Edgar Filing: Western Gas Partners LP

thousands

Property, plant and equipment

134,719

Asset retirement obligations

Total purchase price

134,545

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2013

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

For the transition period from to

Commission file number: 001-34046

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)


Delaware		26-1075808
(State or other jurisdiction of		(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 ¨

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

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

Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

(Do not check if smaller reporting company)

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

There were 112,131,561 common units outstanding as of July 31, 2013.

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, 2013 and 2012	4

		Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	5

		Consolidated Statement of Equity and Partners’ Capital for the six months ended June 30, 2013	6

		Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012	7

		Notes to Consolidated Financial Statements	8

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
		Cautionary Note Regarding Forward-Looking Statements	22
		Executive Summary	24
		Acquisitions	25
		Equity Offerings	26
		Results of Operations	27
		Operating Results	27
		Key Performance Metrics	33
		Liquidity and Capital Resources	37
		Contractual Obligations	42
		Off-Balance Sheet Arrangements	42

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

	Item 4.	Controls and Procedures	44

PART II		OTHER INFORMATION

	Item 1.	Legal Proceedings	44

	Item 1A.	Risk Factors	44

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44

	Item 6.	Exhibits	45

DEFINITIONS

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

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

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

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

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

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

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

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

MBbls/d: One thousand barrels per day.

MMBtu: One million British thermal units.

MMcf/d: One million cubic feet per day.

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

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)


	Three Months Ended June 30,				Six Months Ended June 30,
thousands except unit and per-unit amounts	2013		2012 ⁽¹⁾		2013		2012 ⁽¹⁾
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	69,175	$	59,941	$	135,074	$	121,060
Natural gas, natural gas liquids and condensate sales		129,996		104,008		241,666		209,661
Equity income and other, net		4,869		4,133		8,850		8,134

Total revenues – affiliates		204,040		168,082		385,590		338,855
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids		40,625		33,503		77,616		63,973
Natural gas, natural gas liquids and condensate sales		9,565		18,218		19,624		41,051
Other, net		896		507		2,043		1,107

Total revenues – third parties		51,086		52,228		99,283		106,131

Total revenues		255,126		220,310		484,873		444,986

Operating expenses
Cost of product ⁽²⁾		93,460		82,456		176,543		165,612
Operation and maintenance ⁽²⁾		41,669		35,690		78,408		67,811
General and administrative ⁽²⁾		7,288		10,310		14,952		20,584
Property and other taxes		6,086		4,833		11,871		9,670
Depreciation, amortization and impairments		36,496		27,741		68,936		54,808

Total operating expenses		184,999		161,030		350,710		318,485

Operating income		70,127		59,280		134,163		126,501
Interest income, net – affiliates		4,225		4,225		8,450		8,450
Interest expense ⁽³⁾		(12,654)		(9,560)		(24,465)		(19,141)
Other income (expense), net		499		(1,267)		1,173		(809)

Income before income taxes		62,197		52,678		119,321		115,001
Income tax expense		137		5,079		4,373		9,508

Net income		62,060		47,599		114,948		105,493
Net income attributable to noncontrolling interests		1,860		4,290		4,091		8,533

Net income attributable to Western Gas Partners, LP	$	60,200	$	43,309	$	110,857	$	96,960

Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	60,200	$	43,309	$	110,857	$	96,960
Pre-acquisition net (income) loss allocated to Anadarko		764		(7,032)		(4,637)		(12,520)
General partner interest in net (income) loss ⁽⁴⁾		(16,154)		(6,127)		(29,040)		(10,466)

Limited partners’ interest in net income ⁽⁴⁾	$	44,810	$	30,150	$	77,180	$	73,974
Net income per common unit – basic and diluted	$	0.41	$	0.33	$	0.72	$	0.81
Weighted average common units outstanding – basic and diluted		108,736		91,272		106,784		90,981

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

⁽²⁾

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $32.1 million and $64.0 million for the three and six months ended June 30, 2013, respectively, and $39.3 million and $72.8 million for the three and six months ended June 30, 2012, respectively. Operation and maintenance includes charges from Anadarko of $14.2 million and $27.6 million for the three and six months ended June 30, 2013, respectively, and $12.9 million and $25.4 million for the three and six months ended June 30, 2012, respectively. General and administrative includes charges from Anadarko of $5.6 million and $11.5 million for the three and six months ended June 30, 2013, respectively, and $7.8 million and $16.6 million for the three and six months ended June 30, 2012, respectively. See Note 5.

⁽³⁾	Includes affiliate (as defined in Note 1) interest expense of zero for the three and six months ended June 30, 2013, and $1.3 million and $2.6 million for the three and six months ended June 30, 2012, respectively. See Note 8.

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

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


thousands except number of units	June 30, 2013		December 31, 2012 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	74,180	$	419,981
Accounts receivable, net ⁽²⁾		76,943		50,233
Other current assets ⁽³⁾		6,162		6,998

Total current assets		157,285		477,212
Note receivable – Anadarko		260,000		260,000
Plant, property and equipment
Cost		3,873,539		3,432,392
Less accumulated depreciation		779,513		714,436

Net property, plant and equipment		3,094,026		2,717,956
Goodwill		105,336		105,336
Other intangible assets		54,798		55,490
Equity investments		211,151		106,130
Other assets		26,678		27,798

Total assets	$	3,909,274	$	3,749,922

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables ⁽⁴⁾	$	23,423	$	25,154
Accrued ad valorem taxes		11,805		11,949
Income taxes payable		663		552
Accrued liabilities ⁽⁵⁾		110,420		147,651

Total current liabilities		146,311		185,306
Long-term debt – third parties		1,418,362		1,168,278
Deferred income taxes		1,852		47,153
Asset retirement obligations and other		74,827		68,749

Total long-term liabilities		1,495,041		1,284,180

Total liabilities		1,641,352		1,469,486
Equity and partners’ capital
Common units (112,131,561 and 104,660,553 units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)		2,130,279		1,957,066
General partner units (2,288,399 and 2,135,930 units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)		66,457		52,752
Net investment by Anadarko		—		199,960

Total partners’ capital		2,196,736		2,209,778
Noncontrolling interests		71,186		70,658

Total equity and partners’ capital		2,267,922		2,280,436

Total liabilities, equity and partners’ capital	$	3,909,274	$	3,749,922

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

⁽²⁾	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $43.6 million and $19.1 million as of June 30, 2013 and December 31, 2012, respectively.

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

⁽⁴⁾	Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.7 million and $2.5 million as of June 30, 2013 and December 31, 2012, respectively.

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

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(UNAUDITED)


	Partners’ Capital
thousands	Net Investment by Anadarko		Common Units		General Partner Units		Noncontrolling Interests		Total
Balance at December 31, 2012⁽¹⁾	$	199,960	$	1,957,066	$	52,752	$	70,658	$	2,280,436
Net income		4,637		77,180		29,040		4,091		114,948
Issuance of common and general partner units, net of offering expenses		—		416,119		9,267		—		425,386
Contributions from noncontrolling interest owners		—		—		—		1,097		1,097
Distributions to noncontrolling interest owners		—		—		—		(4,660)		(4,660)
Distributions to unitholders		—		(111,183)		(24,618)		—		(135,801)
Acquisition from affiliates		(255,642)		(209,858)		—		—		(465,500)
Contributions of equity-based compensation from Anadarko		—		1,378		28		—		1,406
Net pre-acquisition contributions from (distributions to) Anadarko		4,515		—		—		—		4,515
Net distributions of other assets to Anadarko		—		(603)		(12)		—		(615)
Elimination of net deferred tax liabilities		46,530		—		—		—		46,530
Other		—		180		—		—		180

Balance at June 30, 2013	$	—	$	2,130,279	$	66,457	$	71,186	$	2,267,922

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

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Six Months Ended June 30,
thousands	2013		2012 ⁽¹⁾
Cash flows from operating activities
Net income	$	114,948	$	105,493
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments		68,936		54,808
Non-cash equity-based compensation expense		1,682		1,834
Deferred income taxes		1,229		15,839
Debt-related amortization and other items, net		1,126		1,030
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		(26,807)		12,723
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net		336		(9,948)
Change in other items, net		3,563		4,407

Net cash provided by operating activities		165,013		186,186
Cash flows from investing activities
Capital expenditures		(339,756)		(193,053)
Acquisitions from affiliates		(466,936)		(465,507)
Acquisitions from third parties		(212,674)		—
Investments in equity affiliates		(29,824)		—
Proceeds from sale of assets to affiliates		82		11
Other		(382)		—

Net cash used in investing activities		(1,049,490)		(658,549)
Cash flows from financing activities
Borrowings, net of debt issuance costs		494,948		886,369
Repayments of debt		(245,000)		(549,000)
Increase (decrease) in outstanding checks		(1,809)		(1,010)
Proceeds from issuance of common and general partner units, net of offering expenses		425,386		216,574
Distributions to unitholders		(135,801)		(89,080)
Contributions from noncontrolling interest owners		1,097		21,315
Distributions to noncontrolling interest owners		(4,660)		(10,339)
Net contributions from (distributions to) Anadarko		4,515		29,027

Net cash provided by financing activities		538,676		503,856

Net increase (decrease) in cash and cash equivalents		(345,801)		31,493
Cash and cash equivalents at beginning of period		419,981		226,559

Cash and cash equivalents at end of period	$	74,180	$	258,052


Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets	$	615	$	4,096
Interest paid, net of capitalized interest	$	23,516	$	18,186
Taxes paid	$	—	$	72

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

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to own, operate, acquire and develop midstream energy assets.

For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership (see Western Gas Equity Partners, LP below). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), and a joint venture, Enterprise EF78 LLC (“Mont Belvieu JV”). See Note 2. “Equity investment throughput” refers to the Partnership’s 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

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


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

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

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

In December 2012, WGP completed its IPO of 19,758,150 common units representing limited partner interests in WGP at a price of $22.00 per common unit. WGP used the net proceeds from the offering to purchase common and general partner units of the Partnership resulting in aggregate proceeds to the Partnership of approximately $409.4 million, which was used for general partnership purposes, including the funding of capital expenditures.

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. Management evaluates its estimates and related assumptions regularly, utilizing historical experience and other methods considered reasonable under the particular circumstances. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial statements, and certain prior-period amounts have been reclassified to conform to the current-year presentation.

For the six months ended June 30, 2012, operating cash inflows and investing cash outflows in the Partnership’s unaudited consolidated statements of cash flows include a reduction of $16.4 million attributable to the correction of an error discovered during an analysis of accounts payable balances. This analysis revealed that certain 2012 invoices received, but not yet paid, were properly attributable to ongoing capital projects rather than to operating expenses. Management concluded that this misstatement was not material relative to the six months ended June 30, 2012, and has corrected the error within the unaudited statement of cash flows for the six months ended June 30, 2012, as included in this report.

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

In July 2009, the Partnership acquired a 51% interest in Chipeta Processing LLC (“Chipeta”) and became party to Chipeta’s limited liability company agreement. On August 1, 2012, the Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (the “additional Chipeta interest”). Prior to this transaction, the interests in Chipeta held by Anadarko and a third-party member were reflected as noncontrolling interests in the consolidated financial statements. The acquisition of Anadarko’s then remaining 24% interest was accounted for on a prospective basis as the Partnership acquired an additional interest in an already-consolidated entity. As such, effective August 1, 2012, noncontrolling interest excludes the financial results and operations of the additional Chipeta interest. The remaining 25% membership interest held by the third-party member is reflected within noncontrolling interests in the consolidated financial statements for all periods presented. See Note 2.

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

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS

The following table presents the acquisitions completed by the Partnership during 2012 and 2013, and identifies the funding sources for such acquisitions:


thousands except unit and percent amounts	Acquisition Date		Percentage Acquired		Borrowings		Cash On Hand		Common Units Issued		GP Units Issued
MGR ⁽¹⁾		01/13/12		100%	$	299,000	$	159,587		632,783		12,914
Chipeta ⁽²⁾		08/01/12		24%		—		128,250		151,235		3,086
Non-Operated Marcellus Interest⁽³⁾		03/01/13		33.75%		250,000		215,500		449,129		—
Anadarko-Operated Marcellus Interest⁽⁴⁾		03/08/13		33.75%		133,500		—		—		—
Mont Belvieu JV⁽⁵⁾		06/05/13		25%		—		78,129		—		—

⁽¹⁾

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

⁽²⁾

The Partnership acquired Anadarko’s then remaining 24% membership interest in Chipeta (as described in Note 1). The Partnership received distributions related to the additional interest beginning July 1, 2012. This transaction brought the Partnership’s total membership interest in Chipeta to 75%. The remaining 25% membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented.

⁽³⁾

The Partnership acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in the Partnership. See Non-Operated Marcellus Interest acquisition below for further information.

⁽⁴⁾

The interest acquired from a third party consisted of a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Anadarko-Operated Marcellus Interest acquisition below for further information, including the preliminary allocation of the purchase price as of June 30, 2013.

⁽⁵⁾

The acquisition from a third party consisted of a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See Mont Belvieu JV acquisition below for further information.

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS (CONTINUED)

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


	Three Months Ended June 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	205,341	$	14,969	$	220,310
Net income		40,567		7,032		47,599

	Six Months Ended June 30, 2012
thousands	Partnership Historical		Non-Operated Marcellus Interest		Combined
Revenues	$	417,583	$	27,403	$	444,986
Net income		92,973		12,520		105,493

Anadarko-Operated Marcellus Interest acquisition. The Anadarko-Operated Marcellus Interest acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Anadarko-Operated Marcellus Interest were included in the Partnership’s consolidated statements of income beginning on the acquisition date in the first quarter of 2013.

The following is a preliminary allocation of the purchase price as of June 30, 2013, including $1.0 million of post-closing purchase price adjustments, to the assets acquired and liabilities assumed in the Anadarko-Operated Marcellus Interest acquisition as of the acquisition date:

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS (CONTINUED)

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


	Six Months Ended June 30,
thousands except per unit amount	2013		2012
Revenues	$	486,127	$	446,666
Net income		115,097		103,708
Net income attributable to Western Gas Partners, LP		111,006		95,175
Net income per common unit - basic and diluted	$	0.72	$	0.77

The pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the Anadarko-Operated Marcellus Interest acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s pro forma information in the table above includes $3.4 million of revenues and $0.3 million of operating expenses, excluding depreciation, amortization and impairments, attributable to the Anadarko-Operated Marcellus Interest that are included in the Partnership’s consolidated statement of income for the six months ended June 30, 2013. The pro forma adjustments reflect pre-acquisition results of the Anadarko-Operated Marcellus Interest including (a) estimated revenues and expenses; (b) estimated depreciation and amortization based on the purchase price allocated to property, plant and equipment and estimated useful lives; and (c) interest on the Partnership’s borrowings under its revolving credit facility to finance the Anadarko-Operated Marcellus Interest acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the Anadarko-Operated Marcellus Interest acquisition, nor any future acquisition related expenses.

Mont Belvieu JV acquisition. The acquisition purchase price represents the Partnership’s 25% share of construction costs incurred by the joint venture partner up to the date of acquisition and 25% of the capitalized interest charged to the financial statements of the Mont Belvieu JV up to the date of acquisition. The allocated capitalized interest is reflected as a component of the equity investment balance recorded upon acquisition. Based on the total estimated net project cost, the construction of the fractionation facilities owned by the Mont Belvieu JV is considered a significant project and satisfies criteria for capitalization of interest. Capitalization of interest subsequent to the acquisition is treated as a basis difference between the cost of the investment and the underlying equity in the net assets of the Mont Belvieu JV. The Partnership will begin to amortize the capitalized interest recognized subsequent to the acquisition upon completion of the facilities, and will reflect the amortization as an adjustment to equity earnings from the Mont Belvieu JV.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

3. PARTNERSHIP DISTRIBUTIONS

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


thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit	Total Cash Distribution	Date of Distribution
2012
March 31	$ 0.460	$ 46,053	May 2012
June 30	$ 0.480	$ 52,425	August 2012
2013
March 31	$ 0.540	$ 70,143	May 2013
June 30⁽¹⁾	$ 0.560	$ 79,315	August 2013

⁽¹⁾

On July 17, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.56 per unit, or $79.3 million in aggregate, including incentive distributions. The cash distribution is payable on August 12, 2013, to unitholders of record at the close of business on July 31, 2013.

4. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public offerings of its common units during 2012 and 2013:

thousands except unit
and per-unit amounts

Common
Units Issued ⁽¹⁾

GP Units
Issued ⁽²⁾

Price Per
Unit

Underwriting
Discount and
Other Offering
Expenses

Net
Proceeds

June 2012 equity offering

5,000,000

102,041

43.88

7,468

216,409

May 2013 equity offering

7,015,000

143,163

61.18

13,059

424,878

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

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

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

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

Common
Units

General
Partner Units

Total

Balance at December 31, 2012

104,660,553

2,135,930

106,796,483

Non-Operated Marcellus Interest acquisition

449,129

9,166

458,295

Long-Term Incentive Plan awards

6,879

140

7,019

May 2013 equity offering

7,015,000

143,163

7,158,163

Balance at June 30, 2013

112,131,561

2,288,399

114,419,960

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Holdings of Partnership equity. As of June 30, 2013, WGP held 49,296,205 common units, representing a 43.1% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,288,399 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the Partnership’s IDRs. Also as of June 30, 2013, Anadarko Marcellus Midstream, L.L.C. (“AMM”), a subsidiary of Anadarko, separately held 449,129 common units, representing a 0.4% limited partner interest in the Partnership. As of June 30, 2013, the public held 62,386,227 common units, representing a 54.5% limited partner interest in the Partnership.

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

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

5. TRANSACTIONS WITH AFFILIATES

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

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

Note receivable from and amounts payable to Anadarko. Concurrently with the closing of the Partnership’s May 2008 IPO, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was approximately $307.0 million and $334.8 million at June 30, 2013, and December 31, 2012, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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

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


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

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


	Three Months Ended June 30,				Six Months Ended June 30,
thousands	2013		2012		2013		2012
Gains (losses) on commodity price swap agreements related to sales: ⁽¹⁾
Natural gas sales	$	2,404	$	11,746	$	7,784	$	21,596
Natural gas liquids sales		34,203		19,680		55,508		20,034

Total		36,607		31,426		63,292		41,630
Losses on commodity price swap agreements related to purchases ⁽²⁾		(22,857)		(27,347)		(42,711)		(44,539)

Net gains (losses) on commodity price swap agreements	$	13,750	$	4,079	$	20,581	$	(2,909)

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

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

Gas gathering and processing agreements. The Partnership has significant gas gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. Approximately 58% and 64% of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended June 30, 2013 and 2012, respectively, and 59% and 65% for the six months ended June 30, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko. Approximately 54% and 59% of the Partnership’s processing throughput (excluding equity investment throughput and volumes measured in barrels) for the three months ended June 30, 2013 and 2012, respectively, and 55% and 59% for the six months ended June 30, 2013 and 2012, respectively, was attributable to natural gas production owned or controlled by Anadarko.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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


	Six Months Ended June 30,
	2013		2012		2013		2012

thousands	Purchases				Sales
Cash consideration	$	1,436	$	6,744	$	82	$	11
Net carrying value		773		1,751		34		11

Partners’ capital adjustment	$	663	$	4,993	$	48	$	—

Long-term incentive plan. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”), primarily to its independent directors and the Chief Executive Officer. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized ratably over the vesting period and was approximately $0.2 million and $0.3 million for the three and six months ended June 30, 2013, respectively, and approximately $0.1 million and $0.2 million for the three and six months ended June 30, 2012, respectively.

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

The Partnership’s general and administrative expenses included $0.7 million and $1.4 million for the three and six months ended June 30, 2013, respectively, and $0.8 million and $1.6 million for the three and six months ended June 30, 2012, respectively, of equity-based compensation expense for awards granted to the executive officers of the general partner and other employees under the Anadarko Incentive Plans, which was allocated to the Partnership by Anadarko.

For the three and six months ended June 30, 2012, the Partnership’s general and administrative expenses included $2.1 million and $5.4 million, respectively, of compensation expense for grants of Unit Value Rights, Unit Appreciation Rights (“UARs”) and Distribution Equivalent Rights under the Incentive Plan to certain executive officers of the general partner as a component of their compensation, which was allocated to the Partnership by Anadarko. Awards outstanding under the Incentive Plan at June 30, 2012, were valued at $757.00 per UAR. WGP’s IPO in December 2012 resulted in the vesting of all then unvested Incentive Plan awards and the effective termination of the Incentive Plan.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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


	Three Months Ended June 30,				Six Months Ended June 30,
thousands	2013		2012		2013		2012

Revenues ⁽¹⁾	$	204,040	$	168,082	$	385,590	$	338,855
Cost of product ⁽¹⁾		32,119		39,338		64,048		72,764
Operation and maintenance ⁽²⁾		14,186		12,929		27,552		25,402
General and administrative ⁽³⁾		5,589		7,751		11,458		16,584

Operating expenses		51,894		60,018		103,058		114,750
Interest income, net ⁽⁴⁾		4,225		4,225		8,450		8,450
Interest expense ⁽⁵⁾		—		1,288		—		2,603
Distributions to unitholders ⁽⁶⁾		40,247		22,891		77,115		43,763
Contributions from noncontrolling interest owners ⁽⁷⁾		—		5,616		—		10,440
Distributions to noncontrolling interest owners ⁽⁷⁾		—		2,544		—		5,064

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

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

⁽³⁾

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

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

⁽⁵⁾

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

⁽⁶⁾	Represents distributions paid under the partnership agreement.

⁽⁷⁾

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

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. PROPERTY, PLANT AND EQUIPMENT

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


thousands	Estimated Useful Life	June 30, 2013		December 31, 2012
Land	n/a	$	2,584	$	501
Gathering systems	3 to 47 years		3,533,779		2,911,572
Pipelines and equipment	15 to 45 years		91,488		91,126
Assets under construction	n/a		235,757		422,002
Other	3 to 25 years		9,931		7,191

Total property, plant and equipment			3,873,539		3,432,392
Accumulated depreciation			779,513		714,436

Net property, plant and equipment		$	3,094,026	$	2,717,956

The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet suitable to be placed into productive service as of the respective balance sheet date. See Note 7.

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

7. COMPONENTS OF WORKING CAPITAL

A summary of other current assets is as follows:


thousands	June 30, 2013		December 31, 2012
Natural gas liquids inventory	$	2,327	$	1,678
Natural gas imbalance receivables		1,977		1,663
Prepaid insurance		162		1,897
Other		1,696		1,760

Total other current assets	$	6,162	$	6,998


A summary of accrued liabilities is as follows:
thousands	June 30, 2013		December 31, 2012
Accrued capital expenditures	$	74,435	$	112,311
Accrued plant purchases		17,789		16,350
Accrued interest expense		15,691		15,868
Short-term asset retirement obligations		1,905		1,711
Short-term remediation and reclamation obligations		649		799
Other		(49)		612

Total accrued liabilities	$	110,420	$	147,651

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE

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


	June 30, 2013						December 31, 2012
thousands	Principal		Carrying Value		Fair Value⁽¹⁾		Principal		Carrying Value		Fair Value⁽¹⁾
4.000% Senior Notes due 2022	$	670,000	$	673,449	$	656,895	$	670,000	$	673,617	$	669,928
5.375% Senior Notes due 2021		500,000		494,913		537,550		500,000		494,661		499,946
Revolving credit facility		250,000		250,000		250,000		—		—		—

Total debt outstanding	$	1,420,000	$	1,418,362	$	1,444,445	$	1,170,000	$	1,168,278	$	1,169,874

⁽¹⁾	Fair value is measured using Level 2 inputs.

Debt activity. The following table presents debt activity of the Partnership for the six months ended June 30, 2013:


thousands	Carrying Value
Balance as of December 31, 2012	$	1,168,278
Revolving credit facility borrowings		495,000
Repayments of revolving credit facility		(245,000)
Other		84

Balance as of June 30, 2013	$	1,418,362

Senior Notes. In June 2012, the Partnership completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, the Partnership issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The October 2012 notes and the June 2012 notes were issued under the same indenture and are considered a single class of securities, collectively referred to as the “2022 Notes.”

In May 2011, the Partnership completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) at a price to the public of 98.778% of the face amount.

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

Interest rate agreements. In May 2012, the Partnership entered into U.S. Treasury Rate lock agreements to mitigate the risk of rising interest rates prior to the issuance of the 2022 Notes. The Partnership settled the rate lock agreements simultaneously with the June 2012 offering of the 2022 Notes, realizing a loss of $1.7 million, which is included in other income (expense), net in the consolidated statements of income.

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

Revolving credit facility. At June 30, 2013 and December 31, 2012, the interest rate on the Partnership’s $800.0 million senior unsecured revolving credit facility (“RCF”) was 1.70% and 1.71%, respectively. The Partnership is required to pay a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon the Partnership’s senior unsecured debt rating. The facility fee rate was 0.25% at June 30, 2013 and December 31, 2012.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE (CONTINUED)

At June 30, 2013, the Partnership had $250.0 million of outstanding borrowings, $12.8 million in outstanding letters of credit issued and $537.2 million available for borrowing under the RCF. At June 30, 2013, the Partnership was in compliance with all covenants under the RCF.

The 2022 Notes, the 2021 Notes and obligations under the RCF are recourse to the Partnership’s general partner and as of December 31, 2012, the Partnership’s general partner was indemnified by a wholly owned subsidiary of Anadarko, Western Gas Resources, Inc. (“WGRI”), against any claims made against the general partner under the 2022 Notes, the 2021 Notes and/or the RCF. In connection with the acquisition of the Non-Operated Marcellus Interest in March 2013, the general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary agreed to indemnify the Partnership’s general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. As of June 30, 2013, the 2013 Indemnification Agreement applied to such debt financings up to $250.0 million. The Partnership’s general partner and WGRI also amended and restated the existing indemnity agreement between them to reduce the amount for which WGRI would indemnify the Partnership’s general partner by an amount equal to any amounts payable to the Partnership’s general partner under the 2013 Indemnification Agreement.

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


	Three Months Ended June 30,				Six Months Ended June 30,
thousands	2013		2012		2013		2012
Third parties
Interest expense on long-term debt	$	14,850	$	8,202	$	28,789	$	16,117
Amortization of debt issuance costs and commitment fees⁽¹⁾		1,064		1,016		2,117		2,024
Capitalized interest		(3,260)		(946)		(6,441)		(1,603)

Total interest expense – third parties		12,654		8,272		24,465		16,538

Affiliates
Interest expense on note payable to Anadarko⁽²⁾		—		1,206		—		2,440
Interest expense on affiliate balances⁽³⁾		—		82		—		163

Total interest expense – affiliates		—		1,288		—		2,603

Interest expense	$	12,654	$	9,560	$	24,465	$	19,141

⁽¹⁾

For the three and six months ended June 30, 2013, includes $0.2 million and $0.5 million, respectively, of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters’ fees. For the three and six months ended June 30, 2012, includes $0.2 million and $0.4 million, respectively, of amortization of the original issue discount and underwriters’ fees for the 2022 Notes issued in June 2012 and the 2021 Notes.

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

⁽³⁾

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

9. COMMITMENTS AND CONTINGENCIES

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

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

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

Other commitments. The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates. As of June 30, 2013, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of approximately $31.2 million, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to the continued construction of the Lancaster plant and an expansion project at the Fort Lupton compressor station in the Wattenberg system. In addition, in conjunction with the Mont Belvieu JV acquisition, the Partnership is committed to fund 25%, or approximately $21.9 million, of the total remaining estimated net project cost to complete the construction of the fractionation facilities over the next nine months (see Note 2).

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

Rent expense associated with the office, warehouse and equipment leases was $0.7 million and $1.4 million for the three and six months ended June 30, 2013, respectively, and $0.8 million and $1.5 million for the three and six months ended June 30, 2012, respectively.

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 were recast to reflect the results of the acquisition of the Non-Operated Marcellus Interest in our Current Report on Form 8-K, as filed with the Securities and Exchange Commission, or “SEC,” on May 13, 2013), and other public filings and press releases by Western Gas Partners, LP. Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refer to Western Gas Partners, LP and its subsidiaries. Our general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a consolidated subsidiary of Anadarko Petroleum Corporation. Western Gas Equity Holdings, LLC is WGP’s general partner and a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and our general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC, (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), and a joint venture, Enterprise EF78 LLC (“Mont Belvieu JV”). “Equity investment throughput” refers to our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

•

our ability to pay distributions to our unitholders;

•

our assumptions about the energy market;

•

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

•

operating results;

•

competitive conditions;

•

technology;

•

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

•

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

•

weather;

•

inflation;

•

availability of goods and services;

•

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

•

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

•

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

•

changes in the financial or operational condition of Anadarko;

•

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

•

our commitments to capital projects;

•

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

•

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

•

our ability to repay debt;

•

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

•

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

•

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

•

our ability to acquire assets on acceptable terms;

•

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

•

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

•

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

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

EXECUTIVE SUMMARY

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

Significant financial highlights during the first six months of 2013 included the following:

•

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

•

We announced a project to expand the processing capacity at our Lancaster plant by 300 MMcf/d with the construction of a second cryogenic processing train. Startup is anticipated in the first quarter of 2015.

•

We completed the acquisition of a 25% interest in the Mont Belvieu JV, which is constructing two NGL fractionators located in Mont Belvieu, Texas. See Acquisitions below.

•

We issued 7,015,000 common units to the public, generating net proceeds of $424.9 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds from this offering were used to repay a portion of the amount outstanding under our revolving credit facility, with the remaining net proceeds used for general partnership purposes, including the funding of capital expenditures.

•

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

•

We raised our distribution to $0.56 per unit for the second quarter of 2013, representing a 4% increase over the distribution for the first quarter of 2013, a 17% increase over the distribution for the second quarter of 2012, and our seventeenth consecutive quarterly increase.

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

•

Throughput attributable to Western Gas Partners, LP totaled 3,139 MMcf/d and 3,023 MMcf/d for the three and six months ended June 30, 2013, respectively, representing a 15% and an 11% increase, respectively, compared to the same periods in 2012.

•

Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.55 per Mcf for both the three and six months ended June 30, 2013, representing a 4% and 2% decrease, respectively, compared to the same periods in 2012.

ACQUISITIONS

Acquisitions. The following table presents our acquisitions during 2012 and 2013, and identifies the funding sources for such acquisitions.


thousands except unit and percent amounts	Acquisition Date		Percentage Acquired		Borrowings		Cash On Hand		Common Units Issued		GP Units Issued
MGR ⁽¹⁾		01/13/12		100%	$	299,000	$	159,587		632,783		12,914
Chipeta ⁽²⁾		08/01/12		24%		—		128,250		151,235		3,086
Non-Operated Marcellus Interest⁽³⁾		03/01/13		33.75%		250,000		215,500		449,129		—
Anadarko-Operated Marcellus Interest⁽⁴⁾		03/08/13		33.75%		133,500		—		—		—
Mont Belvieu JV⁽⁵⁾		06/05/13		25%		—		78,129		—		—

⁽¹⁾

The assets acquired from Anadarko consist of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant with a capacity of 125 MMcf/d, the Red Desert processing plant with a capacity of 48 MMcf/d, 1,295 miles of gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a 338-mile mainline gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.” In connection with the MGR acquisition, we entered into 10-year, fee-based gathering and processing agreements with Anadarko effective December 1, 2011, for all affiliate throughput on the MGR assets.

⁽²⁾

We acquired Anadarko’s then remaining 24% membership interest in Chipeta (as described in Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q). We received distributions related to the additional interest beginning July 1, 2012. This transaction brought our total membership interest in Chipeta to 75%. The remaining 25% membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in our consolidated financial statements for all periods presented.

⁽³⁾

We acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, our general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in us.

⁽⁴⁾

The interest acquired from a third party consisted of a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽⁵⁾

The acquisition from a third party consisted of a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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

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

EQUITY OFFERINGS

Public equity offerings. We completed the following public equity offerings during 2012 and 2013:

thousands except unit
and per-unit amounts

Common
Units Issued ⁽¹⁾

GP Units
Issued ⁽²⁾

Price Per
Unit

Underwriting
Discount and
Other Offering
Expenses

Net
Proceeds

June 2012 equity offering

5,000,000

102,041

43.88

7,468

216,409

May 2013 equity offering

7,015,000

143,163

61.18

13,059

424,878

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

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

Other equity offerings. In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to $125.0 million of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of June 30, 2013, we had not issued any common units under this registration statement.

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

RESULTS OF OPERATIONS

OPERATING RESULTS

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
thousands	2013		2012		2013		2012
Gathering, processing and transportation of natural gas and natural gas liquids	$	109,800	$	93,444	$	212,690	$	185,033
Natural gas, natural gas liquids and condensate sales		139,561		122,226		261,290		250,712
Equity income and other, net		5,765		4,640		10,893		9,241

Total revenues ⁽¹⁾		255,126		220,310		484,873		444,986
Total operating expenses ⁽¹⁾		184,999		161,030		350,710		318,485

Operating income		70,127		59,280		134,163		126,501
Interest income, net – affiliates		4,225		4,225		8,450		8,450
Interest expense		(12,654)		(9,560)		(24,465)		(19,141)
Other income (expense), net		499		(1,267)		1,173		(809)

Income before income taxes		62,197		52,678		119,321		115,001
Income tax expense		137		5,079		4,373		9,508

Net income		62,060		47,599		114,948		105,493
Net income attributable to noncontrolling interests		1,860		4,290		4,091		8,533

Net income attributable to Western Gas Partners, LP	$	60,200	$	43,309	$	110,857	$	96,960

Key performance metrics ⁽²⁾
Gross margin	$	161,666	$	137,854	$	308,330	$	279,374
Adjusted EBITDA attributable to Western Gas Partners, LP	$	107,646	$	87,639	$	203,575	$	182,319
Distributable cash flow	$	89,783	$	72,290	$	168,913	$	154,651

⁽¹⁾

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

⁽²⁾

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

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

Throughput


	Three Months Ended June 30,						Six Months Ended June 30,
throughput in MMcf/d	2013		2012		D		2013		2012		D
Gathering, treating and transportation ⁽¹⁾		1,765		1,611		10%		1,696		1,608		5%
Processing ⁽²⁾		1,330		1,170		14%		1,282		1,160		11%
Equity investment ⁽³⁾		211		234		(10)%		206		235		(12)%

Total throughput ⁽⁴⁾		3,306		3,015		10%		3,184		3,003		6%
Throughput attributable to noncontrolling interests		167		290		(42)%		161		280		(43)%

Total throughput attributable to Western Gas Partners, LP		3,139		2,725		15%		3,023		2,723		11%

⁽¹⁾

Excludes average NGL pipeline volumes of 19 MBbls/d and 20 MBbls/d for the three and six months ended June 30, 2013, respectively, and 26 MBbls/d for both the three and six months ended June 30, 2012. Includes 100% of Wattenberg system volumes for all periods presented and throughput beginning March 2013 attributable to the Anadarko-Operated Marcellus Interest.

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

⁽³⁾	Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes, and excludes our 10% share of average White Cliffs pipeline volumes consisting of 7 MBbls/d for both the three and six months ended June 30, 2013 and 6 MBbls/d for both the three and six months ended June 30, 2012.

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

Gathering, treating and transportation throughput increased by 154 MMcf/d and 88 MMcf/d for the three and six months ended June 30, 2013, respectively, due to increased volumes at the Non-Operated Marcellus Interest and the additional throughput from the Anadarko-Operated Marcellus Interest beginning in March 2013. These increases were partially offset by decreases at MIGC due to the expiration of a firm transportation agreement effective September 2012 and at the Bison facility resulting from reduced drilling activity in the area.

Processing throughput increased by 160 MMcf/d and 122 MMcf/d for the three and six months ended June 30, 2013, respectively, primarily due to throughput increases at Chipeta, plus the completion of a pipeline connection that allowed additional throughput to flow into the plant, increased volumes processed at a plant included in the MGR acquisition (“the Granger straddle plant”), an increase in volumes at the Red Desert complex due to additional well connections during the period, and the start-up of the Brasada plant in June 2013. These increases were partially offset by a decrease in throughput at the Granger complex due to natural production declines in the area.

Equity investment volumes decreased by 23 MMcf/d and 29 MMcf/d for the three and six months ended June 30, 2013, respectively, primarily due to lower throughput at the Fort Union system due to production declines in the area.

Natural Gas Gathering, Processing and Transportation Revenues


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2013		2012		D		2013		2012		D
Gathering, processing and transportation of natural gas and natural gas liquids	$	109,800	$	93,444		18%	$	212,690	$	185,033		15%

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $16.4 million for the three months ended June 30, 2013, primarily due to increases of $6.8 million, $6.7 million and $1.4 million at the Non-Operated Marcellus Interest, the Wattenberg system and Chipeta, respectively, all due to higher volumes, and an increase of $2.8 million due to the addition of the Anadarko-Operated Marcellus Interest beginning in March 2013. These increases were partially offset by decreased revenue of $0.7 million at the Bison facility due to lower volumes as a result of reduced drilling activity in the area, and decreased revenue of $0.5 million at MIGC due to the expiration of a firm transportation agreement effective September 2012.

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $27.7 million for the six months ended June 30, 2013, primarily due to increases of $12.5 million, $10.2 million and $4.8 million at the Non-Operated Marcellus Interest, the Wattenberg system and Chipeta, respectively, all due to higher volumes, and an increase of $3.4 million due to the addition of the Anadarko-Operated Marcellus Interest beginning in March 2013. These increases were partially offset by decreased revenue of $1.3 million at the Helper system due to a downward rate revision effective April 1, 2012, decreased revenue of $1.3 million at the Bison facility due to lower volumes as a result of reduced drilling activity in the area, and decreased revenue of $1.2 million at MIGC due to the expiration of a firm transportation agreement effective September 2012.

Natural Gas, Natural Gas Liquids and Condensate Sales


thousands except percentages and per-unit amounts	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages and per-unit amounts	2013		2012		D		2013		2012		D
Natural gas sales	$	29,474	$	23,743		24%	$	54,991	$	49,301		12%
Natural gas liquids sales		102,381		92,527		11%		189,598		186,169		2%
Drip condensate sales		7,706		5,956		29%		16,701		15,242		10%

Total	$	139,561	$	122,226		14%	$	261,290	$	250,712		4%

Average price per unit:
Natural gas (per Mcf)	$	4.34	$	4.06		7%	$	4.28	$	4.18		2%
Natural gas liquids (per Bbl)	$	47.73	$	46.94		2%	$	47.41	$	47.41		—%
Drip condensate (per Bbl)	$	77.71	$	76.03		2%	$	75.98	$	76.07		—%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $17.3 million for the three months ended June 30, 2013, which consisted of a $5.7 million increase in natural gas sales, a $9.9 million increase in NGLs sales and a $1.8 million increase in drip condensate sales.

For the three months ended June 30, 2013, natural gas sales increased primarily due to a 7% increase in the overall natural gas sales price and higher sales volumes at the Red Desert complex and the Wattenberg system. The growth in NGLs sales for the three months ended June 30, 2013, was primarily due to increases of $11.1 million, $1.5 million and $4.6 million at the Red Desert complex, the Hilight system, and the Granger straddle plant, respectively, due to higher volumes processed and sold. These increases were partially offset by a decrease of $5.3 million at Chipeta (with corresponding decreases in cost of product as discussed below), and a decrease of $2.0 million at the Granger complex due to lower volumes sold.

The growth in drip condensate sales for the three months ended June 30, 2013, was primarily due to a $1.5 million increase at the Wattenberg system and a $0.3 million increase at the Platte Valley system, both as a result of more condensate volumes sold.

For the six months ended June 30, 2013, including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $10.6 million, which consisted primarily of a $5.7 million increase in sales of natural gas, a $3.4 million increase in NGLs sales and a $1.5 million increase in drip condensate sales.

For the six months ended June 30, 2013, natural gas sales increased primarily due to a 2% increase in the overall natural gas sales price and higher sales volumes at the Red Desert complex and the Wattenberg system. Natural gas sales also increased by $2.9 million at the Platte Valley system due to an increase in average price, partially offset by a decrease in volume. These increases were partially offset by a decrease of $2.9 million at the Hilight system due to a decrease in average price, offset by an increase in volume and a decrease of $1.9 million at the Granger complex due to a decrease in volume, offset by an increase in average price.

The growth in NGLs sales for the six months ended June 30, 2012, was primarily due to increases of $13.3 million, $2.3 million and $4.5 million resulting from higher volumes processed and sold at the Red Desert complex, the Hilight system and the Granger straddle plant, respectively. These increases were partially offset by a decrease of $9.7 million at Chipeta (with corresponding decreases in cost of product as discussed below), and a decrease of $6.9 million at the Granger complex due to lower volumes sold.

The growth in drip condensate sales for the six months ended June 30, 2013, was primarily due to a $1.2 million increase at the Wattenberg system and a $0.7 million increase at the Platte Valley system, both as a result of more condensate volumes sold.

For the three and six months ended June 30, 2013 and 2012, average natural gas, NGL and drip condensate prices include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Newcastle, Hugoton and Wattenberg systems, and the MGR assets. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Equity Income and Other Revenues


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2013		2012		D		2013		2012		D
Equity income	$	3,724	$	3,335		12%	$	7,704	$	6,948		11%
Other revenues, net		2,041		1,305		56%		3,189		2,293		39%

Total	$	5,765	$	4,640		24%	$	10,893	$	9,241		18%

Equity income increased by $0.4 million and $0.8 million for the three and six months ended June 30, 2013, respectively, primarily due to an increase in income from White Cliffs of $0.4 million and $1.2 million, respectively, as a result of increased volumes. Partially offsetting the amounts for the six months ended June 30, 2013, were a $0.2 million decrease in income from Rendezvous and a $0.2 million decrease in income from Fort Union, both as a result of decreased volumes.

Other revenues, net increased by $0.7 million and $0.9 million for the three and six months ended June 30, 2013, respectively, primarily due to the collection of deficiency fees associated with volume commitments at Chipeta.

Cost of Product and Operation and Maintenance Expenses


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2013		2012		D		2013		2012		D
Cost of product	$	93,460	$	82,456		13%	$	176,543	$	165,612		7%
Operation and maintenance		41,669		35,690		17%		78,408		67,811		16%

Total cost of product and operation and maintenance expenses	$	135,129	$	118,146		14%	$	254,951	$	233,423		9%

Including the effects of commodity price swap agreements on purchases, cost of product expense increased by $11.0 million for the three months ended June 30, 2013, as a result of:

• a $5.2 million net increase in NGL purchases primarily due to increased purchases at the Red Desert complex and the Wattenberg system, partially offset by decreased purchases at Chipeta and the Granger complex; and

• a $5.2 million net increase in residue purchases primarily due to increased purchases at the Red Desert complex, the Wattenberg system, the Platte Valley system, and the Granger straddle plant, partially offset by decreased purchases at the Granger complex and the Hilight system.

Including the effects of commodity price swap agreements on purchases, cost of product expense increased by $10.9 million for the six months ended June 30, 2013, as a result of:

• a $5.1 million net increase in NGL purchases primarily due to increased purchases at the Red Desert complex, the Hilight system, and the Wattenberg system, partially offset by decreased purchases at Chipeta and the Granger complex; and

• a $5.7 million net increase in residue purchases primarily due to increased purchases at the Red Desert complex, the Platte Valley system, the Granger straddle plant and the Wattenberg system, partially offset by decreased purchases at the Granger complex and the Hilight system.

Cost of product expense for the three and six months ended June 30, 2013 and 2012, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and the MGR assets. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Operation and maintenance expense increased by $6.0 million and $10.6 million for the three and six months ended June 30, 2013, respectively, primarily due to increases in property, overhead and facility expense attributable to the Non-Operated Marcellus Interest, and increases in contract labor expense, payroll taxes, electric expense and plant repairs, primarily at Chipeta and the Wattenberg system.

General and Administrative, Depreciation and Other Expenses


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2013		2012		D		2013		2012		D
General and administrative	$	7,288	$	10,310		(29)%	$	14,952	$	20,584		(27)%
Property and other taxes		6,086		4,833		26%		11,871		9,670		23%
Depreciation, amortization and impairments		36,496		27,741		32%		68,936		54,808		26%

Total general and administrative, depreciation and other expenses	$	49,870	$	42,884		16%	$	95,759	$	85,062		13%

General and administrative expenses decreased by $3.0 million and $5.6 million for the three and six months ended June 30, 2013, respectively, due to a decrease of $2.2 million and $5.5 million, respectively, in non-cash compensation expenses primarily attributable to the awards outstanding under the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”), which were settled in December 2012 when the Incentive Plan terminated in conjunction with WGP’s IPO, and a decrease of $0.8 million and $0.4 million in consulting and audit fees, respectively, partially offset by an increase of $0.5 million and $0.8 million, respectively, in corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement.

Property and other taxes increased by $1.3 million and $2.2 million for the three and six months ended June 30, 2013, respectively, primarily due to ad valorem tax increases at the Platte Valley system and the completion of the Brasada plant in June 2013.

For the three months ended June 30, 2013, depreciation, amortization and impairments increased by $8.8 million primarily attributable to a $2.5 million increase in depreciation and impairment expense associated with the Non-Operated Marcellus Interest, an increase of $3.9 million in depreciation expense associated with capital projects at the Wattenberg system, Chipeta, and the Anadarko-Operated Marcellus Interest, and a $1.2 million increase in depreciation expense related to the completion of the Brasada plant in June 2013.

For the six months ended June 30, 2013, depreciation, amortization and impairments increased by $14.1 million primarily attributable to a $3.7 million increase in depreciation and impairment expense associated with the Non-Operated Marcellus Interest, an increase of $7.1 million in depreciation expense associated with capital projects at the Wattenberg system, Chipeta, and the Anadarko-Operated Marcellus Interest, and a $1.2 million increase in depreciation expense related to the completion of the Brasada plant in June 2013.

Interest Income, Net – Affiliates and Interest Expense


	Three Months Ended June 30,					Six Months Ended June 30,
thousands except percentages	2013		2012		D	2013		2012		D
Interest income on note receivable	$	4,225	$	4,225	—%	$	8,450	$	8,450	—%

Interest income, net – affiliates	$	4,225	$	4,225	—%	$	8,450	$	8,450	—%


Third parties
Interest expense on long-term debt	$	(14,850)	$	(8,202)	81%	$	(28,789)	$	(16,117)	79%
Amortization of debt issuance costs and commitment fees⁽²⁾		(1,064)		(1,016)	5%		(2,117)		(2,024)	5%
Capitalized interest		3,260		946	nm⁽¹⁾		6,441		1,603	nm
Affiliates
Interest expense on note payable to Anadarko⁽³⁾		—		(1,206)	(100)%		—		(2,440)	(100)%
Interest expense, net on affiliate balances⁽⁴⁾		—		(82)	(100)%		—		(163)	(100)%

Interest expense	$	(12,654)	$	(9,560)	32%	$	(24,465)	$	(19,141)	28%

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

⁽²⁾

For the three and six months ended June 30, 2013, includes $0.2 million and $0.5 million, respectively, of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”), (ii) original issue discount for the $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) and (iii) underwriters’ fees. For the three and six months ended June 30, 2012, includes $0.2 million and $0.4 million, respectively, of amortization of the original issue discount and underwriters’ fees for the 2022 Notes issued in June 2012 and the 2021 Notes.

⁽³⁾	In June 2012, the note payable to Anadarko was repaid in full. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽⁴⁾

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

Interest expense increased by $3.1 million and $5.3 million for the three and six months ended June 30, 2013, respectively, primarily due to interest expense incurred on the 2022 Notes of $6.5 million and $13.2 million, respectively. Partially offsetting these amounts for the three and six months ended June 30, 2013, were increases of capitalized interest of $2.3 million and $4.8 million, respectively, primarily associated with the construction of the Brasada and Lancaster plants and decreases in interest expense of $1.2 million and $2.4 million, respectively, attributable to the repayment of the note payable to Anadarko in June 2012. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q).

Other Income (Expense), Net

Three Months Ended
June 30,

Six Months Ended
June 30,

thousands except percentages

2013

2012

2013

2012

Other income (expense), net

499

(1,267)

(139)%

1,173

(809)

For the three and six months ended June 30, 2013 and 2012, other income (expense), net included $0.4 million and $0.8 million, respectively, of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition. In addition, for the three and six months ended June 30, 2013, other income (expense), net included $0.1 million and $0.3 million, respectively, on interest earned on overnight investments. For the three and six months ended June 30, 2012, other income (expense), net included a realized loss of $1.7 million resulting from U.S. Treasury Rate lock agreements settled simultaneously with our June 2012 offering of the 2022 Notes. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Income Tax Expense


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2013		2012		D		2013		2012		D
Income before income taxes	$	62,197	$	52,678		18%	$	119,321	$	115,001		4%
Income tax expense		137		5,079		(97)%		4,373		9,508		(54)%
Effective tax rate		—%		10%				4%		8%

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

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

Noncontrolling Interests


	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages	2013		2012		D		2013		2012		D
Net income attributable to noncontrolling interests	$	1,860	$	4,290		(57)%	$	4,091	$	8,533		(52)%

For the three and six months ended June 30, 2013, net income attributable to noncontrolling interests decreased by $2.4 million and $4.4 million, respectively, primarily due to our acquisition of Anadarko’s then remaining 24% membership interest in Chipeta in August 2012. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

KEY PERFORMANCE METRICS


thousands except percentages and gross margin per Mcf	Three Months Ended June 30,						Six Months Ended June 30,
thousands except percentages and gross margin per Mcf	2013		2012		D		2013		2012		D
Gross margin	$	161,666	$	137,854		17%	$	308,330	$	279,374		10%
Gross margin per Mcf ⁽¹⁾		0.54		0.50		8%		0.54		0.51		6%
Gross margin per Mcf attributable to
Western Gas Partners, LP ^{(1) (2)}		0.55		0.53		4%		0.55		0.54		2%
Adjusted EBITDA attributable to Western Gas Partners, LP ⁽³⁾		107,646		87,639		23%		203,575		182,319		12%
Distributable cash flow ⁽³⁾	$	89,783	$	72,290		24%	$	168,913	$	154,651		9%

⁽¹⁾

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

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

⁽³⁾

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

Gross margin and Gross margin per Mcf. Gross margin increased by $23.8 million for the three months ended June 30, 2013, primarily due to higher margins at the Wattenberg system, the Non-Operated Marcellus Interest, the Granger straddle plant, the Red Desert complex, and the Anadarko-Operated Marcellus Interest.

Gross margin increased by $29.0 million for the six months ended June 30, 2013, primarily due to higher margins at the Non-Operated Marcellus Interest, the Wattenberg system, the Anadarko-Operated Marcellus Interest and the Granger straddle plant, partially offset by a decrease in margin at MIGC due to the expiration of a firm transportation agreement effective September 2012.

Gross margin per Mcf increased by $0.04 and $0.03 for the three and six months ended June 30, 2013, respectively, primarily due to higher margins and increases in throughput at Chipeta and the Wattenberg and Platte Valley systems, as well as overall changes in the throughput mix of our portfolio.

Adjusted EBITDA. We define “Adjusted EBITDA” as net income attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, and other income. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:

•

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

•

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

•

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

Adjusted EBITDA increased by $20.0 million for the three months ended June 30, 2013, primarily due to a $34.4 million increase in total revenues excluding equity income, a $2.4 million decrease in net income attributable to noncontrolling interest, a $0.9 million decrease in general and administrative expenses excluding non-cash equity-based compensation, and a $0.4 million increase in distributions from equity investees. These amounts were offset by an $11.0 million increase in cost of product, a $6.0 million increase in operation and maintenance expenses, and a $1.3 million increase in property and other tax expense.

Adjusted EBITDA increased by $21.3 million for the six months ended June 30, 2013, primarily due to a $39.1 million increase in total revenues excluding equity income, a $4.4 million decrease in net income attributable to noncontrolling interest, a $1.0 million increase in distributions from equity investees, and a $0.3 million decrease in general and administrative expenses excluding non-cash equity-based compensation. These amounts were offset by a $10.9 million increase in cost of product, a $10.6 million increase in operation and maintenance expenses, and a $2.2 million increase in property and other tax expense.

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

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

Distributable cash flow increased by $17.5 million for the three months ended June 30, 2013, primarily due to a $20.0 million increase in Adjusted EBITDA, and a $3.0 million decrease in maintenance capital expenditures, offset by a $5.5 million increase in net cash paid for interest expense.

Distributable cash flow increased by $14.3 million for the six months ended June 30, 2013, primarily due to a $21.3 million increase in Adjusted EBITDA, and a $3.3 million decrease in maintenance capital expenditures, offset by a $10.3 million increase in net cash paid for interest expense.

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

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
thousands	2013		2012		2013		2012
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	107,646	$	87,639	$	203,575	$	182,319
Less:
Distributions from equity investees		6,026		5,578		11,032		10,019
Non-cash equity-based compensation expense		824		2,924		1,701		6,990
Interest expense		12,654		9,560		24,465		19,141
Income tax expense		137		5,079		4,373		9,508
Depreciation, amortization and impairments ⁽¹⁾		35,857		27,084		67,681		53,496
Other expense ⁽¹⁾		—		1,665		—		1,665
Add:
Equity income, net		3,724		3,335		7,704		6,948
Interest income, net – affiliates		4,225		4,225		8,450		8,450
Other income ^{(1) (2)}		103		—		380		62

Net income attributable to Western Gas Partners, LP	$	60,200	$	43,309	$	110,857	$	96,960


Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	107,646	$	87,639	$	203,575	$	182,319
Adjusted EBITDA attributable to noncontrolling interests		2,499		4,945		5,345		9,843
Interest income (expense), net		(8,429)		(5,335)		(16,015)		(10,691)
Non-cash equity based compensation expense		54		(2,004)		(19)		(5,156)
Debt-related amortization and other items, net		566		519		1,126		1,030
Current income tax expense		(32)		(1,452)		(3,144)		6,331
Other income (expense), net ⁽²⁾		103		(1,663)		381		(1,601)
Distributions from equity investees less than (in excess of) equity income, net		(2,302)		(2,243)		(3,328)		(3,071)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		(47,875)		(20,241)		(27,121)		12,586
Accounts payable, accrued liabilities and natural gas imbalance payable		(20,951)		3,717		336		(9,948)
Other		3,779		3,583		3,877		4,544

Net cash provided by operating activities	$	35,058	$	67,465	$	165,013	$	186,186


Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities					$	165,013	$	186,186
Net cash used in investing activities					$	(1,049,490)	$	(658,549)
Net cash provided by financing activities					$	538,676	$	503,856

⁽¹⁾

Includes our 51% share for the three and six months ended June 30, 2012, and our 75% share for the three and six months ended June 30, 2013, of depreciation, amortization and impairments; other expense; and other income attributable to Chipeta. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽²⁾

Excludes income of $0.4 million and $0.8 million for each of the three and six months ended June 30, 2013 and 2012, respectively, related to a component of a gas processing agreement accounted for as a capital lease. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.


	Three Months Ended June 30,					Six Months Ended June 30,
thousands except Coverage ratio	2013			2012		2013			2012
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	89,783		$	72,290	$	168,913		$	154,651
Less:
Distributions from equity investees		6,026			5,578		11,032			10,019
Non-cash equity-based compensation expense		824			2,924		1,701			6,990
Interest expense, net (non-cash settled)		—			82		—			163
Income tax expense		137			5,079		4,373			9,508
Depreciation, amortization and impairments ⁽¹⁾		35,857			27,084		67,681			53,496
Other expense ⁽¹⁾		—			1,665		—			1,665
Add:
Equity income, net		3,724			3,335		7,704			6,948
Cash paid for maintenance capital expenditures ^{(1) (3)}		6,174			9,150		12,206			15,465
Capitalized interest		3,260			946		6,441			1,603
Cash paid for income taxes		—			—		—			72
Other income ^{(1) (2)}		103			—		380			62

Net income attributable to Western Gas Partners, LP	$	60,200		$	43,309	$	110,857		$	96,960


Distributions declared ⁽⁴⁾
Limited partners	$	62,794				$	119,553
General partner		16,521					29,905

Total	$	79,315				$	149,458

Coverage ratio		1.13	x				1.13	x

⁽¹⁾

Includes our 51% share for the three and six months ended June 30, 2012, and our 75% share for the three and six months ended June 30, 2013, of depreciation, amortization and impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to Chipeta. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

⁽²⁾

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

⁽⁴⁾	Reflects distributions of $0.56 and $1.10 per unit declared for the three and six months ended June 30, 2013, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and other capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owner. Our sources of liquidity as of June 30, 2013, included cash and cash equivalents, cash flows generated from operations, including interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under our RCF, and issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. On July 17, 2013, the board of directors of our general partner declared a cash distribution to our unitholders of $0.56 per unit, which equates to $79.3 million in the aggregate including incentive distributions. The cash distribution is payable on August 12, 2013, to unitholders of record at the close of business on July 31, 2013.

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

Working capital. As of June 30, 2013, we had $11.0 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. As of June 30, 2013, we had $537.2 million available for borrowing under our $800.0 million RCF.

Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or develop new midstream infrastructure. We categorize capital expenditures as either of the following:

•

maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput and related cash flows; or

•

expansion capital expenditures, which include expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.

Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:


	Six Months Ended June 30,
thousands	2013		2012
Acquisitions	$	679,610	$	465,507


Expansion capital expenditures	$	327,550	$	176,840
Maintenance capital expenditures		12,206		16,213

Total capital expenditures ⁽¹⁾	$	339,756	$	193,053


Capital incurred ⁽²⁾	$	301,880	$	278,930

⁽¹⁾

Capital expenditures for the six months ended June 30, 2013, included $6.0 million of capitalized interest. Capital expenditures included the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners for all periods presented. Capital expenditures for the six months ended June 30, 2012, included $44.6 million of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest acquisition.

⁽²⁾

Capital incurred for the six months ended June 30, 2013, included $6.0 million of capitalized interest. Capital incurred for the six months ended June 30, 2013 and 2012, included $8.8 million and $76.3 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest acquisition and included the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

Acquisitions included the Mont Belvieu JV acquisition in the second quarter of 2013, the Anadarko-Operated Marcellus Interest acquisition and the Non-Operated Marcellus Interest acquisition in the first quarter of 2013, and the MGR acquisition in the first quarter of 2012, as discussed in Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Capital expenditures, excluding acquisitions, increased by $146.7 million for the six months ended June 30, 2013. Expansion capital expenditures increased by $150.7 million (including a $4.4 million increase in capitalized interest), primarily due to an increase of $117.9 million related to the construction of the Brasada and Lancaster gas processing facilities and a $61.1 million increase in expenditures at the Wattenberg and Hilight systems and the Red Desert complex. These increases were partially offset by a $31.1 million decrease at Chipeta. Maintenance capital expenditures decreased by $4.0 million, primarily as a result of decreased expenditures of $4.6 million at the Wattenberg, Haley, and Platte Valley systems and the Red Desert complex, partially offset by a $1.4 million increase at the Anadarko-Operated Marcellus Interest and the Non-Operated Marcellus Interest.

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


	Six Months Ended June 30,
thousands	2013		2012
Net cash provided by (used in):
Operating activities	$	165,013	$	186,186
Investing activities		(1,049,490)		(658,549)
Financing activities		538,676		503,856

Net increase (decrease) in cash and cash equivalents	$	(345,801)	$	31,493

Operating Activities. Net cash provided by operating activities during the six months ended June 30, 2013, was $165.0 million, compared to $186.2 million for the six months ended June 30, 2012. Operating cash flows for the six months ended June 30, 2013, decreased primarily due to the unfavorable impact of changes in working capital items, partially offset by higher sales volumes and higher average natural gas prices. Refer to Operating Results within Item 2 of this Form 10-Q for a discussion of our results of operations as compared to the prior period.

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

•

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

•

$339.8 million of capital expenditures;

•

$134.5 million of cash paid for the Anadarko-Operated Marcellus Interest acquisition;

•

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

•

$12.0 million of cash paid related to a White Cliffs expansion project anticipated to be completed in the first half of 2014;

•

$17.8 million of capital contributions to the Mont Belvieu JV to fund our current share of construction costs for the fractionation facilities anticipated to be completed by the first quarter of 2014; and

•

$1.4 million of cash paid for equipment purchases from Anadarko.

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

•

$458.6 million of cash paid for the MGR acquisition;

•

$193.1 million of capital expenditures; and

•

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

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

•

$424.9 million of net proceeds from our May 2013 equity offering, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;

•

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

•

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

•

$111.5 million of borrowings to fund capital expenditures; and

•

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

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

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

•

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

•

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

•

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

Proceeds from our 2022 Notes offering were used to repay amounts outstanding under our RCF and our note payable to Anadarko. Net contributions from Anadarko attributable to intercompany balances were $29.0 million during the six months ended June 30, 2012, representing intercompany transactions attributable to the Non-Operated Marcellus Interest acquisition.

For the six months ended June 30, 2013 and 2012, we paid $135.8 million and $89.1 million, respectively, of cash distributions to our unitholders. Contributions to Chipeta from noncontrolling interest owners totaled $1.1 million and $21.3 million during the six months ended June 30, 2013 and 2012, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $4.7 million and $10.3 million for the six months ended June 30, 2013 and 2012, respectively, representing the distributions received as of June 30 of the respective year. Decreases in contributions to and distributions from Chipeta noncontrolling interest owners are also due to the August 2012 acquisition of Anadarko’s then remaining 24% membership interest in Chipeta.

Debt and credit facility. As of June 30, 2013, the carrying value of our outstanding debt consisted of $673.4 million of the 2022 Notes, $494.9 million of the 2021 Notes and $250.0 million of the RCF. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Senior Notes. In June 2012, we completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, we issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The October 2012 notes and the June 2012 notes were issued under the same indenture and are considered a single class of securities, collectively referred to as the “2022 Notes.”

In May 2011, we completed the offering of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”) at a price to the public of 98.778% of the face amount.

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

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

Revolving credit facility. As of June 30, 2013, we had $250.0 million of outstanding borrowings and $12.8 million in outstanding letters of credit issued under our $800.0 million RCF. The interest rate was 1.70% and 1.71% at June 30, 2013 and December 31, 2012, respectively. We are required to pay a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon our senior unsecured debt rating. The facility fee rate was 0.25% at June 30, 2013 and December 31, 2012. At June 30, 2013, we were in compliance with all covenants under the RCF.

The 2022 Notes, the 2021 Notes and obligations under the RCF are recourse to our general partner and as of December 31, 2012, our general partner was indemnified by a wholly owned subsidiary of Anadarko, Western Gas Resources, Inc. (“WGRI”), against any claims made against our general partner under the 2022 Notes, the 2021 Notes and/or the RCF. In connection with the acquisition of the Non-Operated Marcellus Interest in March 2013, our general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary agreed to indemnify our general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. As of June 30, 2013, the 2013 Indemnification Agreement applied to such debt financings up to $250.0 million. Our general partner and WGRI also amended and restated the existing indemnity agreement between them to reduce the amount for which WGRI would indemnify our general partner by an amount equal to any amounts payable to our general partner under the 2013 Indemnification Agreement.

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

In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to $125.0 million of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of June 30, 2013, we had not issued any common units under this registration statement.

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

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

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

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

CONTRACTUAL OBLIGATIONS

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

OFF-BALANCE SHEET ARRANGEMENTS

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

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

Interest rate risk. Interest rates during the six months ended June 30, 2013 were low compared to historic rates. As of June 30, 2013, we had $250.0 million of outstanding borrowings under our RCF (which bears interest at a rate based on LIBOR). If interest rates rise, our future financing costs could increase. A 10% change in LIBOR would have resulted in a nominal change in net income and the fair value of our borrowings under the RCF.

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

Item 4. Controls and Procedures

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

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, 2013, that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are not a party to any legal, regulatory or administrative proceedings other than proceedings arising in the ordinary course of our business. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial condition, or for which disclosure is otherwise required by Item 103 of Regulation S-K.

Item 1A. Risk Factors

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

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

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

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

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

Item 6. Exhibits

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


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


3.3		Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated December 19, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
3.4		Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of April 15, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046).
3.5		Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated July 22, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
3.6		Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated January 29, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
3.7		Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 2, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
3.8		Amendment No. 6 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated July 8, 2011 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 8, 2011, File No. 001-34046).
3.9		Amendment No. 7 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated January 13, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 17, 2012, File No. 001-34046).
3.10		Amendment No. 8 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 1, 2012 (incorporated by reference to Exhibit 3.10 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 2, 2012, File No. 001-34046).
3.11		Amendment No. 9 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated December 12, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
3.12		Amendment No. 10 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 1, 2013 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
3.13		Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.14		Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
4.1		Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
4.2		Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.3		First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.4		Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.5		Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).


4.6		Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
10.1*		Assignment of Indemnification Agreement, dated April 1, 2013, between Anadarko USH2 LLC and Anadarko E&P Onshore LLC.
31.1*		Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

#		Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document

SIGNATURES

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


		WESTERN GAS PARTNERS, LP

August 1, 2013

		/s/ Donald R. Sinclair
		Donald R. Sinclair
		President and Chief Executive Officer
		Western Gas Holdings, LLC
		(as general partner of Western Gas Partners, LP)

August 1, 2013

		/s/ Benjamin M. Fink
		Benjamin M. Fink
		Senior Vice President, Chief Financial Officer and Treasurer
		Western Gas Holdings, LLC
		(as general partner of Western Gas Partners, LP)