution of assets from Parent	$	7		$	7,530
Increase in accrued capital expenditures	$	4,237		$	2,376
Interest paid	$	8,271		$	6,068
Interest received	$	8,450		$	8,450


⁽¹⁾		Financial information for 2010 has been revised to include results attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1.

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

Description of business. Western Gas Partners, LP (the “Partnership”) is a Delaware limited partnership formed in August 2007. As of June 30, 2011, the Partnership’s assets included eleven gathering systems, six natural gas treating facilities, seven natural gas processing facilities, one NGL pipeline, one interstate pipeline and interests in Fort Union Gas Gathering, L.L.C. (“Fort Union”) and White Cliffs Pipeline, L.L.C. (“White Cliffs”) accounted for under the equity method. The Partnership’s assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming), and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko Petroleum Corporation and its consolidated subsidiaries, as well as third-party producers and customers.

For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its consolidated 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 and White Cliffs.

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. All significant intercompany transactions have been eliminated. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership records its 50% proportionate share of the assets, liabilities, revenues and expenses attributable to the Newcastle system. Noncontrolling interests in the Partnership’s assets and income represent the aggregate 49% interest in Chipeta Processing LLC (“Chipeta”) held by Anadarko Petroleum Corporation and a third party.

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, 2011, and December 31, 2010, results of operations for the three and six months ended June 30, 2011 and 2010, statement of equity and partners’ capital for the six months ended June 30, 2011, and statements of cash flows for the six months ended June 30, 2011 and 2010. The Partnership’s financial results for the three and six months ended June 30, 2011, are not necessarily indicative of the expected results for the full year ending December 31, 2011.

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 annual report on Form 10-K, as filed with the SEC on February 24, 2011. Management believes that the disclosures made are adequate to make the information not misleading.

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

Acquisitions. The following table presents the acquisitions completed by the Partnership during 2010 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	Acquisition		Percentage				Cash		Common		GP Units
percent amounts	Date		Acquired		Borrowings		On Hand		Units Issued		Issued
Granger ⁽¹⁾		01/29/10		100%	$	210,000	$	31,680		620,689		12,667
Wattenberg ⁽²⁾		08/02/10		100%		450,000		23,100		1,048,196		21,392
White Cliffs ⁽³⁾		09/28/10		10%		—		38,047		—		—
Platte Valley ⁽⁴⁾		02/28/11		100%		303,000		602		—		—
Bison ⁽⁵⁾		07/08/11		100%		—		25,000		2,950,284		60,210


⁽¹⁾		The assets acquired from Anadarko include (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of cryogenic trains, a refrigeration train, an NGLs fractionation facility and ancillary equipment. These assets, located in southwestern Wyoming, are referred to collectively as the “Granger assets” and the acquisition as the “Granger acquisition.”

⁽²⁾		The assets acquired from Anadarko include the Wattenberg gathering system and related facilities, including the Fort Lupton processing plant. These assets, located in the Denver-Julesburg Basin, north and east of Denver, Colorado, are referred to collectively as the “Wattenberg assets” and the acquisition as the “Wattenberg acquisition.”

⁽³⁾		White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma, which became operational in June 2009. The Partnership’s acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko combined with the acquisition of an additional 9.6% interest in White Cliffs from a third party, are referred to collectively as the “White Cliffs acquisition.” The Partnership’s interest in White Cliffs is referred to as the “White Cliffs investment.”

⁽⁴⁾		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.” See further information below.

⁽⁵⁾		Subsequent to June 30, 2011, the Partnership acquired Anadarko’s Bison gas treating facility and related assets located in the Powder River Basin in northeastern Wyoming, including (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.”

Platte Valley acquisition. The Platte Valley acquisition has been accounted for under the acquisition method of accounting. At February 28, 2011, the date of the acquisition, the assets and liabilities of the Partnership continue to be recorded based upon their historical costs and the Platte Valley assets and liabilities are recorded at their estimated fair values. 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 following is the current allocation of the purchase price to the assets acquired and liabilities assumed in the Platte Valley acquisition as of the acquisition date.


thousands
Property, plant and equipment	$	264,521
Intangible assets		55,399
Asset retirement obligations and other liabilities		(16,318	)

Total purchase price	$	303,602

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

The purchase price allocation is based on an initial assessment of the fair value of the assets acquired and liabilities assumed in the Platte Valley acquisition. The fair values of the plant and processing facilities, related equipment, and intangible assets acquired were based on market, cost and income approaches. The liabilities assumed include certain amounts associated with environmental contingencies estimated by management. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The current purchase price allocation is preliminary and is subject to change pending post-closing purchase price adjustments; finalizing fair value estimates; and completing evaluations of property, plant and equipment, intangible assets, asset retirement obligations, contractual arrangements and legal and environmental matters as additional information becomes available and is assessed by the Partnership. For more information regarding the intangible assets presented in the table above, see Note 6.

The following table presents the pro forma condensed financial information as if the Platte Valley acquisition occurred on January 1, 2011.


	Six Months
	Ended
thousands except per-unit amount	June 30, 2011
Revenues	$	313,780
Net income		77,441
Net income attributable to Western Gas Partners, LP		71,649
Earnings per limited partner unit – basic and diluted	$	0.85

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s pro forma information in the table above includes $31.5 million of revenues and $21.3 million of expenses attributable to the Platte Valley assets and is included in the Partnership’s consolidated statement of income for the six months ended June 30, 2011. The pro forma adjustments reflect pre-acquisition results of the Platte Valley assets for January and February 2011, including (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the preliminary purchase price allocated to property, plant and equipment and other intangible assets and estimated useful lives; (c) elimination of $0.7 million of acquisition-related costs; and (d) interest on the Partnership’s $303.0 million of borrowings under its revolving credit facility to finance the Platte Valley acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transactions are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the acquisition, nor any future acquisition related expenses. Pro forma information is not presented for periods ended on or before December 31, 2010, as it is not practical to determine revenues and cost of product for periods prior to January 1, 2011, the effective date of the gathering and processing agreement with the seller.

Presentation of Partnership acquisitions. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of June 30, 2011. Because of Anadarko’s control of the Partnership through its ownership of the general partner, each acquisition as of June 30, 2011, of Partnership assets, 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 a result, after each acquisition of assets from Anadarko, the Partnership is required to revise its financial statements to include the activities of the Partnership assets as of the date of common control. Anadarko acquired the Wattenberg assets in connection with its August 10, 2006, acquisition of Kerr-McGee Corporation, and made its initial investment in White Cliffs on January 29, 2007.

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

The Partnership’s historical financial statements for the three and six months ended June 30, 2010, as presented in the Partnership’s second quarter 2010 Form 10-Q as filed with the SEC on August 5, 2010, have been recast in this quarterly report on Form 10-Q to include the results attributable to the Wattenberg assets and the 0.4% interest in White Cliffs as if the Partnership owned such assets for all periods presented. Unless otherwise noted, references to “periods prior to the acquisition of the Partnership assets” and similar phrases refer to periods prior to July 2010 with respect to the Wattenberg assets and periods prior to September 2010 with respect to the White Cliffs investment. References to “periods including and subsequent to the acquisition of the Partnership assets” and similar phrases refer to periods including and subsequent to July 2010 with respect to the Wattenberg assets and periods including and subsequent to September 2010 with respect to the White Cliffs investment. 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 limited partner unit. In addition, certain amounts in prior periods have been reclassified to conform to the current presentation. Specifically, during the quarter ended September 30, 2010, the Partnership revised its presentation to report the effects of commodity price swap agreements attributable to purchases in cost of product in its consolidated statements of income. Net gains and losses on commodity price swap agreements related to purchases have been reclassified from revenue to cost of product for all periods to conform to the current presentation. The following table presents the impact to the historical consolidated statements of income attributable to the Wattenberg assets and 0.4% interest in White Cliffs, as well as the reclassification of the impact of commodity price swap agreements related to purchases:


	Three Months Ended June 30, 2010
	Partnership		Wattenberg		White
thousands	Historical		Assets		Cliffs		Reclassification		Combined
Revenues	$	87,968	$	30,094	$	50	$	6,871	$	124,983
Net income		26,782		5,543		52		—		32,377


	Six Months Ended June 30, 2010
	Partnership		Wattenberg		White
thousands	Historical		Assets		Cliffs		Reclassification		Combined
Revenues	$	182,287	$	65,131	$	90	$	6,411	$	253,919
Net income		51,590		13,026		93		—		64,709

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

Equity offerings. The Partnership completed the following public equity offerings during 2010 and 2011:


							Underwriting
							Discount and
thousands except unit	Common		GP Units		Price Per		Other Offering		Net
and per-unit amounts	Units Issued⁽²⁾		Issued⁽³⁾		Unit		Expenses		Proceeds⁽⁴⁾
May 2010 equity offering ⁽¹⁾		4,558,700		93,035	$	22.25	$	4,427	$	99,074
November 2010 equity offering		8,415,000		171,734		29.92		10,279		246,729
March 2011 equity offering		3,852,813		78,629		35.15		5,621		132,569


⁽¹⁾		The May 2010 equity offering refers collectively to the May 2010 equity offering issuance, and the June 2010 exercise of the underwriters’ over-allotment option.

⁽²⁾		Common units issued includes the issuance of 558,700 common units, 915,000 common units and 302,813 common units pursuant to the exercise, in full or in part, of the underwriters’ over-allotment options granted in connection with the May 2010, November 2010 and March 2011 equity offerings, respectively.

⁽³⁾		GP units issued 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.

⁽⁴⁾		Net proceeds were primarily used to repay amounts outstanding under the Partnership’s revolving credit facility.

Limited partner 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, subordinated and general partner units issued during the six months ended June 30, 2011:

Limited Partner Units

General

thousands

Common

Subordinated

Partner Units

Total

Balance at December 31, 2010

51,037

26,536

1,583

79,156

March 2011 equity offering

3,853

—

3,932

Long-Term Incentive Plan Awards

—

Balance at June 30, 2011

54,904

26,536

1,662

83,102

Anadarko holdings of Partnership equity. As of June 30, 2011, Anadarko held 1,661,757 general partner units representing a 2% general partner interest in the Partnership, 10,302,631 common units, 26,536,306 subordinated units, and 100% of the Partnership’s incentive distribution rights, or “IDRs.” Anadarko owned an aggregate 44.3% interest in the Partnership based on its holdings of common and subordinated limited partner units. The public held 44,601,778 common units, representing a 53.7% interest in the Partnership based on its holdings of common limited partner units. Anadarko’s ownership interest as of June 30, 2011, does not include the common or general units it acquired in connection with the Bison acquisition, which was completed in July 2011. Management anticipates the subordinated units held by Anadarko will convert to common units on August 15, 2011.

Recently issued accounting standards not yet adopted. In May 2011, the Financial Accounting Standards Board (the “FASB”) issued an Accounting Standards Update (“ASU”) amending guidance for fair value measurements and related disclosures. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements, changes the fair value measurement requirements for certain financial instruments and requires additional disclosures about fair value measurements. This ASU will apply to the Partnership prospectively beginning January 1, 2012. The impact of the adoption of the ASU on the Partnership’s consolidated financial statements, if any, is currently under evaluation.

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2. 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:


	Total Quarterly
thousands except per-unit amounts	Distribution		Total Cash		Date of
Quarters Ended	per Unit		Distribution		Distribution
March 31, 2010	$	0.340	$	22,042	May 2010
June 30, 2010	$	0.350	$	24,378	August 2010
March 31, 2011	$	0.390	$	33,168	May 2011
June 30, 2011⁽¹⁾	$	0.405	$	36,063	August 2011


⁽¹⁾		On June 30, 2011, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.405 per unit, or $36.1 million in aggregate, including incentive distributions. The cash distribution is payable on August 12, 2011, to unitholders of record at the close of business on July 29, 2011.

3. NET INCOME PER LIMITED PARTNER UNIT

The Partnership’s net income for periods including and subsequent to the Partnership’s acquisitions of the Partnership assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. The Partnership’s net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner, common unitholders and subordinated unitholders consistent with actual cash distributions, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and subordinated unitholders in accordance with their respective ownership percentages during each period.

Basic and diluted net income per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. The common units issued in connection with acquisitions and equity offerings during 2010 and 2011 are included on a weighted-average basis for periods they were outstanding. Management anticipates the subordinated units will convert to common units on August 15, 2011.

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

3. NET INCOME PER LIMITED PARTNER UNIT (CONTINUED)

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
thousands except per-unit amounts	2011			2010			2011			2010
Net income attributable to Western Gas Partners, LP	$	33,939		$	29,006		$	68,923		$	59,444
Pre-acquisition net income allocated to Parent		—			(5,595	)		—			(11,901	)
General partner interest in net income		(1,842	)		(519	)		(3,290	)		(1,002	)

Limited partner interest in net income	$	32,097		$	22,892		$	65,633		$	46,541


Net income allocable to common units	$	22,028		$	13,639		$	44,615		$	27,380
Net income allocable to subordinated units		10,069			9,253			21,018			19,161

Limited partner interest in net income	$	32,097		$	22,892		$	65,633		$	46,541

Net income per limited partner unit – basic and diluted
Common units	$	0.40		$	0.35		$	0.83		$	0.72
Subordinated units	$	0.38		$	0.35		$	0.79		$	0.72
Total limited partner units	$	0.39		$	0.35		$	0.82		$	0.72
Weighted average limited partner units outstanding – basic and diluted
Common units		54,896			39,117			53,528			37,966
Subordinated units		26,536			26,536			26,536			26,536

Total limited partner units		81,432			65,653			80,064			64,502

4. 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 are 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 1 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 acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged or credited the Partnership interest at a variable rate on outstanding affiliate balances for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to parent net investment in connection with the acquisition of the Partnership assets. Subsequent to the acquisition of the Partnership assets, the Partnership cash-settles transactions related to such assets directly with third parties and with Anadarko affiliates and affiliate-based interest expense on current intercompany balances is not charged.

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

4. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Note receivable from 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%. Interest on the note is payable quarterly. The fair value of the note receivable from Anadarko was approximately $272.8 million and $258.9 million at June 30, 2011, and December 31, 2010, 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.

Commodity price swap agreements. The Partnership holds 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 Hilight, Hugoton, Newcastle, Granger and Wattenberg assets. 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 reports its realized gains and losses on the commodity price swap agreements related to sales in natural gas, natural gas liquids and condensate sales in its consolidated statements of income in the period in which the associated revenues are recognized. The Partnership reports its realized gains and losses on the commodity price swap agreements related to purchases in cost of product in its consolidated statements of income in the period in which the associated purchases are recorded. The Partnership has not entered into any new commodity price swap agreements since the fourth quarter of 2010.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
thousands	2011			2010			2011			2010
Gains (losses) on commodity price swap agreements:
Natural gas sales	$	8,992		$	5,190		$	15,800		$	5,465
Natural gas liquids sales		(10,677	)		2,896			(16,518	)		695

Total		(1,685	)		8,086			(718	)		6,160

Losses on commodity price swap agreements related to purchases		(6,670	)		(6,871	)		(12,876	)		(6,411	)

Net gains (losses) on commodity price swap agreements	$	(8,355	)	$	1,215		$	(13,594	)	$	(251	)

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 80% and 81% of the Partnership’s gathering and transportation throughput for the three and six months ended June 30, 2011 and 2010, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 71% and 78% of the Partnership’s processing throughput for the three months ended June 30, 2011 and 2010, respectively, and 72% and 78% for the six months ended June 30, 2011 and 2010, respectively, was attributable to natural gas production owned or controlled by Anadarko.

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

4. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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

Three Months Ended

Six Months Ended

June 30,

thousands

2011

2010

2011

2010

Revenues ⁽¹⁾

121,479

106,310

225,998

213,054

Cost of product ⁽¹⁾

18,102

16,136

33,592

32,825

Operation and maintenance ⁽²⁾

10,526

8,904

20,178

20,467

General and administrative ⁽³⁾

5,225

4,434

10,262

8,897

Operating expenses

33,853

29,474

64,032

62,189

Interest income ⁽⁴⁾

4,225

4,232

8,450

8,462

Interest expense ⁽⁵⁾

1,233

1,785

2,467

3,570

Distributions to unitholders ⁽⁶⁾

15,779

12,609

30,864

24,848

Contributions from noncontrolling interest owners

2,659

3,619

2,019

Distributions to noncontrolling interest owners

1,533

1,751

4,547

3,126


⁽¹⁾		Represents amounts recognized under gathering and processing, and purchase and sale agreements with affiliates of Anadarko.

⁽²⁾		Represents expenses incurred under the Services and Secondment Agreement with Anadarko, as applicable. See Note 1.

⁽³⁾		Represents general and administrative expense incurred under the Omnibus Agreement with Anadarko, as applicable. See Note 1.

⁽⁴⁾		Represents interest income recognized under the Note Receivable from Anadarko.

⁽⁵⁾		Represents interest expense recognized under the Note Payable to Anadarko.

⁽⁶⁾		Represents distributions paid to an affiliate of Anadarko under the Partnership Agreement.

Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented on the Partnership’s consolidated statements of income. The percentages of revenues from Anadarko and the Partnership’s other customers are as follows:

Three Months Ended

Six Months Ended

June 30,

2011

2010

2011

2010

Anadarko

73%

85%

74%

84%

Other customers

27%

15%

26%

16%

Total

100%

100%

100%

100%

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

5. PROPERTY, PLANT AND EQUIPMENT

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


thousands	June 30, 2011		December 31, 2010
Land	$	354	$	354
Gathering systems		1,902,733		1,621,633
Pipelines and equipment		83,718		83,613
Assets under construction		35,713		18,928
Other		3,134		2,703

Total property, plant and equipment		2,025,652		1,727,231
Accumulated depreciation		406,956		367,881

Net property, plant and equipment	$	1,618,696	$	1,359,350

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. In addition, property, plant and equipment cost as well as third-party accrued liability balances in the Partnership’s consolidated balance sheets include $9.7 million and $5.5 million of accrued capital as of June 30, 2011, and December 31, 2010, respectively, representing estimated capital expenditures for which invoices had not yet been processed.

6. OTHER INTANGIBLE ASSETS

The intangible asset balance in the Partnership’s consolidated balance sheets represent the estimated economic value related to the contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, that dedicate certain customers’ field production to the acquired gathering and processing system. These contracts ensure an extended commercial relationship with the existing customers and provide the Partnership with a high probability of additional production from the customers’ acreage. These contracts are generally limited, however, by the quantity and production life of the underlying natural gas resource base.

At June 30, 2011, the carrying value of the Partnership’s customer relationship intangible assets was $55.0 million, net of $0.4 million of accumulated amortization, and is included in goodwill and other intangible assets in the Partnership’s consolidated balance sheets. Customer relationships are amortized on a straight-line basis over 50 years, which is the estimated productive life of the reserves covered by the underlying acreage ultimately expected to be produced and gathered or processed through the Partnership’s assets subject to current contractual arrangements. Estimated future amortization for these intangible assets is as follows:


	Future
thousands	amortization
July – December 2011	$	554
2012		1,108
2013		1,108
2014		1,108
2015		1,108

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6. OTHER INTANGIBLE ASSETS (CONTINUED)

The Partnership assesses intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense. No intangible asset impairment has been recognized in connection with these assets.

7. DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt as of June 30, 2011, and December 31, 2010:


	June 30, 2011						December 31, 2010
			Carrying		Fair				Carrying		Fair
thousands	Principal		Value		Value		Principal		Value		Value
Revolving credit facility	$	—	$	—	$	—	$	49,000	$	49,000	$	49,000
5.375% Senior Notes due 2021		500,000		493,946		514,834		—		—		—
Wattenberg term loan		—		—		—		250,000		250,000		250,000
Note payable to Anadarko		175,000		175,000		170,327		175,000		175,000		168,116

Total debt outstanding⁽¹⁾	$	675,000	$	668,946	$	685,161	$	474,000	$	474,000	$	467,116


⁽¹⁾		The Partnership’s consolidated balance sheets include accrued interest expense of $3.3 million and $0.8 million as of June 30, 2011, and December 31, 2010, 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 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.

The following table presents the debt activity of the Partnership for the six months ended June 30, 2011:


thousands	Carrying Value
Balance as of December 31, 2010	$	474,000
First Quarter 2011
Revolving credit facility borrowings		560,000
Repayment of revolving credit facility		(139,000	)
Repayment of Wattenberg term loan		(250,000	)
Revolving credit facility borrowings – Swingline		10,000
Repayment of revolving credit facility – Swingline		(10,000	)
Second Quarter 2011
Revolving credit facility borrowings – Swingline		10,000
Issuance of 5.375% Senior Notes due 2021		500,000
Repayment of revolving credit facility		(470,000	)
Repayment of revolving credit facility – Swingline		(10,000	)
Other and changes in debt discount		(6,054	)

Balance as of June 30, 2011	$	668,946

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

7. DEBT AND INTEREST EXPENSE (CONTINUED)

5.375% Senior Notes due 2021. In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “Notes”) at a price to the public of 98.778% of the face amount of the Notes. Interest on the Notes will be paid semi-annually on June 1 and December 1 of each year, commencing on December 1, 2011. The Notes mature on June 1, 2021, unless redeemed, in whole or in part, at any time prior to maturity, at a redemption price that includes a make-whole premium. Proceeds from the offering of the Notes (net of the underwriting discount of $3.3 million and debt issuance costs) were used to repay the then-outstanding balance on the Partnership’s revolving credit facility, with the remainder used for general partnership purposes.

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Partnership’s wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees will be released if, among other things, the Subsidiary Guarantors are released from their obligations under the Partnership’s revolving credit facility. See Note 9 for the financial statements of the Subsidiary Guarantors.

The Notes indenture contains customary events of default including, among others, (i) default in any payment of interest on any debt securities when due that continues for 30 days; (ii) default in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii) certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing the Notes also contains covenants that limit, among other things, the ability of the Partnership and the Subsidiary Guarantors to (i) create liens on their 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 their properties or assets to another entity. At June 30, 2011, the Partnership was in compliance with all covenants under the Notes.

Note payable to Anadarko. In December 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 4.00% until November 2010. The term loan agreement was amended in December 2010 to fix the interest rate at 2.82% through maturity in 2013. The Partnership has the option, at any time, to repay the outstanding principal amount in whole or in part.

The provisions of the five-year term loan agreement contain customary events of default, including (i) non-payment of principal when due or non-payment of interest or other amounts within three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to the Partnership and (iii) a change of control. At June 30, 2011, the Partnership was in compliance with all covenants under this agreement.

Revolving credit facility. In March 2011, the Partnership entered into an amended and restated $800.0 million senior unsecured revolving credit facility (the “RCF”) and borrowed $250.0 million under the RCF to repay the Wattenberg term loan (described below). The RCF amended and restated the Partnership’s $450.0 million credit facility, which was originally entered into in October 2009. The RCF matures in March 2016 and bears interest at London Interbank Offered Rate, or “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%, and (c) LIBOR plus 1%, plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.89% and 3.26% at June 30, 2011, and at December 31, 2010, 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 consolidated leverage ratio, as defined in the RCF. The facility fee rate was 0.30% and 0.50% at June 30, 2011, and December 31, 2010, respectively.

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

7. DEBT AND INTEREST EXPENSE (CONTINUED)

The RCF contains covenants that limit, among other things, the ability of the Partnership and certain of its subsidiaries to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of the Partnership’s assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and certain financial tests as of the end of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to consolidated EBITDA for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio (which is defined as the ratio of consolidated EBITDA for the most recent four consecutive fiscal quarters to consolidated interest expense for such period) of 2.0 to 1.0.

All amounts due under the RCF are unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. The Partnership will no longer be required to comply with the minimum consolidated interest coverage ratio as well as the subsidiary guarantees and certain of the aforementioned covenants, if the Partnership obtains two of the following three ratings: BBB- or better by S&P, Baa3 or better by Moody’s, or BBB- or better by Fitch. As of June 30, 2011, no amounts were outstanding under the RCF, with $800.0 million available for borrowing. At June 30, 2011, the Partnership was in compliance with all covenants under the 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 March 2011 using borrowings from its RCF and recognized $1.3 million of accelerated amortization expense related to its early repayment.

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

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
thousands	2011			2010		2011			2010
Third Parties
Interest expense on long-term debt	$	4,474		$	1,130	$	7,150		$	2,107
Amortization of debt issuance costs and commitment fees		1,003			683		3,204			1,449
Capitalized interest		(13	)		—		(13	)		—

Total interest expense – third parties		5,464			1,813		10,341			3,556

Affiliates
Interest expense on notes payable to Anadarko		1,233			1,750		2,467			3,500
Credit facility commitment fees		—			35		—			70

Total interest expense – affiliates		1,233			1,785		2,467			3,570

Interest expense	$	6,697		$	3,598	$	12,808		$	7,126

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

8. COMMITMENTS AND CONTINGENCIES

Litigation and legal proceedings. In March 2011, DCP Midstream LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering LLC, in Weld County District Court (the “Court”) in Colorado, alleging that Anadarko and its affiliates diverted gas from DCP’s gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering LLC, the entity which holds the Wattenberg assets. In April 2011, the defendants, including the Partnership, moved to dismiss this lawsuit. The motion has been fully briefed by the parties, but not yet ruled upon by the Court. Management does not believe the outcome of this proceeding will have a material effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership intends to vigorously defend this litigation. Furthermore, without regard to the merit of DCP’s claims, management believes that the Partnership has adequate contractual indemnities covering the claims against it in this lawsuit.

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

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations. The lease for the corporate offices expires in January 2012, with no purchase option at termination, and the leases for the shared offices extend through 2014. The lease for the warehouse extends through September 2011 and includes an early termination clause. In addition, during 2010, Anadarko and Kerr-McGee Gathering LLC purchased previously leased compression equipment used at the Granger and Wattenberg assets, which terminated the leases and associated lease expense. The purchased compression equipment was contributed to the Partnership pursuant to provisions of the contribution agreements for the Granger and the Wattenberg acquisitions.

As of June 30, 2011, there was no material change in the existing contractual lease obligations for the office and warehouse leases from December 31, 2010. Rent expense associated with these leases and the previously leased compression equipment was approximately $0.5 million and $0.9 million for the three and six months ended June 30, 2011, respectively, and $2.5 million and $4.6 million for the three and six months ended June 30, 2010, respectively.

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

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

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

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)


	Statement of Income
	Three Months Ended June 30, 2011
	Western					Non-
	Gas			Subsidiary		Guarantor
thousands	Partners, LP			Guarantors		Subsidiary		Eliminations			Consolidated

Revenues	$	(1,686	)	$	148,972	$	14,462	$	—		$	161,748
Operating expenses		13,405			96,645		8,673		—			118,723

Operating income (loss)		(15,091	)		52,327		5,789		—			43,025
Interest income – affiliates		4,215			10		—		—			4,225
Interest expense		(6,697	)		—		—		—			(6,697	)
Other income (expense), net		(3,685	)		—		3		—			(3,682	)
Equity income from consolidated subsidiaries		55,197			2,955		—		(58,152	)		—

Income before income taxes		33,939			55,292		5,792		(58,152	)		36,871
Income tax expense		—			94		—		—			94

Net income		33,939			55,198		5,792		(58,152	)		36,777
Net income attributable to noncontrolling interests		—			2,838		—		—			2,838

Net income attributable to Western Gas Partners, LP	$	33,939		$	52,360	$	5,792	$	(58,152	)	$	33,939


	Statement of Income
	Three Months Ended June 30, 2010
	Western					Non-
	Gas			Subsidiary		Guarantor
thousands	Partners, LP			Guarantors		Subsidiary		Eliminations			Consolidated

Revenues	$	8,086		$	104,798	$	12,099	$	—		$	124,983
Operating expenses		10,868			71,337		5,223		—			87,428

Operating income (loss)		(2,782	)		33,461		6,876		—			37,555
Interest income – affiliates		4,217			15		—		—			4,232
Interest expense		(3,598	)		—		—		—			(3,598	)
Other income (expense), net		(2,395	)		—		2		—			(2,393	)
Equity income from consolidated subsidiaries		27,969			3,508		—		(31,477	)		—

Income before income taxes		23,411			36,984		6,878		(31,477	)		35,796
Income tax expense		—			3,419		—		—			3,419

Net income		23,411			33,565		6,878		(31,477	)		32,377
Net income attributable to noncontrolling interests		—			3,371		—		—			3,371

Net income attributable to Western Gas Partners, LP	$	23,411		$	30,194	$	6,878	$	(31,477	)	$	29,006

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

Statement of Income

Six Months Ended June 30, 2011

Western

Non-

Gas

Subsidiary

Guarantor

thousands

Partners, LP

Guarantors

Subsidiary

Eliminations

Consolidated

Revenues

(719

)

271,205

27,255

—

297,741

Operating expenses

26,018

175,162

15,440

—

216,620

Operating income (loss)

(26,737

)

96,043

11,815

—

81,121

Interest income – affiliates

8,430

—

8,450

Interest expense

(12,808

)

—

(12,808

)

Other income (expense), net

(1,936

)

—

(1,922

)

Equity income from consolidated subsidiaries

101,974

6,029

—

(108,003

)

—

Income before income taxes

68,923

102,101

11,820

(108,003

)

74,841

Income tax expense

—

126

—

126

Net income

68,923

101,975

11,820

(108,003

)

74,715

Net income attributable to noncontrolling interests

—

5,792

—

5,792

Net income attributable to Western Gas Partners, LP

68,923

96,183

11,820

(108,003

)

68,923


	Statement of Income
	Six Months Ended June 30, 2010
	Western					Non-
	Gas			Subsidiary		Guarantor
thousands	Partners, LP			Guarantors		Subsidiary		Eliminations			Consolidated

Revenues	$	6,160		$	225,573	$	22,186	$	—		$	253,919
Operating expenses		14,910			152,842		11,446		—			179,198

Operating income (loss)		(8,750	)		72,731		10,740		—			74,721
Interest income – affiliates		8,436			26		—		—			8,462
Interest expense		(7,126	)		—		—		—			(7,126	)
Other income (expense), net		(2,377	)		—		4		—			(2,373	)
Equity income from consolidated subsidiaries		57,361			5,480		—		(62,841	)		—

Income before income taxes		47,544			78,237		10,744		(62,841	)		73,684
Income tax expense		—			8,975		—		—			8,975

Net income		47,544			69,262		10,744		(62,841	)		64,709
Net income attributable to noncontrolling interests		—			5,265		—		—			5,265

Net income attributable to Western Gas Partners, LP	$	47,544		$	63,997	$	10,744	$	(62,841	)	$	59,444

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

Balance Sheet

June 30, 2011

Western

Non-

Gas

Subsidiary

Guarantor

thousands

Partners, LP

Guarantors

Subsidiary

Eliminations

Consolidated

Current assets

51,027

21,782

21,691

—

94,500

Note receivable – Anadarko

260,000

—

260,000

Investment in consolidated subsidiaries

1,140,545

104,787

—

(1,245,332

)

—

Net property, plant and equipment

137

1,430,883

187,676

—

1,618,696

Other long-term assets

9,017

155,008

—

164,025

Total assets

1,460,726

1,712,460

209,367

(1,245,332

)

2,137,221

Current liabilities

4,181

47,963

6,475

—

58,619

Long-term debt

668,946

—

668,946

Other long-term liabilities

59,434

2,018

—

61,514

Total liabilities

673,189

107,397

8,493

—

789,079

Partners’ capital

787,537

1,508,915

200,874

(1,245,332

)

1,251,994

Noncontrolling interests

—

96,148

—

96,148

Total liabilities, equity and partners’ capital

1,460,726

1,712,460

209,367

(1,245,332

)

2,137,221


	Balance Sheet
	December 31, 2010
	Western				Non-
	Gas		Subsidiary		Guarantor
thousands	Partners, LP		Guarantors		Subsidiary		Eliminations			Consolidated

Current assets	$	24,972	$	208,208	$	10,346	$	(200,342	)	$	43,184
Note receivable – Anadarko		260,000		—		—		—			260,000
Investment in consolidated subsidiaries		1,052,073		97,018		—		(1,149,091	)		—
Net property, plant and equipment		165		1,177,971		181,214		—			1,359,350
Other long-term assets		2,361		100,642		—		—			103,003

Total assets	$	1,339,571	$	1,583,839	$	191,560	$	(1,349,433	)	$	1,765,537


Current liabilities	$	201,989	$	38,420	$	2,127	$	(200,342	)	$	42,194
Long-term debt		474,000		—		—		—			474,000
Other long-term liabilities		38		42,283		1,954		—			44,275

Total liabilities		676,027		80,703		4,081		(200,342	)		560,469
Partners’ capital		663,544		1,412,674		187,479		(1,149,091	)		1,114,606
Noncontrolling interests		—		90,462		—		—			90,462

Total liabilities, equity and partners’ capital	$	1,339,571	$	1,583,839	$	191,560	$	(1,349,433	)	$	1,765,537

WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)

Statement of Cash Flows

Six Months Ended June 30, 2011

Western

Non-

Gas

Subsidiary

Guarantor

thousands

Partners, LP

Guarantors

Subsidiary

Eliminations

Consolidated

Net income

68,923

101,975

11,820

(108,003

)

74,715

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

Equity income from consolidated subsidiaries

(101,974

)

(6,029

)

—

108,003

—

Depreciation, amortization and impairments

38,365

2,877

—

41,269

Change in other items, net

(196,478

)

195,113

(1,266

)

—

(2,631

)

Net cash provided by (used in) operating activities

(229,502

)

329,424

13,431

—

113,353

Net cash used in investing activities

—

(335,333

)

(5,767

)

7,691

(333,409

)

Net cash provided by (used in) financing activities

255,886

5,909

1,573

(7,691

)

255,677

Net increase (decrease) in cash and cash equivalents

26,384

—

9,237

—

35,621

Cash and cash equivalents at beginning of period

21,480

—

5,594

—

27,074

Cash and cash equivalents at end of period

47,864

—

14,831

—

62,695


	Statement of Cash Flows
	Six Months Ended June 30, 2010
	Western						Non-
	Gas			Subsidiary			Guarantor
thousands	Partners, LP			Guarantors			Subsidiary			Eliminations			Consolidated

Net income	$	47,544		$	69,262		$	10,744		$	(62,841	)	$	64,709
Adjustments to reconcile net income to net cash provided by operating activities:
Equity income from consolidated subsidiaries		(57,361	)		(5,480	)		—			62,841			—
Depreciation, amortization and impairments		27			32,436			2,869			—			35,332
Change in other items, net		82,245			(79,097	)		(3,463	)		—			(315	)

Net cash provided by operating activities		72,455			17,121			10,150			—			99,726
Net cash used in investing activities		(241,680	)		(48,759	)		(1,740	)		—			(292,179	)
Net cash provided by (used in) financing activities		166,136			31,638			(10,903	)		—			186,871

Net increase (decrease) in cash and cash equivalents		(3,089	)		—			(2,493	)		—			(5,582	)
Cash and cash equivalents at beginning of period		61,632			—			8,352			—			69,984

Cash and cash equivalents at end of period	$	58,543		$	—		$	5,859		$	—		$	64,402

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

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and notes to consolidated financial statements, which are included under Part I, Item 1 of this quarterly report, as well as our historical consolidated financial statements, and the notes thereto, which are included in Part I, Item 8 of our 2010 annual report on Form 10-K as filed with the Securities and Exchange Commission, or “SEC,” on February 24, 2011. 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 acquisition dates, combined with the financial results and operations of the Wattenberg assets (defined in Acquisitions) and 0.4% interest in White Cliffs (defined below) for all periods presented. For ease of reference, we 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 wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and also refers to Fort Union Gas Gathering, L.L.C., or “Fort Union,” and White Cliffs Pipeline, L.L.C., or “White Cliffs.” References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of June 30, 2011.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

	•		our assumptions about the energy market;

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

	•		operating results;

	•		competitive conditions;

	•		technology;

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

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

	•		the weather;

	•		inflation;

	•		the availability of goods and services;

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

	•		changes in environmental and safety regulation; environmental risks; regulations by the Federal Energy Regulatory Commission, or “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 the outcome of the Deepwater Horizon events;

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

	•		our commitments to capital projects;

	•		the ability to utilize our revolving credit facility;

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

	•		our ability to repay debt;

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

	•		our ability to acquire assets on acceptable terms;

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

	•		other factors discussed below and elsewhere in “Risk Factors” under Part I, Item 1A in our 2010 annual report on Form 10-K, and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” under Part II, Item 7 included in our 2010 annual report on Form 10-K, our quarterly reports on Form 10-Q and in our other public filings and press releases.

The risk factors and other factors noted throughout or incorporated by reference in this report could cause our actual results to differ materially from those contained in any forward-looking statement. Except as required by law, 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 limited partnership organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently operate in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged primarily in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko and third-party producers and customers. As of June 30, 2011, our assets consist of eleven gathering systems, six natural gas treating facilities, seven natural gas processing facilities, one NGL pipeline, one interstate pipeline, and interests in a gas gathering system and a crude oil pipeline accounted for under the equity method.

Significant financial and operational highlights during the first six months of 2011 include the following:

	•		In February 2011, we acquired the Platte Valley gathering system and processing plant from a third party for $303.6 million, funded primarily by borrowings under our revolving credit facility. These assets are located in the Denver-Julesburg basin and consist of a cryogenic processing plant, two fractionation trains and a natural gas gathering system.

	•		In March 2011, we issued 3,852,813 common units to the public, generating net proceeds of $132.6 million, including the general partner’s proportionate capital contributions to maintain its 2.0% general partner interest. Net proceeds from this offering were used primarily to repay amounts outstanding under our revolving credit facility.

	•		In March 2011, we entered into an amended and restated $800.0 million senior unsecured revolving credit facility to amend and restate the $450.0 million credit facility originally entered into in October 2009. Refer to Liquidity and Capital Resources for additional information.

	•		In May 2011, we issued $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021. Net proceeds from this issuance were used primarily to repay amounts outstanding under our revolving credit facility. Refer to Liquidity and Capital Resources for additional information.

	•		Our stable operating cash flow, combined with a focus on cost reduction and capital spending discipline, enabled us to raise our distribution to $0.405 per unit for the second quarter of 2011, representing a 4% increase over the distribution for the first quarter of 2011 and our ninth consecutive quarterly increase.

	•		Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP for the three months ended June 30, 2011, averaged $0.67 per Mcf, representing a 22% increase compared to the three months ended June 30, 2010, and averaged $0.65 per Mcf for the six months ended June 30, 2011, representing an 18% increase compared to the six months ended June 30, 2010. The increase in gross margin per Mcf is primarily due to the addition of the Platte Valley system, the increase in ownership of the White Cliffs investment (as defined in Acquisitions) and growth in higher-margin areas, which offset the impact of the expiration of lower-margin contracts. The predominantly fee-based and fixed-price structure of our contracts mitigated the impact of changes in commodity prices on our gross margin.

	•		Throughput attributable to Western Gas Partners, LP totaled 1,555 MMcf/d and 1,531 MMcf/d for the three and six months ended June 30, 2011, respectively, representing a 5% and 7% decrease, respectively, compared to the same periods in 2010. The throughput decrease is primarily due to lower volumes at the MIGC and Fort Union systems following the startup of the Bison pipeline, and lower volumes at the Haley, Pinnacle, Dew and Hugoton systems due to natural production declines and low drilling activity. These declines were partially offset by increased throughput at the Granger, Chipeta and Wattenberg systems resulting from drilling activity in these areas driven by favorable producer economics, and the additional throughput attributable to the Platte Valley system acquired in 2011.

ACQUISITIONS

Acquisitions. The following table presents our acquisitions completed during 2010 and 2011, and details the funding for those acquisitions through borrowings, cash on hand and/or the issuance of equity:


thousands except unit and	Acquisition		Percentage					Cash		Common		GP Units
percent amounts	Date		Acquired			Borrowings		On Hand		Units Issued		Issued
Granger ⁽¹⁾		01/29/10		100	%	$	210,000	$	31,680		620,689		12,667
Wattenberg ⁽²⁾		08/02/10		100	%		450,000		23,100		1,048,196		21,392
White Cliffs ⁽³⁾		09/28/10		10	%		—		38,047		—		—
Platte Valley ⁽⁴⁾		02/28/11		100	%		303,000		602		—		—
Bison ⁽⁵⁾		07/08/11		100	%		—		25,000		2,950,284		60,210


⁽¹⁾		The assets acquired from Anadarko include (i) the Granger gathering system, a 750-mile gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains with combined capacity of 200 MMcf/d, a refrigeration train with capacity of 100 MMcf/d, an NGLs fractionation facility with capacity of 9,500 barrels per day, and ancillary equipment. These assets, located in southwestern Wyoming, are referred to collectively as the “Granger assets” or “Granger system” and the acquisition as the “Granger acquisition.” In connection with the acquisition, we entered into a ten-year fee-based arrangement covering a majority of the Granger assets’ affiliate throughput and five-year, fixed-price commodity swap agreements with Anadarko, which cover non-fee-based volumes processed at the Granger complex.

⁽²⁾		The assets acquired from Anadarko include the Wattenberg gathering system and related facilities, including the Fort Lupton processing plant. These assets, located in the Denver-Julesburg Basin, north and east of Denver, Colorado, are referred to collectively as the “Wattenberg assets” or “Wattenberg system” and the acquisition as the “Wattenberg acquisition.” In connection with the acquisition, we entered into a ten-year fee-based arrangement covering all of the Wattenberg assets’ affiliate throughput and five-year, fixed-price commodity swap agreements with Anadarko, which fix the margin we will realize from the purchase and sale of natural gas, condensate or NGLs at the Wattenberg assets.

⁽³⁾		White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma and that became operational in June 2009. Our acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko combined with the acquisition of an additional 9.6% interest in White Cliffs from a third party, are referred to collectively as the “White Cliffs acquisition.” Our interest in White Cliffs is referred to as the “White Cliffs investment.”

⁽⁴⁾		The assets acquired from a third party include (i) a processing plant with cryogenic capacity of 84 MMcf/d, (ii) two fractionation trains, (iii) a 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.” 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 revolving credit facility.

⁽⁵⁾		Subsequent to June 30, 2011, we acquired Anadarko’s Bison gas treating facility and related assets located in the Powder River Basin in northeastern Wyoming, including (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.”

Presentation of Partnership acquisitions. References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of June 30, 2011. Because of Anadarko’s control of the Partnership through its ownership of our general partner, each acquisition of Partnership assets, 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. Accordingly, our consolidated financial statements include the financial results and operations of the Partnership assets since the date of common control. Anadarko acquired the Wattenberg assets in connection with its August 10, 2006, acquisition of Kerr-McGee Corporation and made its initial investment in White Cliffs on January 29, 2007.

Our historical financial statements for the three and six months ended June 30, 2010, as presented in our second quarter 2010 Form 10-Q as filed with the SEC on August 5, 2010, have been recast in this quarterly report on Form 10-Q to include the results attributable to the Wattenberg assets and the 0.4% interest in White Cliffs as if we owned such assets for all periods presented. Unless otherwise noted, references to “periods prior to our acquisition of the Partnership assets” and similar phrases refer to periods prior to July 2010 with respect to the Wattenberg assets and periods prior to September 2010 with respect to the White Cliffs investment. Reference to “periods including and subsequent to our acquisition of the Partnership assets” and similar phrases refer to periods including and subsequent to July 2010 with respect to the Wattenberg assets and periods including and subsequent to September 2010 with respect to the White Cliffs investment. In addition, certain amounts in prior periods have been reclassified to conform to the current presentation. Our noncontrolling interests represent the aggregate 49% interest in Chipeta Processing LLC (“Chipeta”) held by Anadarko and a third party.

EQUITY OFFERINGS

Equity offerings. We completed the following public equity offerings during 2010 and 2011:


							Underwriting
							Discount and
thousands except unit	Common		GP Units		Price Per		Other Offering		Net
and per-unit amounts	Units Issued ⁽²⁾		Issued ⁽³⁾		Unit		Expenses		Proceeds ⁽⁴⁾
May 2010 equity offering ⁽¹⁾		4,558,700		93,035	$	22.25	$	4,427	$	99,074
November 2010 equity offering		8,415,000		171,734		29.92		10,279		246,729
March 2011 equity offering		3,852,813		78,629		35.15		5,621		132,569


⁽¹⁾		The May 2010 equity offering refers collectively to the May 2010 equity offering issuance, and the June 2010 exercise of the underwriters’ over-allotment option.

⁽²⁾		Common units issued includes the issuance of 558,700 common units, 915,000 common units and 302,813 common units pursuant to the exercise, in full or in part, of the underwriters’ over-allotment options granted in connection with the May 2010, November 2010 and March 2011 equity offerings, respectively.

⁽³⁾		GP units issued represent general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% interest.

⁽⁴⁾		Net proceeds were primarily used to repay amounts outstanding under our revolving credit facility.

RESULTS OF OPERATIONS

OPERATING RESULTS

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
thousands	2011			2010			2011			2010
Revenues ⁽¹⁾
Gathering, processing and transportation of natural gas and natural gas liquids	$	67,509		$	55,491		$	128,639		$	112,406
Natural gas, natural gas liquids and condensate sales		90,557			67,033			161,962			136,905
Equity income and other, net		3,682			2,459			7,140			4,608

Total revenues		161,748			124,983			297,741			253,919

Operating expenses ⁽¹⁾
Cost of product		62,317			38,506			109,137			80,479
Operation and maintenance		23,639			22,205			44,501			44,596
General and administrative		7,082			5,455			13,780			11,523
Property and other taxes		3,974			3,649			7,933			7,268
Depreciation, amortization and impairments		21,711			17,613			41,269			35,332

Total operating expenses		118,723			87,428			216,620			179,198

Operating income		43,025			37,555			81,121			74,721
Interest income – affiliates		4,225			4,232			8,450			8,462
Interest expense		(6,697	)		(3,598	)		(12,808	)		(7,126	)
Other expense, net		(3,682	)		(2,393	)		(1,922	)		(2,373	)

Income before income taxes		36,871			35,796			74,841			73,684
Income tax expense		94			3,419			126			8,975

Net income		36,777			32,377			74,715			64,709
Net income attributable to noncontrolling interests		2,838			3,371			5,792			5,265

Net income attributable to Western Gas Partners, LP	$	33,939		$	29,006		$	68,923		$	59,444

Key Performance Metrics ⁽²⁾
Gross margin	$	99,431		$	86,477		$	188,604		$	173,440
Adjusted EBITDA attributable to Western Gas Partners, LP	$	63,479		$	51,552		$	119,793		$	104,182
Distributable cash flow	$	56,619		$	46,901		$	106,345		$	94,739


⁽¹⁾		Revenues include affiliate amounts earned by the Partnership from services provided to our affiliates, as well as from 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 4. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, 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 (“GAAP”).

For purposes of the following discussion, any increases or decreases “for the three months ended June 30, 2011” refer to the comparison of the three months ended June 30, 2011, to the three months ended June 30, 2010, any increases or decreases “for the six months ended June 30, 2011” refer to the comparison of the six months ended June 30, 2011, to the six months ended June 30, 2010, and any increases or decreases “for the three and six months ended June 30, 2011” refer to both the comparison for the three months ended June 30, 2011, and to the comparison for the six months ended June 30, 2011.

Operating Statistics


	Three Months Ended						Six Months Ended
	June 30,						June 30,
MMcf/d except percentages	2011		2010		Δ		2011		2010		Δ
Gathering and transportation throughput ⁽¹⁾		884		1,059		(17)%		893		1,068		(16)%
Processing throughput ⁽²⁾		851		664		28%		800		649		23%
Equity investment throughput ⁽³⁾		54		114		(53)%		64		118		(46)%

Total throughput ⁽⁴⁾		1,789		1,837		(3)%		1,757		1,835		(4)%
Throughput attributable to noncontrolling interests		234		198		18%		226		194		16%

Total throughput attributable to Western Gas Partners, LP		1,555		1,639		(5)%		1,531		1,641		(7)%


⁽¹⁾		Excludes average NGL pipeline volumes of 23 MBbls/d and 16 MBbls/d, for the three months ended June 30, 2011 and 2010, respectively, and 22 MBbls/d and 16 MBbls/d, for the six months ended June 30, 2011 and 2010, respectively.

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

⁽³⁾		Represents our 14.81% share of Fort Union’s gross volumes and excludes crude oil throughput measured in barrels attributable to White Cliffs.

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

Gathering and transportation throughput decreased by 175 MMcf/d for both the three and six months ended June 30, 2011, primarily due to lower throughput at the MIGC system resulting from the January 2011 expiration of certain contracts which were not renewed due to the start up of the Bison pipeline, and throughput decreases at the Haley, Pinnacle, Dew and Hugoton systems resulting from natural production declines and reduced drilling activity in those areas. These declines were partially offset by throughput increases at the Wattenberg system due to increased drilling activity in the area.

Processing throughput increased by 187 MMcf/d and 151 MMcf/d for the three and six months ended June 30, 2011, respectively, primarily due to the additional throughput from the Platte Valley system acquired in February 2011, as well as throughput increases at the Chipeta, Granger and Hilight systems, resulting from drilling activity in these areas driven by the relatively high liquid content of the gas volumes produced.

Equity investment volumes decreased by 60 MMcf/d and by 54 MMcf/d for the three and six months ended June 30, 2011, respectively, due to lower throughput at the Fort Union system following the start up of the Bison pipeline.

Natural Gas Gathering, Processing and Transportation Revenues

Three Months Ended

Six Months Ended

June 30,

thousands except percentages

2011

2010

2011

2010

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

67,509

55,491

22%

128,639

112,406

14%

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $12.0 million and $16.2 million for the three and six months ended June 30, 2011, respectively, due to the acquisition of the Platte Valley system, increased fee revenue at the Wattenberg system as a result of changes in affiliate contract terms (from primarily keep-whole and percentage-of-proceeds arrangements to fee-based arrangements) effective July 2010, and increased throughput at the Chipeta system due to additional drilling activity. These increases were partially offset by decreased fee revenue at the MIGC, Haley, Hugoton and Dew systems resulting from decreased throughput.

Natural Gas, Natural Gas Liquids and Condensate Sales


	Three Months Ended						Six Months Ended
thousands except percentages and	June 30,						June 30,
per-unit amounts	2011		2010		Δ		2011		2010		Δ
Natural gas sales	$	29,259	$	14,876		97%	$	49,689	$	29,588		68%
Natural gas liquids sales		52,494		44,701		17%		95,216		89,671		6%
Drip condensate sales		8,804		7,456		18%		17,057		17,646		(3)%

Total	$	90,557	$	67,033		35%	$	161,962	$	136,905		18%

Average price per unit:
Natural gas (per Mcf)	$	5.91	$	5.70		4%	$	5.86	$	5.60		5%
Natural gas liquids (per Bbl)	$	44.72	$	43.14		4%	$	46.20	$	40.24		15%
Drip condensate (per Bbl)	$	74.00	$	71.70		3%	$	73.53	$	71.47		3%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $23.5 million for the three months ended June 30, 2011, which consisted of a $14.4 million increase in natural gas sales, a $7.8 million increase in NGLs sales and a $1.3 million increase in drip condensate sales.

For the three months ended June 30, 2011, natural gas sales increased due to an 88% increase in the volume of natural gas sold and NGLs sales increased due to a 10% increase in the volume of NGLs sold as a result of higher throughput at the Granger and Hilight systems, as well as the acquisition of the Platte Valley system. Increases are also attributable to 4% increases in both natural gas and NGLs sales prices. The increase in drip condensate sales for the three months ended June 30, 2011, was primarily due to an increase in the average sales prices at the Hugoton and Wattenberg systems along with Platte Valley sales beginning March 2011, partially offset by a decrease in the volume of condensate sold.

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $25.1 million for the six months ended June 30, 2011, which consisted of a $20.1 million increase in natural gas sales and a $5.5 million increase in NGLs sales, partially offset by a $0.6 million decrease in drip condensate sales.

The increase in natural gas sales was due to a 60% increase in the volume of natural gas sold and a 5% increase in the average price. The increase in NGLs sales was primarily due to a 15% increase in average price, partially offset by a 7% decrease in volumes sold attributable to the decrease in volumes sold at the Wattenberg system as a result of changes in affiliate contract terms (from primarily keep-whole and percentage-of-proceeds arrangements to fee-based arrangements, whereby the producer takes product in kind) effective July 2010. The decrease in drip condensate sales for the six months ended June 30, 2011, was primarily due to a decrease in the volume of condensate sold, partially offset by higher average sales price at the Hugoton system and Platte Valley sales beginning March 2011.

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, Wattenberg, Hilight, Newcastle and Hugoton systems. The average natural gas and NGLs prices for the three and six months ended June 30, 2010, include the effects of commodity price swap agreements attributable to sales for only the Granger, Hilight and Newcastle systems. See Note 4. Transactions with Affiliates—Commodity price swap agreements in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Equity Income and Other Revenues


	Three Months Ended						Six Months Ended
	June 30,						June 30,
thousands except percentages	2011		2010		Δ		2011		2010		Δ
Equity income	$	2,646	$	1,308		102%	$	4,690	$	2,687		75%
Other revenues, net		1,036		1,151		(10)%		2,450		1,921		28%

Total equity income and other revenues, net	$	3,682	$	2,459		50%	$	7,140	$	4,608		55%

Equity income increased by $1.3 million and $2.0 million for the three and six months ended June 30, 2011, respectively, due to the increase in the ownership interest in White Cliffs in September 2010.

Other revenues decreased by $0.1 million and increased by $0.5 million for the three and six months ended June 30, 2011, respectively, primarily due to changes in gas imbalance positions at the Wattenberg, Granger, Hilight and MIGC systems.

Cost of Product and Operation and Maintenance Expenses


	Three Months Ended						Six Months Ended
	June 30,						June 30,
thousands except percentages	2011		2010		Δ		2011		2010		Δ
Cost of product	$	62,317	$	38,506		62%	$	109,137	$	80,479		36%
Operation and maintenance		23,639		22,205		6%		44,501		44,596		—%

Total cost of product and operation and maintenance expenses	$	85,956	$	60,711		42%	$	153,638	$	125,075		23%

Cost of product expense increased by $23.8 million for the three months ended June 30, 2011, which includes a $27.6 million increase due to the acquisition of the Platte Valley system and increased throughput at systems subject to percent-of-proceeds and keep-whole contracts, partially offset by a $3.8 million decrease due to changes in gas imbalance positions.

Cost of product expense increased by $28.7 million for the six months ended June 30, 2011, which includes a $36.4 million increase primarily due to the acquisition of the Platte Valley system as well as increased throughput at systems subject to percent-of-proceeds and keep-whole contracts, partially offset by a $7.7 million decrease due to changes in gas imbalance positions.

Cost of product expense includes the effects of commodity price swap agreements attributable to purchases for the three and six months ended June 30, 2011 and 2010. See Note 4. Transactions with Affiliates—Commodity price swap agreements in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Operation and maintenance expense increased by $1.4 million for the three months ended June 30, 2011, primarily due to the acquisition of the Platte Valley system.

General and Administrative, Depreciation and Other Expenses


	Three Months Ended							Six Months Ended
	June 30,						June 30,
thousands except percentages	2011		2010		Δ		2011		2010		Δ
General and administrative	$	7,082	$	5,455		30%	$	13,780	$	11,523		20%
Property and other taxes		3,974		3,649		9%		7,933		7,268		9%
Depreciation, amortization and impairments		21,711		17,613		23%		41,269		35,332		17%

Total general and administrative, depreciation and other expenses	$	32,767	$	26,717		23%	$	62,982	$	54,123		16%

General and administrative expenses increased by $1.6 million and $2.3 million for the three and six months ended June 30, 2011, respectively, due to (i) an increase in noncash payroll expenses primarily due to an increase in the value of incentive plan awards, (ii) an increase in corporate and management personnel costs allocated to us pursuant to the omnibus agreement, and (iii) an increase in legal, consultation and accounting transition fees related to the Platte Valley acquisition. These increases were partially offset by the management fee allocated to the Wattenberg assets during the three and six months ended June 30, 2010, which was discontinued upon contribution of the assets to us effective July 2010.

Property and other taxes increased by $0.3 million and $0.7 million for the three and six months ended June 30, 2011, respectively, primarily due to the ad valorem tax for the Platte Valley assets.

Depreciation, amortization and impairments increased by $4.1 million and $5.9 million for the three and six months ended June 30, 2011, respectively, primarily attributable to the addition of the Platte Valley system, depreciation associated with previously leased compressors used at the Granger and Wattenberg systems purchased and contributed to us during 2010, and capital projects completed at the Hugoton system.

Interest Income and Interest Expense


	Three Months Ended						Six Months Ended
	June 30,						June 30,
thousands except percentages	2011		2010		Δ		2011		2010		Δ
Interest income on note receivable	$	4,225	$	4,225		—%	$	8,450	$	8,450		—%
Interest income, net on affiliate balances		—		7		(100)%		—		12		(100)%

Interest income — affiliates	$	4,225	$	4,232	nm⁽¹⁾		$	8,450	$	8,462	nm⁽¹⁾


Third Parties
Interest expense on long-term debt	$	(4,474)	$	(1,130)		296%	$	(7,150)	$	(2,107)		239%
Amortization of debt issuance costs and commitment fees		(1,003)		(683)		47%		(3,204)		(1,449)		121%
Capitalized interest		13		—	nm			13		—	nm
Affiliates
Interest expense on notes payable		(1,233)		(1,750)		(30)%		(2,467)		(3,500)		(30)%
Credit facility commitment fees		—		(35)		(100)%		—		(70)		(100)%

Interest expense	$	(6,697)	$	(3,598)		86%	$	(12,808)	$	(7,126)		80%


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

Interest expense increased by $3.1 million and by $5.7 million for the three and six months ended June 30, 2011, respectively, due to interest expense incurred on the 5.375% Senior Notes issued in May 2011, higher interest expense on the amounts outstanding on our revolving credit facility during 2011, interest expense during 2011 under the Wattenberg term loan (described in Liquidity and Capital Resources), as well as $1.3 million of accelerated amortization expense related to the early repayment of the Wattenberg term loan in March 2011. This increase is partially offset by a decrease in interest expense on the Note Payable to Anadarko which was amended in December 2010 reducing the interest rate from 4.00% to 2.82% for the remainder of the term. See Note 7. Debt and Interest Expense in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Form 10-Q.

Other Income (Expense), Net

Three Months Ended

Six Months Ended

June 30,

thousands except percentages

2011

2010

2011

2010

Other expense, net

(3,682)

(2,393)

54%

(1,922)

(2,373)

(19)%

Other expense, net for the three months ended June 30, 2011, primarily consists of the reversal of a $1.7 million unrealized gain on our terminated forward-starting interest-rate swap agreement, previously recorded in March 2011, and a $1.9 million loss, realized upon termination of the interest-rate swap agreement in May 2011. Other expense, net for the six months ended June 30, 2011, primarily consists of the $1.9 million loss realized upon termination of the interest-rate swap agreement in May 2011. Other expense, net for the three and six months ended June 30, 2010, primarily consists of expense incurred in contemplation of refinancing existing borrowings under our revolving credit agreement with long-term fixed-rate notes. In April 2010 we entered into financial agreements to fix the underlying ten-year Treasury rates with respect to potential note issuances that were under consideration at that time. Upon reaching our decision not to issue the notes in May 2010, we terminated the agreements at a cost of $2.4 million.

Income Tax Expense


	Three Months Ended								Six Months Ended
	June 30,								June 30,
thousands except percentages	2011			2010			Δ		2011			2010			Δ
Income before income taxes	$	36,871		$	35,796			3%	$	74,841		$	73,684			2%
Income tax expense		94			3,419			(97)%		126			8,975			(99)%
Effective tax rate		—	%		10	%				—	%		12	%

We are not a taxable entity for U.S. federal income tax purposes. For the three and six months ended June 30, 2011, only the portion of our income allocable to Texas was subject to Texas margin tax. For the three and six months ended June 30, 2010, other than income earned by the Granger and Wattenberg assets, only the portion of our income allocable to Texas was subject to Texas margin tax. Income attributable to the Wattenberg assets prior to and including July 2010 and income attributable to the Granger assets prior to and including January 2010 were subject to federal and state income tax, resulting in the lower income tax expense for the three and six months ended June 30, 2011. Income earned by the Granger and Wattenberg assets for periods subsequent to January 2010 and July 2010, respectively, was subject only to Texas margin tax.

For 2011 and 2010, the Partnership’s variance from the federal statutory rate is primarily attributable to the Partnership’s status as a non-taxable entity for U.S. federal income tax purposes.

Noncontrolling Interests

Three Months Ended

Six Months Ended

June 30,

thousands except percentages

2011

2010

2011

2010

Net income attributable to noncontrolling interests

2,838

3,371

(16)%

5,792

5,265

10%

For the three months ended June 30, 2011, net income attributable to noncontrolling interests decreased by $0.5 million, primarily due to decreased NGL recoveries resulting from a cryogenic unit outage at Chipeta during April 2011. Net income attributable to noncontrolling interests increased by $0.5 million for the six months ended June 30, 2011, due to the higher overall year to date volumes and improved liquids recoveries at the Chipeta system.

Key Performance Metrics


	Three Months Ended						Six Months Ended
thousands except percentages	June 30,						June 30,
and gross margin per Mcf	2011		2010		Δ		2011		2010		Δ
Gross margin	$	99,431	$	86,477		15%	$	188,604	$	173,440		9%
Gross margin per Mcf ⁽¹⁾		0.61		0.52		17%		0.59		0.52		13%
Gross margin per Mcf attributable to Western Gas Partners, LP⁽²⁾		0.67		0.55		22%		0.65		0.55		18%
Adjusted EBITDA⁽³⁾		63,479		51,552		23%		119,793		104,182		15%
Distributable cash flow⁽³⁾	$	56,619	$	46,901		21%	$	106,345	$	94,739		12%


⁽¹⁾		Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput, including 100% of gross margin and volumes attributable to Chipeta and our 14.81% interest in income and volumes attributable to Fort Union.

⁽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 Western Gas Partners, LP. Calculation includes income attributable to our investments in Fort Union and White Cliffs and volumes attributable to our investment in Fort Union.

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

Gross margin and Gross margin per Mcf. Gross margin increased by $13.0 million for the three months ended June 30, 2011, primarily due to the acquisition of the Platte Valley system; higher margins at the Wattenberg and Hilight systems due to an increase in prices and volumes, including the impact of commodity price swap agreements; and the increase in our interest in White Cliffs from 0.4% to 10% in September 2010. These increases were partially offset by (i) lower gross margins at the Haley and Hugoton systems due to naturally declining production volumes and (ii) lower gross margin at the MIGC system due to the expiration of certain firm transportation contracts in January 2011. For the three months ended June 30, 2011, gross margin per Mcf increased by 17% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 22%, primarily due to the acquisition of the Platte Valley system in 2011, the additional interest in the White Cliffs system in September 2010 and changes in the throughput mix of the portfolio.

Gross margin increased by $15.2 million for the six months ended June 30, 2011, primarily due to the acquisition of the Platte Valley system; higher margins at the Chipeta and Hilight systems due to an increase in volumes and prices, including the impact of commodity price swap agreements at the Hilight system; and the increase in our interest in White Cliffs from 0.4% to 10% in September 2010. These increases were partially offset by (i) lower gross margins at the Haley and Hugoton systems due to naturally declining production volumes and (ii) lower gross margin at the MIGC system due to the expiration of certain firm transportation contracts in January 2011. For the six months ended June 30, 2011, gross margin per Mcf increased by 13% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 18%, due to the acquisition of the Platte Valley system in 2011, the additional interest in the White Cliffs system in September 2010 and changes in the throughput mix of the portfolio.

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, general and administrative expense in excess of the omnibus cap (if any), 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, which management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:

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

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

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

Adjusted EBITDA increased by $11.9 million for the three months ended June 30, 2011, primarily due to a $35.4 million increase in total revenues excluding equity income, a $1.9 million increase in distributions from Fort Union and White Cliffs and a $0.5 million decrease in net income attributable to noncontrolling interests. These changes were partially offset by a $23.8 million increase in cost of product, a $0.4 million increase in general and administrative expenses excluding non-cash equity-based compensation and a $1.4 million increase in operation and maintenance expenses.

Adjusted EBITDA increased by $15.6 million for the six months ended June 30, 2011, primarily due to a $41.8 million increase in total revenues excluding equity income and a $3.2 million increase in distributions from Fort Union and White Cliffs. These changes were partially offset by a $28.7 million increase in cost of product and a $0.5 million increase in net income attributable to noncontrolling interests.

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), maintenance capital expenditures, and income taxes. 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. We also 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.

Distributable cash flow increased by $9.7 million for the three months ended June 30, 2011, primarily due to the $11.9 million increase in Adjusted EBITDA and a $0.9 million decrease in cash paid for maintenance capital expenditures, partially offset by a $3.1 million increase in interest expense on borrowings.

Distributable cash flow increased by $11.6 million for the six months ended June 30, 2011, primarily due to the $15.6 million increase in Adjusted EBITDA and a $1.7 million decrease in cash paid for maintenance capital expenditures, partially offset by a $5.7 million increase in interest expense on borrowings.

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, while 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 has important limitations as an analytical tool because it excludes 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. 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.

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						Six Months Ended
	June 30,						June 30,
thousands	2011			2010			2011			2010
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	63,479		$	51,552		$	119,793		$	104,182
Less:
Distributions from equity investees		3,013			1,088			5,447			2,238
Non-cash equity-based compensation expense		1,918			681			3,846			1,248
Interest expense		6,697			3,598			12,808			7,126
Income tax expense ⁽¹⁾		94			3,419			126			8,975
Depreciation, amortization and impairments ⁽¹⁾		21,007			16,907			39,860			33,926
Other expense⁽¹⁾		3,682			2,393			3,682			2,393
Add:
Equity income, net		2,646			1,308			4,690			2,687
Interest income – affiliates		4,225			4,232			8,450			8,462
Other income⁽¹⁾		—			—			1,759			19

Net income attributable to Western Gas Partners, LP	$	33,939		$	29,006		$	68,923		$	59,444


Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	63,479		$	51,552		$	119,793		$	104,182
Adjusted EBITDA attributable to noncontrolling interests		3,542			4,077			7,200			6,670
Interest income (expense), net		(2,472	)		634			(4,358	)		1,336
Non-cash equity-based compensation expense		(1,918	)		(681	)		(3,846	)		(1,248	)
Current income tax expense		(77	)		(4,267	)		(167	)		(11,608	)
Other expense, net		(3,682	)		(2,393	)		(1,922	)		(2,373	)
Distributions from equity investees less than (in excess of) equity income, net		(367	)		220			(757	)		449
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		(9,030	)		(788	)		(17,715	)		(6,317	)
Accounts payable, accrued liabilities and natural gas imbalance payable		6,302			(1,623	)		12,189			8,106
Other		2,512			536			2,936			529

Net cash provided by operating activities	$	58,289		$	47,267		$	113,353		$	99,726


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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
thousands	2011		2010		2011		2010
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP
Distributable cash flow	$	56,619	$	46,901	$	106,345	$	94,739
Less:
Distributions from equity investees		3,013		1,088		5,447		2,238
Non-cash equity-based compensation expense		1,918		681		3,846		1,248
Income tax expense ⁽¹⁾		94		3,419		126		8,975
Depreciation, amortization and impairments ⁽¹⁾		21,007		16,907		39,860		33,926
Other expense⁽¹⁾		3,682		2,393		3,682		2,393
Add:
Equity income, net		2,646		1,308		4,690		2,687
Cash paid for maintenance capital expenditures ⁽¹⁾		4,375		5,278		9,077		10,767
Capitalized interest		13		—		13		—
Interest income, net (non-cash settled)		—		7		—		12
Other income⁽¹⁾		—		—		1,759		19

Net income attributable to Western Gas Partners, LP	$	33,939	$	29,006	$	68,923	$	59,444


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

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, 2011, include cash flows generated from operations, including interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under our revolving credit facility, and issuances of additional common and general partner units or debt securities. We believe that cash flows generated from the sources above will be sufficient to satisfy our short-term working capital requirements and long-term maintenance capital expenditure requirements. The amount of future distributions to unitholders will depend on results of operations, financial conditions, 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 debt and common unit 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 revolving credit facility 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 subsequent to the end of each quarter. We have made cash distributions to our unitholders and have increased our quarterly distribution each quarter from the second quarter of 2009 through the second quarter of 2011. On June 30, 2011, the board of directors of our general partner declared a cash distribution to our unitholders of $0.405 per unit, or $36.1 million in aggregate, including incentive distributions. The cash distribution is payable on August 12, 2011, to unitholders of record at the close of business on July 29, 2011.

Management continuously monitors our leverage position and coordinates its capital expenditure program, quarterly distributions and acquisition strategy with its expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance outstanding debt balances with longer-term notes. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statement. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Please read Item 1A—Risk Factors of our 2010 annual report on Form 10-K.

Working capital. As of June 30, 2011, we had $35.9 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 can be capital intensive, requiring significant investment to maintain and improve existing facilities. 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 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 and capital incurred were as follows:


	Six Months Ended June 30,
thousands	2011		2010

Acquisitions	$	303,602	$	241,680


Expansion capital expenditures	$	20,840	$	39,298
Maintenance capital expenditures		9,116		10,891

Total capital expenditures ⁽¹⁾	$	29,956	$	50,189


Capital incurred ⁽²⁾	$	34,193	$	50,323


⁽¹⁾		Capital expenditures for the six months ended June 30, 2010, include $40.6 million of pre-acquisition capital expenditures for Partnership assets and capital expenditures for the six months ended June 30, 2011 and 2010, include the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners.

⁽²⁾		Capital incurred for the six months ended June 30, 2010, includes $41.4 million of pre-acquisition capital incurred for the Partnership assets and capital incurred for the six months ended June 30, 2011 and 2010, includes the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

Acquisitions include the Platte Valley acquisition and the Granger acquisition described under the caption Acquisitions within this Item 2.

Capital expenditures, excluding acquisitions, decreased by $20.2 million for the six months ended June 30, 2011. Expansion capital expenditures decreased by $18.5 million for the six months ended June 30, 2011, primarily due to the purchase of previously leased compressors at the Wattenberg system during the six months ended June 30, 2010 for $37.5 million, partially offset by an increase of $19.0 million in expenditures primarily at our Chipeta and Hilight systems during the six months ended June 30, 2011. Maintenance capital expenditures decreased by $1.8 million, primarily as a result of fewer well connections at the Haley, Hugoton and Granger systems in 2011 and improvements at the Granger system completed during 2010, partially offset by power system upgrades at the Dew system in 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	2011			2010

Net cash provided by (used in):
Operating activities	$	113,353		$	99,726
Investing activities		(333,409	)		(292,179	)
Financing activities		255,677			186,871


Net increase (decrease) in cash and cash equivalents	$	35,621		$	(5,582	)

Operating Activities. Net cash provided by operating activities increased by $13.6 million for the six months ended June 30, 2011, as compared to the six months ended June 30, 2010, primarily due to the following items:

	•		a $41.8 million increase in revenues, excluding equity income;

	•		an $11.4 million decrease in current income tax expense;

	•		a $6.5 million increase due to changes in accounts payable balances and other items;

	•		a $0.3 million decrease in general and administrative expenses, excluding non-cash equity-based compensation; and

	•		a $0.1 million decrease in operating and maintenance expenses.

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

	•		a $28.7 million increase in cost of product expense;

	•		an $11.4 million decrease due to changes in accounts receivable balances;

	•		a $5.7 million increase in interest expense; and

	•		a $0.7 million increase in property and other taxes expense.

Investing Activities. Net cash used in investing activities for the six months ended June 30, 2011, included $303.6 million of cash paid for the Platte Valley acquisition and $30.0 million of capital expenditures. Net cash used in investing activities for the six months ended June 30, 2010, included $241.7 million of cash paid for the Granger acquisition and $50.2 million of capital expenditures. See the sub-caption Capital expenditures above within this Liquidity and Capital Resources discussion.

Financing Activities. Net cash provided by financing activities for the six months ended June 30, 2011, included $303.0 million of borrowings to fund the Platte Valley acquisition, $132.6 million of net proceeds from our March 2011 equity offering and $493.9 million net proceeds from our Notes offering in May 2011, after debt discount and offering costs, each offset by repayment of amounts due under our revolving credit facility using the offering proceeds. Financing activities for the six months ended June 30, 2011, also included the $250.0 million repayment of the Wattenberg term loan (described below) using borrowings from our revolving credit facility. Financing activities for the six months ended June 30, 2010 included the $210.0 million of borrowings to partially fund the Granger acquisition. For the six months ended June 30, 2011 and 2010, we paid $63.7 million and $43.4 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $7.4 million and $2.1 million during the six months ended June 30, 2011 and 2010, respectively, primarily for expansion of the cryogenic units. Distributions from Chipeta to noncontrolling interest owners totaled $7.5 million and $6.4 million for the six months ended June 30, 2011 and 2010, 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, 2011, our outstanding debt consisted of $493.9 million of 5.375% Senior Notes and the $175.0 million note payable to Anadarko. See Note 7. Debt and Interest Expense in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Form 10-Q.

5.375% Senior Notes due 2021. In May 2011, we completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes (the “Notes”) at a public offering price of 98.778%. Interest on the Notes will be paid semi-annually on June 1 and December 1 of each year, commencing on December 1, 2011. The Notes mature on June 1, 2021, unless redeemed, in whole or in part, at any time prior to maturity, at a redemption price that includes a make-whole premium. Proceeds from the offering of the Notes (net of the underwriting discount of $3.3 million and debt issuance costs) were used to repay the then-outstanding balance on the revolving credit facility, with the remainder used for general partnership purposes.

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees will be released if, among other things, the Subsidiary Guarantors are released from their obligations under our revolving credit facility.

The Notes indenture contains customary events of default including, among others, (i) default in any payment of interest on any debt securities when due that continues for 30 days; (ii) default in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii) certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing the Notes also contains covenants that will, among other things, limit our ability, as well as that of the Subsidiary Guarantors, to create liens on our principal properties, engage in sale and leaseback transactions, and merge or consolidate with another entity or sell, lease or transfer substantially all of our properties or assets to another entity. At June 30, 2011, we were in compliance with all covenants under the Notes.

Note payable to Anadarko. In December 2008, we entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 4.00% through November 2010, and is fixed at 2.82% thereafter, reflecting an amendment to the term loan agreement made in December 2010. We have the option, at any time, to repay the outstanding principal amount in whole or in part.

The provisions of the five-year term loan agreement contain customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to the Partnership and (iii) a change of control. At June 30, 2011, we were in compliance with all covenants under this agreement.

Revolving credit facility. In March 2011, we entered into an amended and restated $800.0 million senior unsecured revolving credit facility, or the “RCF,” and borrowed $250.0 million under the RCF to repay the Wattenberg term loan (described below). The RCF amended and restated our $450.0 million credit facility, which was originally entered into in October 2009. The RCF matures in March 2016 and bears interest at London Interbank Offered Rate, or “LIBOR,” plus applicable margins ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 0.30% to 0.90%. We are also required to pay a quarterly facility fee ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon our consolidated leverage ratio as defined in the RCF.

The RCF contains covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of our business, sell all or substantially all of our assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and certain financial tests, as of the end of each quarter, including a maximum consolidated leverage ratio, as defined in the RCF, of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio, as defined in the RCF, of 2.0 to 1.0.

All amounts due under the RCF are unconditionally guaranteed by our wholly owned subsidiaries. We will no longer be required to comply with the minimum consolidated interest coverage ratio as well as the subsidiary guarantees and certain of the aforementioned covenants, if we obtain two of the following three ratings: BBB- or better by S&P, Baa3 or better by Moody’s or BBB- or better by Fitch. As of June 30, 2011, no amounts were outstanding under the RCF, with $800.0 million available for borrowing. At June 30, 2011, we were in compliance with all covenants under the 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 March 2011 using borrowings from our RCF.

Registered securities. We may issue an indeterminate amount of limited partner common units and various debt securities under our effective shelf registration statement on file with the SEC.

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 a note payable to Anadarko, a revolving credit facility, other third-party long-term debt, a corporate office lease and warehouse lease, for which information is provided in Note 7. Debt and Interest Expense and Note 8. Commitments and Contingencies included in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. Our contractual obligations also include asset retirement obligations, which have not changed significantly since December 31, 2010, except for asset retirement obligations assumed in connection with the Platte Valley acquisition for which information is provided under Note 1. Description of Business and Basis of Presentation—Acquisitions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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 Part I, Item 1 of this Form 10-Q.

RECENT ACCOUNTING DEVELOPMENTS

Recently issued accounting standards not yet adopted. In May 2011, the Financial Accounting Standards Board (the “FASB”) issued an Accounting Standards Update (“ASU”) amending guidance on fair value measurements and related disclosures. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement requirements, changes the fair value measurement requirements for certain financial instruments and requires additional disclosures about fair value measurements. This ASU will apply to our consolidated financial statements prospectively beginning January 1, 2012, and the impact, if any, is currently under evaluation.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk. 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.

In addition, 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 September 2015. For additional information on the commodity price swap agreements, see Note 4. Transactions with Affiliates—Commodity price swap agreements in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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. 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 2010 and 2011 were low compared to historic rates. Only our revolving credit facility carries interest at variable rates based on LIBOR, and we did not have an outstanding balance as of June 30, 2011. If interest rates rise, our future financing costs could increase if we incur borrowings under our revolving credit facility.

We entered into a forward-starting interest-rate swap agreement in March 2011 to mitigate the risk of rising interest rates prior to the issuance of the Notes. In May 2011, we issued the Notes and terminated the swap agreement, realizing a loss of $1.9 million, which is included in other expense, net on our consolidated statements of income. For the three months ended June 30, 2011, a 10% change in LIBOR would have resulted in a nominal change in interest expense.

We may incur additional debt in the future, either under our revolving credit facility 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. 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, 2011.

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, 2011, 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 financial condition, results of operations or cash flows, or for which disclosure is 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 1, Item 1A set forth in our annual report on Form 10-K for the year ended December 31, 2010, together with all of the other information included in this document; the Partnership’s annual report on Form 10-K; and in our other public filings, press releases, and discussions with management of the Partnership. Additionally, for a full discussion of the risks associated with Anadarko’s business, see Item 1A under Part I in Anadarko’s annual report on Form 10-K for the year ended December 31, 2010, 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.

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).

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		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).

3.10		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).

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.LAB**		XBRL Label Linkbase Document

101.PRE**		XBRL Presentation Linkbase Document

101.DEF**		XBRL Definition 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 4, 2011


		/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 4, 2011


		/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)