Edgar Filing: Western Gas Partners LP

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WES 03.31.14 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2014


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

For the transition period from to

Commission file number: 001-34046

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)



Delaware		26-1075808
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1201 Lake Robbins Drive The Woodlands, Texas		77380
(Address of principal executive offices)		(Zip Code)

(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.

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 117,932,582 common units outstanding as of May 5, 2014.

Table of Contents

TABLE OF CONTENTS



PART I		FINANCIAL INFORMATION (UNAUDITED)	PAGE

	Item 1.	Financial Statements

		Consolidated Statements of Income for the three months ended March 31, 2014 and 2013	4

		Consolidated Balance Sheets as of March 31, 2014, and December 31, 2013	5

		Consolidated Statement of Equity and Partners’ Capital for the three months ended March 31, 2014	6

		Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013	7

		Notes to Consolidated Financial Statements	8

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

		Cautionary Note Regarding Forward-Looking Statements	21

		Executive Summary	23

		Acquisitions	24

		Equity Offerings	25

		Results of Operations	26

		Operating Results	26

		Key Performance Metrics	32

		Liquidity and Capital Resources	37

		Contractual Obligations	43

		Off-Balance Sheet Arrangements	43

	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 6.	Exhibits	45

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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 for end-use sale.

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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended March 31,
thousands except per-unit amounts	2014			2013 ⁽¹⁾
Revenues – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	85,161		$	65,899
Natural gas, natural gas liquids and condensate sales	120,400			111,670
Other, net	729			—
Total revenues – affiliates	206,290			177,569
Revenues – third parties
Gathering, processing and transportation of natural gas and natural gas liquids	56,288			36,991
Natural gas, natural gas liquids and condensate sales	16,038			10,059
Other, net	841			1,147
Total revenues – third parties	73,167			48,197
Total revenues	279,457			225,766
Equity income, net ⁽²⁾	9,251			3,968
Operating expenses
Cost of product ⁽³⁾	91,950			83,083
Operation and maintenance ⁽³⁾	40,532			36,739
General and administrative ⁽³⁾	8,415			7,664
Property and other taxes	7,041			5,785
Depreciation, amortization and impairments	40,612			32,440
Total operating expenses	188,550			165,711
Operating income	100,158			64,023
Interest income, net – affiliates	4,225			4,225
Interest expense	(13,961		)	(11,811		)
Other income, net	477			674
Income before income taxes	90,899			57,111
Income tax (benefit) expense	(228		)	4,166
Net income	91,127			52,945
Net income attributable to noncontrolling interest	3,692			2,231
Net income attributable to Western Gas Partners, LP	$	87,435		$	50,714
Limited partners’ interest in net income:
Net income attributable to Western Gas Partners, LP	$	87,435		$	50,714
Pre-acquisition net (income) loss allocated to Anadarko	956			(5,458		)
General partner interest in net (income) loss ⁽⁴⁾	(24,834		)	(12,886		)
Limited partners’ interest in net income ⁽⁴⁾	$	63,557		$	32,370
Net income per common unit – basic and diluted	$	0.54		$	0.31
Weighted average common units outstanding – basic and diluted	117,716			104,815


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


⁽²⁾	Income earned from equity investments is classified as affiliate. See Note 1.

⁽³⁾

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $16.6 million and $31.9 million for the three months ended March 31, 2014 and 2013, respectively. Operation and maintenance includes charges from Anadarko of $11.1 million and $13.4 million for the three months ended March 31, 2014 and 2013, respectively. General and administrative includes charges from Anadarko of $6.8 million and $5.9 million for the three months ended March 31, 2014 and 2013, respectively. See Note 5.


⁽⁴⁾	Represents net income earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 4.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



thousands except number of units	March 31, 2014		December 31, 2013 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	83,091	$	100,728
Accounts receivable, net ⁽²⁾	100,621		84,060
Other current assets ⁽³⁾	7,432		10,022
Total current assets	191,144		194,810
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	4,414,168		4,239,100
Less accumulated depreciation	894,690		855,845
Net property, plant and equipment	3,519,478		3,383,255
Goodwill	105,336		105,336
Other intangible assets	53,258		53,606
Equity investments	613,207		593,400
Other assets	34,684		27,401
Total assets	$	4,777,107	$	4,617,808
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables ⁽⁴⁾	$	30,219	$	39,589
Accrued ad valorem taxes	16,987		13,860
Income taxes payable	357		—
Accrued liabilities ⁽⁵⁾	124,893		137,011
Total current liabilities	172,456		190,460
Long-term debt	1,912,839		1,418,169
Deferred income taxes	428		37,998
Asset retirement obligations and other	79,850		79,145
Total long-term liabilities	1,993,117		1,535,312
Total liabilities	2,165,573		1,725,772
Equity and partners’ capital
Common units (117,932,582 and 117,322,812 units issued and outstanding at March 31, 2014, and December 31, 2013, respectively)	2,459,637		2,431,193
General partner units (2,406,763 and 2,394,345 units issued and outstanding at March 31, 2014, and December 31, 2013, respectively)	81,735		78,157
Net investment by Anadarko	—		312,092
Total partners’ capital	2,541,372		2,821,442
Noncontrolling interest	70,162		70,594
Total equity and partners’ capital	2,611,534		2,892,036
Total liabilities, equity and partners’ capital	$	4,777,107	$	4,617,808


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


⁽²⁾	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $57.6 million and $47.9 million as of March 31, 2014, and December 31, 2013, respectively.


⁽³⁾	Other current assets includes natural gas imbalance receivables from affiliates of $1.2 million and $0.1 million as of March 31, 2014, and December 31, 2013, respectively.


⁽⁴⁾	Accounts and natural gas imbalance payables includes amounts payable to affiliates of $0.1 million and $2.3 million as of March 31, 2014, and December 31, 2013, respectively.


⁽⁵⁾	Accrued liabilities includes amounts payable to affiliates of zero and $0.1 million as of March 31, 2014, and December 31, 2013, respectively.

See accompanying Notes to Consolidated Financial Statements.

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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 Interest			Total
Balance at December 31, 2013 ⁽¹⁾	$	312,092		$	2,431,193		$	78,157		$	70,594		$	2,892,036
Net income (loss)	(956		)	63,557			24,834			3,692			91,127
Issuance of common and general partner units, net of offering expenses	—			17,769			759			—			18,528
Distributions to noncontrolling interest owner	—			—			—			(4,124		)	(4,124		)
Distributions to unitholders	—			(70,574		)	(22,035		)	—			(92,609		)
Acquisitions from affiliates	(372,784		)	16,534			—			—			(356,250		)
Contributions of equity-based compensation from Anadarko	—			911			19			—			930
Net pre-acquisition contributions from (distributions to) Anadarko	23,788			—			—			—			23,788
Net contributions from Anadarko of other assets	—			42			1			—			43
Elimination of net deferred tax liabilities	38,160			—			—			—			38,160
Other	(300		)	205			—			—			(95		)
Balance at March 31, 2014	$	—		$	2,459,637		$	81,735		$	70,162		$	2,611,534


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

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Three Months Ended March 31,
thousands	2014			2013 ⁽¹⁾
Cash flows from operating activities
Net income	$	91,127		$	52,945
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and impairments	40,612			32,440
Non-cash equity-based compensation expense	1,150			804
Deferred income taxes	290			9,270
Debt-related amortization and other items, net	680			560
Equity income, net ⁽²⁾	(9,251		)	(3,968		)
Distributions from equity investment earnings ⁽²⁾	10,269			5,006
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(10,982		)	21,661
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	(1,727		)	21,287
Change in other items, net	1,878			(1,835		)
Net cash provided by operating activities	124,046			138,170
Cash flows from investing activities
Capital expenditures	(189,327		)	(166,463		)
Acquisitions from affiliates	(360,952		)	(465,721		)
Acquisitions from third parties	—			(134,869		)
Investments in equity affiliates	(27,605		)	(64,580		)
Distributions from equity investments in excess of cumulative earnings ⁽²⁾	2,044			—
Other	(857		)	—
Net cash used in investing activities	(576,697		)	(831,633		)
Cash flows from financing activities
Borrowings, net of debt issuance costs	917,742			384,946
Repayments of debt	(430,000		)	—
Increase (decrease) in outstanding checks	1,928			(2,808		)
Proceeds from the issuance of common and general partner units, net of offering expenses	18,289			500
Distributions to unitholders	(92,609		)	(65,657		)
Contributions from noncontrolling interest owner	—			1,097
Distributions to noncontrolling interest owner	(4,124		)	(2,650		)
Net contributions from (distributions to) Anadarko	23,788			21,570
Net cash provided by financing activities	435,014			336,998
Net increase (decrease) in cash and cash equivalents	(17,637		)	(356,465		)
Cash and cash equivalents at beginning of period	100,728			419,981
Cash and cash equivalents at end of period	$	83,091		$	63,516
Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets	$	(43	)	$	(6	)
Interest paid, net of capitalized interest	$	14,106		$	11,244
Taxes paid (reimbursements received)	$	(340	)	$	—


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


⁽²⁾	Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

See accompanying Notes to Consolidated Financial Statements.

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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 equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78, LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”) (see Note 2). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” All income earned on, distributions from and contributions to the Partnership’s equity investments are considered to be affiliate transactions. “Equity investment throughput” refers to the Partnership’s 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput, but excludes throughput measured in barrels consisting of the 10% share of average White Cliffs pipeline throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput. The “DJ Basin complex” refers to the Platte Valley system, Wattenberg system, and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014.

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 for third-party producers and customers. As of March 31, 2014, the Partnership’s assets and investments accounted for under the equity method consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	13	1	5	2
NGL gathering systems	—	—	—	2
Natural gas treating facilities	8	—	—	1
Natural gas processing facilities	8	3	—	2
NGL pipelines	3	—	—	2
Natural gas pipelines	3	—	—	—
Oil pipeline	—	—	—	1

These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), north-central Pennsylvania and Texas. The Partnership was also constructing the Lancaster processing plant (located in the DJ Basin complex) in Northeast Colorado at the end of the first quarter of 2014.

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) a significant limited partner interest (see Holdings of Partnership equity in Note 4). WGP has no independent operations or material assets other than its partnership interests in the Partnership.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

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.

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, using 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.

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 2013 Form 10-K, as filed with the SEC on February 28, 2014. Management believes that the disclosures made are adequate to make the information not misleading.

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets and interests accounted for under the equity method, owned by the Partnership as of March 31, 2014. 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 or interests from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets or interests 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 or interests from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such assets or interests 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 the Partnership assets or interests from Anadarko 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 or interests during the periods reported. Net income attributable to the Partnership assets or interests acquired from Anadarko for periods prior to the Partnership’s acquisition of such assets or interests is not allocated to the limited partners for purposes of calculating net income per common unit.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Equity investments. The following table presents the activity in the Partnership’s equity investments in Fort Union, White Cliffs, Rendezvous, the Mont Belvieu JV, TEG, TEP and FRP:



	Equity Investments
thousands	Fort Union			White Cliffs			Rendezvous			Mont Belvieu JV			TEG			TEP			FRP
Balance at December 31, 2013	$	25,172		$	35,039		$	60,928		$	122,480		$	16,649		$	197,731		$	135,401
Investment earnings (loss), net of amortization	1,501			2,227			244			7,124			192			(874		)	(1,163		)
Contributions	—			2,500			—			(1,919		)	352			187			20,992
Capitalized interest	—			—			—			—			—			—			857
Distributions	(1,016		)	(2,082		)	(729		)	(6,200		)	(242		)	—			—
Distributions in excess of cumulative earnings ⁽¹⁾	—			(581		)	(859		)	—			(163		)	(541		)	—
Balance at March 31, 2014	$	25,657		$	37,103		$	59,584		$	121,485		$	16,788		$	196,503		$	156,087


⁽¹⁾	Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.

Recently issued accounting standards. The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The ASU changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. The ASU is effective for annual and interim periods beginning in 2015. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Partnership elected to early adopt the ASU on a prospective basis for the three months ended March 31, 2014. The adoption did not have a material impact on the Partnership’s consolidated interim financial statements.

The FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The ASU specifies whether an unrecognized tax benefit, or a portion of an unrecognized tax benefit for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, should be presented in the financial statements as a reduction to a deferred tax asset or as a liability. The ASU is effective for annual and interim periods beginning in 2014. The Partnership adopted the ASU on a prospective basis for the three months ended March 31, 2014.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS

The following table presents the acquisitions completed by the Partnership during 2013 and 2014, 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
Non-Operated Marcellus Interest ⁽¹⁾	03/01/2013	33.75	%	$	250,000	$	215,500	449,129
Anadarko-Operated Marcellus Interest ⁽²⁾	03/08/2013	33.75	%	133,500		1,145		—
Mont Belvieu JV ⁽³⁾	06/05/2013	25	%	—		78,129		—
OTTCO ⁽⁴⁾	09/03/2013	100	%	27,500		—		—
TEFR Interests ⁽⁵⁾	03/03/2014	Various ⁽⁵⁾		350,000		6,250		308,490

⁽¹⁾

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.” 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 to maintain its 2.0% general partner interest in the Partnership.


⁽²⁾	The Partnership acquired 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, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest.”


⁽³⁾	The Partnership acquired a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting.


⁽⁴⁾	The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.

⁽⁵⁾

The Partnership acquired a 20% interest in each of TEG and TEP, and a 33.33% interest in FRP, from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and DJ Basin. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership’s general partner purchased 6,296 general partner units for consideration of $0.4 million to maintain its 2.0% general partner interest in the Partnership.

TEFR Interests acquisition. Because the acquisition of the TEFR Interests 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 TEFR Interests as if the Partnership owned such interests for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets or interests from Anadarko, including the TEFR Interests, 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 or interests during the periods reported.

The following table presents the impact of the TEFR Interests on revenue, equity income (loss), net and net income as presented in the Partnership’s historical consolidated statements of income:



	Three Months Ended March 31, 2013
thousands	Partnership Historical		TEFR Interests			Combined
Revenues	$	225,766	$	—		$	225,766
Equity income (loss), net	3,981		(13		)	3,968
Net income	$	52,888	$	57		$	52,945

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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 the Partnership’s unitholders for the periods presented:



thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
March 31, 2013	$	0.540	$	70,143	May 2013
March 31, 2014 ⁽¹⁾	$	0.625	$	98,749	May 2014


⁽¹⁾	On April 17, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.625 per unit, or $98.7 million in aggregate, including incentive distributions. The cash distribution is payable on May 14, 2014, to unitholders of record at the close of business on April 30, 2014.

4. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public offerings of its common units during 2013 and 2014:



thousands except unit and per-unit amounts	Common Units Issued	GP Units Issued ⁽¹⁾	Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
May 2013 equity offering ⁽²⁾	7,015,000	143,163	$	61.18	$	13,203	$	424,733
December 2013 equity offering ⁽³⁾	4,800,000	97,959	61.51		9,395		291,879
Continuous Offering Program - 2013 ⁽⁴⁾	685,735	13,996	60.84		965		41,603
Continuous Offering Program - 2014 ⁽⁵⁾	—	—	—		—		—


⁽¹⁾	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.


⁽²⁾	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.


⁽³⁾	Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with the December 2013 equity offering. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.2 million.

⁽⁴⁾

Represents common and general partner units issued during the year ended December 31, 2013, pursuant to the Partnership’s registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”). Gross proceeds generated (including the general partner’s proportionate capital contributions) were $42.6 million. The price per unit in the table above represents an average price for all issuances under the Continuous Offering Program during 2013.


⁽⁵⁾	During the three months ended March 31, 2014, the Partnership did not issue any common units under the Continuous Offering Program.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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

The following table summarizes common and general partner units issued during the three months ended March 31, 2014:



	Common Units	General Partner Units	Total
Balance at December 31, 2013	117,322,812	2,394,345	119,717,157
December 2013 equity offering	300,000	6,122	306,122
Long-Term Incentive Plan awards	1,280	—	1,280
TEFR Interests acquisition	308,490	6,296	314,786
Balance at March 31, 2014	117,932,582	2,406,763	120,339,345

Holdings of Partnership equity. As of March 31, 2014, WGP held 49,296,205 common units, representing a 41.0% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,406,763 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the Partnership’s IDRs. As of March 31, 2014, other wholly owned subsidiaries of Anadarko held 757,619 common units, representing a 0.6% limited partner interest in the Partnership. As of March 31, 2014, the public held 67,878,758 common units, representing a 56.4% limited partner interest in the Partnership.

The Partnership’s net income earned on and subsequent to the date of 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.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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 acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged or credited the Partnership interest at a variable rate on outstanding affiliate balances for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to 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 Processing LLC cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

Note receivable from Anadarko. Concurrently with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was $312.3 million and $296.7 million at March 31, 2014, and December 31, 2013, 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.

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 and MGR assets, as well as the Wattenberg assets (located in the DJ Basin complex), with various expiration dates through December 2016. In December 2013, the Partnership extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2014. 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.

Below is a summary of the fixed price ranges on the Partnership’s outstanding commodity price swap agreements as of March 31, 2014:



per barrel except natural gas	2014					2015					2016
Ethane	$	18.36	−	$	30.53	$	18.41	−	$	23.41	$	23.11
Propane	$	40.38	−	$	53.78	$	47.08	−	$	52.99	$	52.90
Isobutane	$	61.24	−	$	75.13	$	62.09	−	$	74.02	$	73.89
Normal butane	$	53.89	−	$	66.83	$	54.62	−	$	65.04	$	64.93
Natural gasoline	$	71.85	−	$	90.89	$	72.88	−	$	81.82	$	81.68
Condensate	$	75.22	−	$	87.30	$	76.47	−	$	81.82	$	81.68
Natural gas (per MMBtu)	$	3.45	−	$	6.20	$	4.66	−	$	5.96	$	4.87

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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



	Three Months Ended March 31,
thousands	2014			2013
Gains (losses) on commodity price swap agreements related to sales:⁽¹⁾
Natural gas sales	$	(3,667	)	$	5,380
Natural gas liquids sales	9,455			21,305
Total	5,788			26,685
Losses on commodity price swap agreements related to purchases ⁽²⁾	(19		)	(19,854		)
Net gains (losses) on commodity price swap agreements	$	5,769		$	6,831


⁽¹⁾	Reported in affiliate natural gas, natural gas liquids 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. For the three months ended March 31, 2014 and 2013, 48% and 58%, respectively, of the Partnership’s gathering, transportation and treating throughput (excluding equity investment throughput and throughput measured in barrels) was attributable to natural gas production owned or controlled by Anadarko. For the three months ended March 31, 2014 and 2013, 59% and 58%, respectively, of the Partnership’s processing throughput (excluding equity investment throughput and throughput measured in barrels) was attributable to natural gas production owned or controlled by Anadarko.

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



	Three Months Ended March 31,
	2014			2013
thousands	Purchases
Cash consideration	$	4,702		$	221
Net carrying value	4,745			227
Partners’ capital adjustment	$	(43	)	$	(6	)

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“WES LTIP”) primarily to its independent directors and its 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 over the vesting period and was $0.1 million for each of the three months ended March 31, 2014 and 2013.

WGP LTIP and Anadarko Incentive Plans. For the three months ended March 31, 2014 and 2013, the Partnership’s general and administrative expenses included $0.9 million and $0.7 million, respectively, of equity-based compensation expense, allocated to the Partnership by WGP and Anadarko, for awards granted to the executive officers of the general partner and other employees under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WGP LTIP”) and Anadarko Incentive Plans. Of this amount, $0.9 million is reflected as a contribution to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the three months ended March 31, 2014.

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 March 31,
thousands	2014		2013
Revenues ⁽¹⁾	$	206,290	$	177,569
Equity income, net	9,251		3,968
Cost of product ⁽¹⁾	16,634		31,929
Operation and maintenance ⁽²⁾	11,099		13,366
General and administrative ⁽³⁾	6,814		5,869
Operating expenses	34,547		51,164
Interest income, net ⁽⁴⁾	4,225		4,225
Distributions to unitholders ⁽⁵⁾	51,882		36,868


⁽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 WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).


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


⁽⁵⁾	Represents distributions paid under the partnership agreement (see Note 3 and Note 4).

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

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. PROPERTY, PLANT AND EQUIPMENT

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



thousands	Estimated Useful Life	March 31, 2014		December 31, 2013
Land	n/a	$	2,584	$	2,584
Gathering systems	3 to 47 years	3,773,582		3,673,008
Pipelines and equipment	15 to 45 years	145,475		146,008
Assets under construction	n/a	478,515		405,633
Other	3 to 40 years	14,012		11,867
Total property, plant and equipment		4,414,168		4,239,100
Accumulated depreciation		894,690		855,845
Net property, plant and equipment		$	3,519,478	$	3,383,255

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.

During 2014, the Partnership recognized a $1.2 million impairment primarily related to a non-operational plant in the Powder River Basin that was impaired to its estimated fair value of $2.4 million, using Level 3 fair-value inputs.

7. COMPONENTS OF WORKING CAPITAL

A summary of other current assets is as follows:



thousands	March 31, 2014		December 31, 2013
Natural gas liquids inventory	$	2,793	$	2,584
Natural gas imbalance receivables	2,101		3,605
Prepaid insurance	1,248		2,123
Other	1,290		1,710
Total other current assets	$	7,432	$	10,022

A summary of accrued liabilities is as follows:



thousands	March 31, 2014		December 31, 2013
Accrued capital expenditures	$	76,332	$	94,750
Accrued plant purchases	27,606		21,396
Accrued interest expense	17,547		18,119
Short-term asset retirement obligations	1,310		1,966
Short-term remediation and reclamation obligations	562		562
Other	1,536		218
Total accrued liabilities	$	124,893	$	137,011

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE

At March 31, 2014, debt consisted of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”), $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”), $350.0 million aggregate principal amount of 2.600% Senior Notes due 2018 (the “2018 Notes”), and $400.0 million aggregate principal amount of 5.450% Senior Notes due 2044 (the “2044 Notes”). The two tranches of the 2022 Notes, issued in June and October 2012, were issued under the same indenture and are considered a single class of securities. The two tranches of the 2018 Notes, issued in August 2013 and March 2014, were issued under the same indenture and are considered a single class of securities.

The following table presents the Partnership’s outstanding debt as of March 31, 2014, and December 31, 2013:



	March 31, 2014						December 31, 2013
thousands	Principal		Carrying Value		Fair Value ⁽¹⁾		Principal		Carrying Value		Fair Value ⁽¹⁾
5.375% Senior Notes due 2021	$	500,000	$	495,305	$	548,287	$	500,000	$	495,173	$	533,615
4.000% Senior Notes due 2022	670,000		673,192		666,755		670,000		673,278		641,237
2.600% Senior Notes due 2018	350,000		350,567		352,159		250,000		249,718		247,988
5.450% Senior Notes due 2044	400,000		393,775		406,664		—		—		—
Total debt outstanding	$	1,920,000	$	1,912,839	$	1,973,865	$	1,420,000	$	1,418,169	$	1,422,840


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

Debt activity. The following table presents the debt activity of the Partnership for the three months ended March 31, 2014:



thousands	Carrying Value
Balance at December 31, 2013	$	1,418,169
Revolving credit facility borrowings	430,000
Issuance of 5.450% Senior Notes due 2044	400,000
Issuance of 2.600% Senior Notes due 2018	100,000
Repayments of revolving credit facility	(430,000		)
Other	(5,330		)
Balance at March 31, 2014	$	1,912,839

Senior Notes. The 2044 Notes were offered at a price to the public of 98.443% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2044 Notes is 5.632%. Interest is paid semi-annually on April 1 and October 1 of each year. Proceeds (net of underwriting discount of $3.5 million, original issue discount and debt issuance costs) were used to repay amounts then outstanding under the Partnership’s senior unsecured revolving credit facility (“RCF”) and for general partnership purposes.

The 2018 Notes issued in March 2014 were offered at a price to the public of 100.857% of the face amount. Including the effects of the issuance premium for the March 2014 offering, the issuance discount for the August 2013 offering of 2018 Notes, and underwriting discounts, the effective interest rate of the 2018 Notes is 2.742%. Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $0.6 million, original issue premium and debt issuance costs) were used to repay amounts then outstanding under the Partnership’s RCF and for general partnership purposes.

At March 31, 2014, the Partnership was in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes, 2018 Notes, and 2044 Notes.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. DEBT AND INTEREST EXPENSE (CONTINUED)

Revolving credit facility. In February 2014, the Partnership entered into an amended and restated $1.2 billion senior unsecured RCF, which is expandable to a maximum of $1.5 billion. Subsequently, the Partnership borrowed $350.0 million under the RCF to fund the acquisition of the TEFR Interests. The RCF replaced an $800.0 million credit facility, which was originally entered into in March 2011. The RCF matures in February 2019 and bears interest at London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 0.975% to 1.45%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, in each case plus applicable margins currently ranging from zero to 0.45%, based upon the Partnership’s senior unsecured debt rating. The interest rate on the RCF was 1.45% at March 31, 2014. At December 31, 2013, the interest rate on the previous credit facility was 1.67%. The Partnership is required to pay a quarterly facility fee currently ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), based upon the Partnership’s senior unsecured debt rating. The facility fee rate was 0.20% and 0.25% at March 31, 2014, and December 31, 2013, respectively.

As of March 31, 2014, the Partnership had no outstanding borrowings, $12.8 million in outstanding letters of credit and $1.19 billion available for borrowing under the RCF. At March 31, 2014, the Partnership was in compliance with all covenants under the RCF.

The 2021 Notes, 2022 Notes, 2018 Notes, 2044 Notes and obligations under the RCF are recourse to the Partnership’s general partner. The Partnership’s general partner is 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, 2021 Notes, and/or the RCF.

In connection with the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest, and the TEFR Interests, the Partnership’s general partner and other wholly owned subsidiaries of Anadarko entered into indemnification agreements, whereby such subsidiaries 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, the Anadarko-Operated Marcellus Interest, and the TEFR Interests. These indemnification agreements apply to the 2044 Notes, 2018 Notes, and/or RCF borrowings outstanding related to the aforementioned acquisitions.

The Partnership’s general partner, the other indemnifying subsidiaries of Anadarko and WGRI also amended and restated the indemnity agreements between them to (i) conform language among all the indemnification agreements and (ii) 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 indemnification agreements related to the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest, and the TEFR Interests.

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



	Three Months Ended March 31,
thousands	2014			2013
Interest expense on long-term debt	$	16,135		$	13,939
Amortization of debt issuance costs and commitment fees	1,266			1,053
Capitalized interest	(3,440		)	(3,181		)
Interest expense	$	13,961		$	11,811

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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 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 that holds the Wattenberg assets (located in the DJ Basin complex). 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. Management does not believe the outcome of this proceeding will have a material effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership intends to vigorously defend this litigation. Furthermore, without regard to the merit of DCP’s claims, management believes that the Partnership has adequate contractual indemnities covering the claims against it in this lawsuit.

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

Other commitments. The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates. As of March 31, 2014, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of $53.6 million, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to the continued construction of a second train at the Lancaster processing plant and an expansion project at the Fort Lupton compressor station, both located in the DJ Basin complex.

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 2015 and includes an early termination clause.

Rent expense associated with the office, warehouse and equipment leases was $0.8 million and $0.7 million for the three months ended March 31, 2014 and 2013, respectively.

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

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and notes to consolidated financial statements, which are included under Part I, Item 1 of this quarterly report, as well as our historical consolidated financial statements, and the notes thereto, which are included in Part II, Item 8 of our 2013 Form 10-K as filed with the Securities and Exchange Commission, or “SEC,” on February 28, 2014, and our other public filings and press releases. For purposes of this report, “we,” “us,” “our,” the “Partnership,” or “Western Gas Partners” refers 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 Delaware master limited partnership formed by Anadarko Petroleum Corporation. 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 our general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78, LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “Equity investment throughput” refers to our 14.81% share of average Fort Union throughput and our 22% share of average Rendezvous throughput, but excludes throughput measured in barrels consisting of our 10% share of average White Cliffs pipeline throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEP and TEG throughput and our 33.33% share of average FRP throughput. The “DJ Basin complex” refers to the Platte Valley system, Wattenberg system, and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014.

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 and Anadarko’s 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;

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•	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 use 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 among 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 2013 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.

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EXECUTIVE SUMMARY

We are a growth-oriented Delaware master limited partnership formed by Anadarko to own, operate, acquire and develop midstream energy assets. We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), north-central Pennsylvania and Texas, and are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. As of March 31, 2014, our assets and investments accounted for under the equity method consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	13	1	5	2
NGL gathering systems	—	—	—	2
Natural gas treating facilities	8	—	—	1
Natural gas processing facilities	8	3	—	2
NGL pipelines	3	—	—	2
Natural gas pipelines	3	—	—	—
Oil pipeline	—	—	—	1

Significant financial and operational highlights during the first three months of 2014 included the following:


•	We issued $400.0 million aggregate principal amount of 5.450% Senior Notes due 2044 and an additional $100.0 million aggregate principal amount of 2.600% Senior Notes due 2018. Net proceeds were used to repay amounts then outstanding under our RCF. See Liquidity and Capital Resources within this Item 2 for additional information.


•	We completed the acquisition of Anadarko’s 20% interests in TEG and TEP, and its 33.33% interest in FRP. See Acquisitions below.


•	We entered into an amended and restated $1.2 billion (expandable to $1.5 billion) senior unsecured RCF replacing our $800.0 million credit facility. See Liquidity and Capital Resources within this Item 2 for additional information.


•	We raised our distribution to $0.625 per unit for the first quarter of 2014, representing a 4% increase over the distribution for the fourth quarter of 2013, a 16% increase over the distribution for the first quarter of 2013, and our twentieth consecutive quarterly increase.

Significant operational highlights during the first three months of 2014 included the following:


•	Throughput attributable to Western Gas Partners, LP totaled 3,404 MMcf/d for the three months ended March 31, 2014, representing a 17% increase compared to the three months ended March 31, 2013.


•	Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $0.60 per Mcf for the three months ended March 31, 2014, representing an 11% increase compared to the three months ended March 31, 2013.

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ACQUISITIONS

Acquisitions. The following table presents our acquisitions during 2013 and 2014, 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
Non-Operated Marcellus Interest ⁽¹⁾	03/01/2013	33.75	%	$	250,000	$	215,500	449,129
Anadarko-Operated Marcellus Interest ⁽²⁾	03/08/2013	33.75	%	133,500		1,145		—
Mont Belvieu JV ⁽³⁾	06/05/2013	25	%	—		78,129		—
OTTCO ⁽⁴⁾	09/03/2013	100	%	27,500		—		—
TEFR Interests ⁽⁵⁾	03/03/2014	Various ⁽⁵⁾		350,000		6,250		308,490

⁽¹⁾

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.” In connection with the issuance of the common units, our general partner purchased 9,166 general partner units for consideration of $0.5 million to maintain its 2.0% general partner interest in us.


⁽²⁾	We acquired 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, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest.”


⁽³⁾	We acquired a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting.


⁽⁴⁾	We acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects our Red Desert and Granger complexes in southwestern Wyoming.

⁽⁵⁾

We acquired a 20% interest in each of TEG and TEP, and a 33.33% interest in FRP, from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and DJ Basin. TEG consists of two NGL gathering systems that link natural gas processing plants to TEP. TEP is an NGL pipeline that originates in Skellytown, Texas and extends approximately 580 miles to Mont Belvieu, Texas. FRP is a 435 mile NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, our general partner purchased 6,296 general partner units for consideration of $0.4 million to maintain its 2.0% general partner interest in us. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets and interests accounted for under the equity method owned by us as of March 31, 2014. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of assets or interests from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets or interests 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 or interests from Anadarko, we may be required to recast our financial statements to include the activities of such assets or interests 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 TEFR Interests as if we owned such interests for all periods presented. The consolidated financial statements for periods prior to our acquisition of the Partnership assets or interests from Anadarko, including the TEFR Interests, 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 or interests during the periods reported.

EQUITY OFFERINGS

Equity offerings. We completed the following public equity offerings during 2013 and 2014:



thousands except unit and per-unit amounts	Common Units Issued	GP Units Issued ⁽¹⁾	Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
May 2013 equity offering ⁽²⁾	7,015,000	143,163	$	61.18	$	13,203	$	424,733
December 2013 equity offering ⁽³⁾	4,800,000	97,959	61.51		9,395		291,879
Continuous Offering Program - 2013 ⁽⁴⁾	685,735	13,996	60.84		965		41,603
Continuous Offering Program - 2014 ⁽⁵⁾	—	—	—		—		—


⁽¹⁾	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.


⁽²⁾	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.


⁽³⁾	Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with the December 2013 equity offering. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.2 million.

⁽⁴⁾

Represents common and general partner units issued during the year ended December 31, 2013, pursuant to our registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”). Gross proceeds generated (including our general partner’s proportionate capital contributions) were $42.6 million. The price per unit in the table above represents an average price for all issuances under our Continuous Offering Program during 2013.


⁽⁵⁾	During the three months ended March 31, 2014, we did not issue any common units under our Continuous Offering Program.

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RESULTS OF OPERATIONS

OPERATING RESULTS

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



	Three Months Ended March 31,
thousands	2014			2013
Gathering, processing and transportation of natural gas and natural gas liquids	$	141,449		$	102,890
Natural gas, natural gas liquids and condensate sales	136,438			121,729
Other, net	1,570			1,147
Total revenues ⁽¹⁾	279,457			225,766
Equity income, net	9,251			3,968
Total operating expenses ⁽¹⁾	188,550			165,711
Operating income	100,158			64,023
Interest income, net – affiliates	4,225			4,225
Interest expense	(13,961		)	(11,811		)
Other income (expense), net	477			674
Income before income taxes	90,899			57,111
Income tax expense	(228		)	4,166
Net income	91,127			52,945
Net income attributable to noncontrolling interest	3,692			2,231
Net income attributable to Western Gas Partners, LP	$	87,435		$	50,714
Key performance metrics ⁽²⁾
Adjusted gross margin attributable to Western Gas Partners, LP	$	194,726		$	143,986
Adjusted EBITDA attributable to Western Gas Partners, LP	$	140,999		$	95,928
Distributable cash flow	$	119,321		$	79,129

⁽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⁾

Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption Key Performance Metrics within this Item 2. Such caption also includes reconciliations of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with Generally Accepted Accounting Principles (“GAAP”).

For purposes of the following discussion, any increases or decreases “for the three months ended March 31, 2014” refer to the comparison of the three months ended March 31, 2014, to the three months ended March 31, 2013.

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Throughput



	Three Months Ended March 31,
MMcf/d (except throughput measured in barrels)	2014	2013	Inc/ (Dec)
Throughput for natural gas assets
Gathering, treating and transportation ⁽¹⁾	1,592	1,251	27	%
Processing ⁽¹⁾	1,799	1,609	12	%
Equity investment ⁽²⁾	186	201	(7	)%
Total throughput for natural gas assets	3,577	3,061	17	%
Throughput attributable to noncontrolling interest for natural gas assets	173	155	12	%
Total throughput attributable to Western Gas Partners, LP for natural gas assets ⁽³⁾	3,404	2,906	17	%
Total throughput (MBbls/d) for crude/NGL assets ⁽⁴⁾	79	27	193	%

⁽¹⁾

The combination of our Wattenberg and Platte Valley systems in the first quarter of 2014 into the entity now referred to as the “DJ Basin complex” resulted in the following: (i) the Wattenberg system volumes previously reported as “Gathering, treating and transportation” are now reported as “Processing” for all periods presented, and (ii) volumes both gathered and processed by the two systems are no longer separately reported.


⁽²⁾	Represents our 14.81% share of average Fort Union and our 22% share of average Rendezvous throughput. Excludes equity investment throughput measured in barrels (captured in “Total throughput (MBbls/d) for crude/NGL assets” as noted below).


⁽³⁾	Includes affiliate, third-party and equity investment throughput (as equity investment throughput is defined in the above footnote), excluding the noncontrolling interest owner’s proportionate share of throughput.


⁽⁴⁾	Represents total throughput measured in barrels consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput.

Gathering, treating and transportation throughput increased by 341 MMcf/d for the three months ended March 31, 2014, due to increased throughput from the Non-Operated Marcellus Interest as a result of additional connection of wells that were waiting on pipeline infrastructure and the Anadarko-Operated Marcellus Interest beginning in March 2013.

Processing throughput increased by 190 MMcf/d for the three months ended March 31, 2014, primarily due to the start-up of the Brasada facility in June 2013.

Equity investment throughput decreased by 15 MMcf/d for the three months ended March 31, 2014, primarily due to lower throughput at the Fort Union system due to production declines in the area.

Throughput for crude/NGL assets measured in barrels increased by 52 MBbls/d for the three months ended March 31, 2014, due to the start-up of the Mont Belvieu JV fractionation trains, TEP and TEG in the fourth quarter of 2013.

Natural Gas Gathering, Processing and Transportation Revenues



	Three Months Ended March 31,
thousands except percentages	2014		2013		Inc/ (Dec)
Gathering, processing and transportation of natural gas and natural gas liquids	$	141,449	$	102,890	37	%

Revenues from gathering, processing and transportation of natural gas and natural gas liquids increased by $38.6 million for the three months ended March 31, 2014, primarily due to revenue increases of $11.3 million, $7.4 million, and $4.5 million at the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest, and Chipeta, respectively, all due to higher throughput, and an increase of $11.3 million due to the start-up of the Brasada facility in June 2013.

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Natural Gas, Natural Gas Liquids and Condensate Sales



	Three Months Ended March 31,
thousands except percentages and per-unit amounts	2014		2013		Inc/ (Dec)
Natural gas sales	$	30,875	$	25,517	21	%
Natural gas liquids sales	95,813		87,217		10	%
Drip condensate sales	9,750		8,995		8	%
Total	$	136,438	$	121,729	12	%
Average price per unit:
Natural gas (per Mcf)	$	4.25	$	4.21	1	%
Natural gas liquids (per Bbl)	$	44.77	$	47.04	(5	)%
Drip condensate (per Bbl)	$	79.34	$	74.56	6	%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $14.7 million for the three months ended March 31, 2014, which consisted of a $5.4 million increase in sales of natural gas, an $8.6 million increase in NGLs sales and a $0.7 million increase in drip condensate sales.

The growth in natural gas sales for the three months ended March 31, 2014, was primarily due to higher sales volumes at the Hilight system and the Red Desert complex.

The growth in NGLs sales for the three months ended March 31, 2014, was primarily due to increases of $3.8 million, $2.2 million, and $1.6 million resulting from higher volumes processed and sold at Chipeta, the Granger straddle plant, and the Hilight system, respectively.

The increase in drip condensate sales for the three months ended March 31, 2014, was primarily due to an increase of $1.3 million at the DJ Basin complex, resulting from an increase in condensate volumes sold as a result of increased throughput, partially offset by a $0.6 million decrease at Hugoton due to a decrease in condensate volumes sold as a result of decreased throughput.

For the three months ended March 31, 2014 and 2013, average natural gas, NGL and drip condensate prices include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle, and MGR assets, as well as at the Wattenberg assets (located in the DJ Basin complex). See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Equity Income, Net



	Three Months Ended March 31,
thousands except percentages	2014		2013		Inc/ (Dec)
Equity income, net	$	9,251	$	3,968	133	%

For the three months ended March 31, 2014, equity income increased by $5.3 million, primarily driven by an increase of $7.1 million due to the fourth quarter 2013 start-up of the Mont Belvieu JV fractionation trains, which was offset by a decrease of $2.0 million attributable to losses associated with the initial start-up and line fill stage of TEP during the fourth quarter of 2013 and of FRP during the first quarter of 2014.

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Cost of Product and Operation and Maintenance Expenses



	Three Months Ended March 31,
thousands except percentages	2014		2013		Inc/ (Dec)
NGL purchases	$	47,881	$	42,009	14	%
Residue purchases	37,107		37,504		(1	)%
Other	6,962		3,570		95	%
Cost of product	$	91,950	$	83,083	11	%
Operation and maintenance	40,532		36,739		10	%
Total cost of product and operation and maintenance expenses	$	132,482	$	119,822	11	%

Including the effects of commodity price swap agreements on purchases, cost of product expense for the three months ended March 31, 2014, increased by $8.9 million primarily due to the volume fluctuations noted in Throughput and Natural Gas, Natural Gas Liquids and Condensate Sales within this Item 2, resulting in the following:


•	a $5.9 million net increase in NGL purchases, primarily at Chipeta, the Hilight system, the Red Desert complex and the DJ Basin complex;


•	a $0.4 million net decrease in residue purchases, primarily due to decreases at the DJ Basin complex and the Granger complex, partially offset by increases at the Hilight system and Chipeta; and


•	a $2.7 million increase in other, due to changes in imbalance positions primarily at the DJ Basin complex.

Cost of product expense for the three months ended March 31, 2014 and 2013, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and MGR assets, as well as the Wattenberg assets (located in the DJ Basin complex). See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

Operation and maintenance expense increased by $3.8 million for the three months ended March 31, 2014, primarily due to an increase of $4.1 million for plant repairs and maintenance primarily at the DJ Basin complex and the Brasada facility.

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General and Administrative, Depreciation and Other Expenses



	Three Months Ended March 31,
thousands except percentages	2014		2013		Inc/ (Dec)
General and administrative	$	8,415	$	7,664	10	%
Property and other taxes	7,041		5,785		22	%
Depreciation, amortization and impairments	40,612		32,440		25	%
Total general and administrative, depreciation and other expenses	$	56,068	$	45,889	22	%

General and administrative expenses increased by $0.8 million for the three months ended March 31, 2014, primarily due to an increase of $0.6 million in corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement and an increase of $0.2 million in non-cash compensation expenses.

Property and other taxes increased by $1.3 million for the three months ended March 31, 2014, primarily due to ad valorem tax increases of $0.7 million associated with capital additions at the DJ Basin complex and $0.6 million due to the completion of Brasada facility in June 2013.

Depreciation, amortization and impairments increased by $8.2 million for the three months ended March 31, 2014, primarily attributable to a $2.4 million increase in depreciation expense associated with the Non-Operated Marcellus Interest and the Anadarko-Operated Marcellus Interest, a $2.4 million increase in depreciation expense due to the completion of the Brasada facility in June 2013, a $1.3 million increase in depreciation expense associated with compression expansion capital projects completed at the DJ Basin complex, an $0.8 million increase in depreciation expense related to OTTCO, which was acquired in September 2013, and an impairment of $1.0 million during 2014 related to a non-operational plant in the Powder River Basin with no comparative activity in the prior period.

Interest Income, Net – Affiliates and Interest Expense



	Three Months Ended March 31,
thousands except percentages	2014			2013			Inc/ (Dec)
Interest income on note receivable	$	4,225		$	4,225		—	%
Interest income, net – affiliates	$	4,225		$	4,225		—	%
Interest expense on long-term debt	$	(16,135	)	$	(13,939	)	16	%
Amortization of debt issuance costs and commitment fees	(1,266		)	(1,053		)	20	%
Capitalized interest	3,440			3,181			8	%
Interest expense	$	(13,961	)	$	(11,811	)	18	%

Interest expense increased by $2.2 million for the three months ended March 31, 2014, primarily due to interest expense of $1.7 million incurred on the 2.600% Senior Notes due 2018 and $0.7 million on the 5.450% Senior Notes due 2044. Amortization of debt issuance costs and commitment fees increased by $0.2 million for the three months ended March 31, 2014, primarily due to the issuance of the 2.600% Senior Notes due 2018 and the amended and restated RCF. These increases were partially offset by an increase of capitalized interest of $0.3 million primarily associated with the expansion of the Lancaster plant located in the DJ Basin complex. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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Income Tax Expense



	Three Months Ended March 31,
thousands except percentages	2014			2013			Inc/ (Dec)
Income before income taxes	$	90,899		$	57,111		59	%
Income tax (benefit) expense	(228		)	4,166			(105	)%
Effective tax rate	—		%	7		%

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 TEFR Interests prior to and including February 2014 and (b) the Non-Operated Marcellus Interest prior to and including February 2013 was subject to federal and state income tax. Income earned on the TEFR Interests and the Non-Operated Marcellus Interest for periods subsequent to February 2014 and February 2013, respectively, was only subject to Texas margin tax on income apportionable to Texas.

Noncontrolling Interest



	Three Months Ended March 31,
thousands except percentages	2014		2013		Inc/ (Dec)
Net income attributable to noncontrolling interest	$	3,692	$	2,231	65	%

For the three months ended March 31, 2014, net income attributable to noncontrolling interest increased by $1.5 million, primarily due to increased revenues at Chipeta driven by increased drilling activities in the Uintah Basin.

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KEY PERFORMANCE METRICS



	Three Months Ended March 31,
thousands except percentages and per-unit amounts	2014		2013		Inc/ (Dec)
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets ⁽¹⁾	$	183,937	$	140,395	31	%
Adjusted gross margin for crude/NGL assets ⁽²⁾	10,789		3,591		200	%
Adjusted gross margin attributable to Western Gas Partners, LP	$	194,726	$	143,986	35	%
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets ⁽³⁾	0.60		0.54		11	%
Adjusted gross margin per Bbl for crude/NGL assets ⁽⁴⁾	1.52		1.48		3	%
Adjusted EBITDA attributable to Western Gas Partners, LP ⁽⁵⁾	140,999		95,928		47	%
Distributable cash flow ⁽⁵⁾	$	119,321	$	79,129	51	%

⁽¹⁾

Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure below.


⁽²⁾	Adjusted gross margin for crude/NGL assets is calculated as total revenues for crude/NGL assets less cost of product for crude/NGL assets plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, TEG, TEP and FRP, which are measured in barrels. See the reconciliation of Adjusted gross margin for crude/NGL assets to its most comparable GAAP measure below.


⁽³⁾	Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets divided by total throughput attributable to Western Gas Partners, LP for natural gas assets.


⁽⁴⁾	Average for period. Calculated as Adjusted gross margin for crude/NGL assets, divided by total throughput (MBbls/d) for crude/NGL assets.


⁽⁵⁾	For reconciliations of Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see the descriptions below.

Adjusted gross margin attributable to Western Gas Partners, LP . We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues less cost of product, plus distributions from equity investees and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. We believe Adjusted gross margin is an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in our industry, without regard to financing methods, historical cost basis, or capital structure.

Adjusted gross margin increased by $50.7 million for the three months ended March 31, 2014, primarily due to higher margins on the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest, the DJ Basin complex and Chipeta, the start-up of the Mont Belvieu JV in the fourth quarter of 2013 and the start-up of the Brasada facility in June 2013.

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets and Adjusted gross margin per Bbl for crude/NGL assets. Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets increased by $0.06 for the three months ended March 31, 2014, primarily due to higher margins and increases in throughput at Chipeta, the DJ Basin complex, and the Non-Operated Marcellus Interest, as well as overall changes in the throughput mix of our portfolio. Adjusted gross margin per Bbl for crude/NGL assets increased by $0.04 for the three months ended March 31, 2014, due to distributions received from the Mont Belvieu JV during the first quarter of 2014.

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Adjusted EBITDA attributable to Western Gas Partners, LP. We define Adjusted EBITDA attributable to Western Gas Partners, LP (“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 $45.1 million for the three months ended March 31, 2014, primarily due to a $53.7 million increase in total revenues and a $7.3 million increase in distributions from equity investees. These amounts were offset by an $8.9 million increase in cost of product, a $3.8 million increase in operation and maintenance expenses, a $1.5 million increase in net income attributable to noncontrolling interest, and a $1.3 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 $40.2 million for the three months ended March 31, 2014, primarily due to a $45.1 million increase in Adjusted EBITDA, offset by a $2.8 million increase in maintenance capital expenditures and a $2.4 million increase in net cash paid for interest expense.

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Reconciliation to GAAP measures. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. The GAAP measure used by us that is most directly comparable to Adjusted gross margin is operating income, while net income attributable to Western Gas Partners, LP and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA. The GAAP measure used by us that is most directly comparable to Distributable cash flow is net income attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow should not be considered as alternatives to the GAAP measures of operating income, 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 gross margin, Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income, net income and net cash provided by operating activities. Adjusted gross margin, 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 gross margin, 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 gross margin, Adjusted EBITDA and Distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA and Distributable cash flow compared to (as applicable) operating income, 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 gross margin to the GAAP measure of operating income, (b) 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 (c) a reconciliation of the non-GAAP financial measure of Distributable cash flow to the GAAP financial measure of net income attributable to Western Gas Partners, LP:



	Three Months Ended March 31,
thousands	2014		2013
Reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to Operating income
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets	$	183,937	$	140,395
Adjusted gross margin for crude/NGL assets	10,789		3,591
Adjusted gross margin attributable to Western Gas Partners, LP	$	194,726	$	143,986
Adjusted gross margin attributable to noncontrolling interest	5,094		3,703
Equity income, net	9,251		3,968
Less:
Distributions from equity investees	12,313		5,006
Operation and maintenance	40,532		36,739
General and administrative	8,415		7,664
Property and other taxes	7,041		5,785
Depreciation, amortization and impairments	40,612		32,440
Operating income	$	100,158	$	64,023

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	Three Months Ended March 31,
thousands	2014			2013
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	140,999		$	95,928
Less:
Distributions from equity investees	12,313			5,006
Non-cash equity-based compensation expense	1,097			877
Interest expense	13,961			11,811
Income tax expense	—			4,166
Depreciation, amortization and impairments ⁽¹⁾	39,975			31,824
Add:
Equity income, net	9,251			3,968
Interest income, net – affiliates	4,225			4,225
Other income ^{(1) (2)}	78			277
Income tax benefit	228			—
Net income attributable to Western Gas Partners, LP	$	87,435		$	50,714
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	140,999		$	95,928
Adjusted EBITDA attributable to noncontrolling interest	4,326			2,846
Interest income (expense), net	(9,736		)	(7,586		)
Non-cash equity-based compensation expense	53			(73		)
Debt-related amortization and other items, net	680			560
Current income tax benefit	518			5,104
Other income (expense), net ⁽²⁾	81			278
Distributions from equity investments in excess of cumulative earnings	(2,044		)	—
Changes in operating working capital:
Accounts receivable, net	(10,982		)	21,661
Accounts and natural gas imbalance payables and accrued liabilities, net	(1,727		)	21,287
Other	1,878			(1,835		)
Net cash provided by operating activities	$	124,046		$	138,170
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	124,046		$	138,170
Net cash used in investing activities	(576,697		)	(831,633		)
Net cash provided by financing activities	435,014			336,998


⁽¹⁾	Includes our 75% share of depreciation, amortization and impairments; and other income attributable to Chipeta.


⁽²⁾	Excludes income of $0.4 million for each of the three months ended March 31, 2014 and 2013, related to a component of a gas processing agreement accounted for as a capital lease.

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	Three Months Ended March 31,
thousands except Coverage ratio	2014				2013
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	119,321			$	79,129
Less:
Distributions from equity investees	12,313				5,006
Non-cash equity-based compensation expense	1,097				877
Income tax (benefit) expense	(228		)		4,166
Depreciation, amortization and impairments ⁽¹⁾	39,975				31,824
Add:
Equity income, net	9,251				3,968
Cash paid for maintenance capital expenditures ⁽¹⁾	8,842				6,032
Capitalized interest	3,440				3,181
Cash paid for (reimbursement of) income taxes	(340		)		—
Other income ^{(1) (2)}	78				277
Net income attributable to Western Gas Partners, LP	$	87,435			$	50,714
Distributions declared ⁽³⁾
Limited partners	$	73,708
General partner	25,041
Total	$	98,749
Coverage ratio	1.21			x


⁽¹⁾	Includes our 75% share of depreciation, amortization and impairments; cash paid for maintenance capital expenditures; and other income attributable to Chipeta.


⁽²⁾	Excludes income of $0.4 million for each of the three months ended March 31, 2014 and 2013, related to a component of a gas processing agreement accounted for as a capital lease.


⁽³⁾	Reflects distributions of $0.625 per unit declared for the three months ended March 31, 2014.

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LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owner. Our sources of liquidity as of March 31, 2014, included cash and cash equivalents, cash flows generated from operations, 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 initial public offering and have increased our quarterly distribution each quarter since the second quarter of 2009. On April 17, 2014, the board of directors of our general partner declared a cash distribution to our unitholders of $0.625 per unit, or $98.7 million in aggregate, including incentive distributions. The cash distribution is payable on May 14, 2014, to unitholders of record at the close of business on April 30, 2014.

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 March 31, 2014, we had $18.7 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 March 31, 2014, we had $1.19 billion available for borrowing under our RCF.

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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 (for fiscal year 2014, the general partner’s board of directors has approved Estimated Maintenance Capital Expenditures (as defined in our partnership agreement) of $15.3 million per quarter); or


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

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



	Three Months Ended March 31,
thousands	2014		2013
Acquisitions	$	360,952	$	600,590

Expansion capital expenditures	$	180,363	$	160,431
Maintenance capital expenditures	8,964		6,032
Total capital expenditures ⁽¹⁾	$	189,327	$	166,463

Capital incurred ⁽²⁾	$	170,909	$	163,663


⁽¹⁾	Capital expenditures for the three months ended March 31, 2014 and 2013, included $3.4 million and $3.2 million, respectively, of capitalized interest. Capital expenditures included the noncontrolling interest owner’s share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owner for all periods presented.

⁽²⁾

Includes the noncontrolling interest owner’s share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owner for all periods presented. Capital incurred for the three months ended March 31, 2014 and 2013, included $3.4 million and $3.2 million, respectively, of capitalized interest. Capital incurred for the three months ended March 31, 2013, included $8.8 million of pre-acquisition capital incurred for the Non-Operated Marcellus Interest.

Acquisitions included the TEFR Interests in the first quarter of 2014 and the Anadarko-Operated Marcellus Interest and the Non-Operated Marcellus Interest in the first quarter of 2013. See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

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Capital expenditures, excluding acquisitions, increased by $22.9 million for the three months ended March 31, 2014. Expansion capital expenditures increased by $19.9 million (including a $0.3 million increase in capitalized interest) for the three months ended March 31, 2014, primarily due to increased activity at the DJ Basin complex, which consisted of $31.7 million related to the construction of the Lancaster plant and $31.3 million at the Wattenberg system related to compression projects and well connects. In addition, there was an increase of $9.1 million at the Hilight system and $4.7 million at the Haley gathering system. These increases were partially offset by a $40.0 million decrease at the Brasada facility driven by the completion of construction in June 2013, a $7.3 million decrease at Chipeta and a $6.8 million decrease at the Non-Operated Marcellus Interest. Maintenance capital expenditures increased by $2.9 million, primarily as a result of increased expenditures of $3.8 million at the Wattenberg system (located in the DJ Basin complex), the Non-Operated Marcellus Interest, the Red Desert complex and Chipeta, partially offset by a $1.1 million decrease at the Platte Valley system located in the DJ Basin complex.

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:



	Three Months Ended March 31,
thousands	2014			2013
Net cash provided by (used in):
Operating activities	$	124,046		$	138,170
Investing activities	(576,697		)	(831,633		)
Financing activities	435,014			336,998
Net increase (decrease) in cash and cash equivalents	$	(17,637	)	$	(356,465	)

Operating Activities. Net cash provided by operating activities during the three months ended March 31, 2014, decreased primarily due to the impact of changes in working capital items.

Refer to Operating Results within this Item 2 for a discussion of our results of operations as compared to the prior periods.

Investing Activities. Net cash used in investing activities for the three months ended March 31, 2014, included the following:


•	$356.3 million of cash paid for the acquisition of the TEFR Interests;


•	$189.3 million of capital expenditures, primarily related to the construction of the Lancaster plant and compression expansion projects at the Wattenberg system (both located in the DJ Basin complex);


•	$22.0 million of cash paid related to the construction of the Front Range pipeline, which was completed during the first quarter of 2014;


•	$4.7 million of cash paid for equipment purchases from Anadarko;


•	$2.5 million of cash paid to a White Cliffs expansion project; and


•	$2.0 million of distributions from equity investments in excess of cumulative earnings.

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


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


•	$166.5 million of capital expenditures;


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


•	$4.8 million of cash paid related to a White Cliffs expansion project.

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Financing Activities. Net cash provided by financing activities for the three months ended March 31, 2014, included the following:


•	$350.0 million of borrowings to fund the acquisition of the TEFR Interests;


•	$390.1 million of net proceeds from the 2044 Notes offering in March 2014, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our outstanding borrowings under our RCF, including $350.0 million of borrowings to fund the acquisition of the TEFR Interests;


•	$100.2 million of net proceeds from the additional 2018 Notes offering in March 2014, after underwriting discounts, original issue premium and offering costs, part of which was used to repay a portion of our outstanding borrowings under our RCF;


•	$18.2 million of net proceeds related to the partial exercise of the underwriters’ over-allotment option granted in connection with our December 2013 equity offering;


•	$80.0 million of borrowings to fund capital expenditures and general partnership purposes; and


•	$0.4 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 acquisition of the TEFR Interests.

Net contributions from Anadarko attributable to intercompany balances were $23.8 million during the three months ended March 31, 2014, representing intercompany transactions attributable to the TEFR Interests.

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


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


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


•	$0.5 million of net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% 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 $21.6 million during the three months ended March 31, 2013, representing intercompany transactions attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest.

For the three months ended March 31, 2014 and 2013, we paid $92.6 million and $65.7 million, respectively, of cash distributions to our unitholders. Contributions from the noncontrolling interest owner of Chipeta totaled zero and $1.1 million during the three months ended March 31, 2014 and 2013, primarily for expansion of the cryogenic units and plant construction. Distributions to the noncontrolling interest owner of Chipeta totaled $4.1 million and $2.7 million for the three months ended March 31, 2014 and 2013, respectively, representing the distributions paid as of March 31 of the respective year.

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Debt and credit facility. Our total outstanding debt as of March 31, 2014, consisted of $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”), $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”), $350.0 million aggregate principal amount of 2.600% Senior Notes due 2018 (the “2018 Notes”), and $400.0 million aggregate principal amount of 5.450% Senior Notes due 2044 (the “2044 Notes”). The two tranches of the 2022 Notes, issued in June and October 2012, were issued under the same indenture and are considered a single class of securities. The two tranches of the 2018 Notes, issued in August 2013 and March 2014, were issued under the same indenture and are considered a single class of securities. As of March 31, 2014, the carrying value of our outstanding debt consisted of $495.3 million of 2021 Notes, $673.2 million of 2022 Notes, $350.6 million of 2018 Notes and $393.8 million of 2044 Notes. See Note 8—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q.

At March 31, 2014, we were in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes, 2018 Notes, and 2044 Notes.

Revolving credit facility. In February 2014, we entered into an amended and restated $1.2 billion senior unsecured RCF, which is expandable to a maximum of $1.5 billion. Subsequently, we borrowed $350.0 million under the RCF to fund the acquisition of the TEFR Interests (see Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q). The RCF replaced an $800.0 million credit facility, which was originally entered into in March 2011. The RCF matures in February 2019 and bears interest at London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 0.975% to 1.45%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, in each case plus applicable margins currently ranging from zero to 0.45%, based upon our senior unsecured debt rating. As of March 31, 2014, we had no outstanding borrowings, $12.8 million in outstanding letters of credit and $1.19 billion available for borrowing under the RCF. The interest rate on the RCF was 1.45% at March 31, 2014. At December 31, 2013, the interest rate on the previous credit facility was 1.67%. We are required to pay a quarterly facility fee currently ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), based upon our senior unsecured debt rating. The facility fee rate was 0.20% and 0.25% at March 31, 2014, and December 31, 2013, respectively. At March 31, 2014, we were in compliance with all covenants under the RCF.

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The 2021 Notes, 2022 Notes, 2018 Notes, 2044 Notes and obligations under the RCF are recourse to our general partner. Our general partner is 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, 2021 Notes, and/or the RCF.

In connection with the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest, and the TEFR Interests, our general partner and other wholly owned subsidiaries of Anadarko entered into indemnification agreements, whereby such subsidiaries 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, the Anadarko-Operated Marcellus Interest, and the TEFR Interests. These indemnification agreements apply to the 2044 Notes, 2018 Notes, and/or RCF borrowings outstanding related to the aforementioned acquisitions.

Our general partner, the other indemnifying subsidiaries of Anadarko and WGRI also amended and restated the indemnity agreements between them to (i) conform language among all the indemnification agreements and (ii) reduce the amount for which WGRI would indemnify our general partner by an amount equal to any amounts payable to the general partner under the indemnification agreements related to the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest, and the TEFR Interests.

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 an aggregate of $125.0 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (the “Continuous Offering Program”). See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q for a discussion of trades completed under our Continuous Offering Program.

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.

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CONTRACTUAL OBLIGATIONS

Our contractual obligations include, among other things, a revolving credit facility, other third-party long-term debt, capital obligations related to our expansion projects and various operating leases. Refer to Note 8—Debt and Interest Expense and Note 9—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 1 of this Form 10-Q for an update to our contractual obligations as of March 31, 2014, 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 that 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 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 three months ended March 31, 2014, were low compared to historic rates. As of March 31, 2014, we had no outstanding borrowings under our RCF (which bears interest at a rate based on LIBOR or, at our option, an alternative base rate). If interest rates rise, our future financing costs could increase. A 10% change in LIBOR would have resulted in no change in net income or in the fair value of the borrowings under the RCF at March 31, 2014.

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.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of the Partnership’s general partner performed an evaluation of the Partnership’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (“Exchange Act”). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Partnership’s disclosure controls and procedures are effective as of March 31, 2014.

Changes in Internal Control Over Financial Reporting. There has been no change in our internal control over financial reporting during the quarter ended March 31, 2014, 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 a final disposition could have a material adverse effect on our results of operations, cash flows or financial condition.

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, 2013, 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, 2013, 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.

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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.



Exhibit Number		Description
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).
2.9#		Contribution Agreement, dated as of February 27, 2014, by and among WGR Asset Holding Company, LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.9 to the Annual Report on Form 10-K filed by Western Gas Partners, LP on February 28, 2014, File No. 001-34046).

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Exhibit Number		Description
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		Amendment No. 11 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 3, 2014 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
3.14		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).
3.15		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).

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Exhibit Number		Description
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		Fifth Supplemental Indenture, dated as of August 14, 2013, 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 August 14, 2013, 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).
4.7		Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
4.8		Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, 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 March 20, 2014, File No. 001-34046).
4.9		Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
10.1		Second Amended and Restated Revolving Credit Agreement, dated as of February 26, 2014, among Western Gas Partners, LP, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.15 to the Annual Report on From 10-K filed by Western Gas Partners, LP on February 28, 2014, File No. 001-34046).
10.2		Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and APC Midstream Holdings, LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
10.3		First Amendment to the Third Amended and Restated Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
10.4		USH2 Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and USH2 LLC (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
31.1*		Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document



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

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SIGNATURES

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



	WESTERN GAS PARTNERS, LP

May 7, 2014

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

May 7, 2014

	/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)