10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2018

Or

¨ 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 every Interactive Data File required to be submitted 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 such files).    Yes  þ    No  ¨

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 152,609,285 common units outstanding as of July 30, 2018.

TABLE OF CONTENTS

			PAGE
PART I		FINANCIAL INFORMATION (UNAUDITED)
	Item 1.	Financial Statements
		Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017	6
		Consolidated Balance Sheets as of June 30, 2018, and December 31, 2017	7
		Consolidated Statement of Equity and Partners’ Capital for the six months ended June 30, 2018	8
		Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017	9
		Notes to Consolidated Financial Statements	10
		Note 1. Description of Business and Basis of Presentation	10
		Note 2. Revenue from Contracts with Customers	17
		Note 3. Acquisitions and Divestitures	19
		Note 4. Partnership Distributions	20
		Note 5. Equity and Partners’ Capital	21
		Note 6. Transactions with Affiliates	24
		Note 7. Property, Plant and Equipment	28
		Note 8. Equity Investments	29
		Note 9. Components of Working Capital	29
		Note 10. Debt and Interest Expense	30
		Note 11. Commitments and Contingencies	32
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
		Cautionary Note Regarding Forward-Looking Statements	33
		Executive Summary	35
		Acquisitions and Divestitures	37
		Equity Offerings	37
		Results of Operations	38
		Operating Results	38
		Key Performance Metrics	45
		Liquidity and Capital Resources	51
		Contractual Obligations	55
		Off-Balance Sheet Arrangements	55
		Recent Accounting Developments	55
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	56
	Item 4.	Controls and Procedures	56
PART II		OTHER INFORMATION
	Item 1.	Legal Proceedings	57
	Item 1A.	Risk Factors	57
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57
	Item 6.	Exhibits	58

2

COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners, LP” refer to Western Gas Partners, LP and its subsidiaries. As used in this Form 10-Q, the terms and definitions below have the following meanings:

Additional DBJV System Interest: Our additional 50% interest in the DBJV system acquired from a third party in March 2017.

Affiliates: Subsidiaries of Anadarko, excluding us, but including equity interests in Fort Union, White Cliffs, Rendezvous, the Mont Belvieu JV, TEP, TEG, FRP, Whitethorn and Cactus II.

Anadarko: Anadarko Petroleum Corporation and its subsidiaries, excluding us and our general partner.

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

Bbls/d: Barrels per day.

Board of Directors: The board of directors of our general partner.

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

Cactus II: Cactus II Pipeline LLC.

Chipeta: Chipeta Processing, LLC.

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 are used to bring natural gas 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.

DBJV: Delaware Basin JV Gathering LLC.

DBJV system: A gathering system and related facilities located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties in West Texas.

DBM: Delaware Basin Midstream, LLC.

DBM complex: The cryogenic processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico.

DBM water systems: Two produced water gathering and disposal systems in West Texas.

DJ Basin complex: The Platte Valley system, Wattenberg system and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014.

EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see Key Performance Metrics under Part I, Item 2 of this Form 10-Q.

Exchange Act: The Securities Exchange Act of 1934, as amended.

Fort Union: Fort Union Gas Gathering, LLC.

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.

FRP: Front Range Pipeline LLC.

3

GAAP: Generally accepted accounting principles in the United States.

General partner: Western Gas Holdings, LLC.

Hydraulic fracturing: The injection of fluids into the wellbore to create fractures in rock formations, stimulating the production of oil or gas.

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

IPO: Initial public offering.

LIBOR: London Interbank Offered Rate.

Marcellus Interest: Our 33.75% interest in the Larry’s Creek, Seely and Warrensville gas gathering systems and related facilities located in northern Pennsylvania.

MBbls/d: One thousand barrels per day.

MGR: Mountain Gas Resources, LLC.

MGR assets: The Red Desert complex and the Granger straddle plant.

MLP: Master limited partnership.

MMBtu: One million British thermal units.

MMcf: One million cubic feet.

MMcf/d: One million cubic feet per day.

Mont Belvieu JV: Enterprise EF78 LLC.

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.

Non-Operated Marcellus Interest: The 33.75% interest in the Liberty and Rome gas gathering systems and related facilities located in northern Pennsylvania that was transferred to a third party in March 2017 pursuant to the Property Exchange.

Produced water: Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.

Property Exchange: Our acquisition of the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, as further described in our Forms 8-K filed with the SEC on February 9, 2017, and March 23, 2017.

RCF: Our $1.5 billion senior unsecured revolving credit facility.

Red Desert complex: The Patrick Draw processing plant, the Red Desert processing plant, associated gathering lines, and related facilities.

Rendezvous: Rendezvous Gas Services, LLC.

Residue: The natural gas remaining after the unprocessed natural gas stream has been processed or treated.

SEC: U.S. Securities and Exchange Commission.

Springfield gas gathering system: A gas gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.

4

Springfield oil gathering system: An oil gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.

Springfield system: The Springfield gas gathering system and Springfield oil gathering system.

TEFR Interests: The interests in TEP, TEG and FRP.

TEG: Texas Express Gathering LLC.

TEP: Texas Express Pipeline LLC.

WGP: Western Gas Equity Partners, LP.

White Cliffs: White Cliffs Pipeline, LLC.

Whitethorn LLC: Whitethorn Pipeline Company LLC.

2018 Notes: Our 2.600% Senior Notes due 2018.

2021 Notes: Our 5.375% Senior Notes due 2021.

2022 Notes: Our 4.000% Senior Notes due 2022.

2025 Notes: Our 3.950% Senior Notes due 2025.

2026 Notes: Our 4.650% Senior Notes due 2026.

2028 Notes: Our 4.500% Senior Notes due 2028.

2044 Notes: Our 5.450% Senior Notes due 2044.

2048 Notes: Our 5.300% Senior Notes due 2048.

$500.0 million COP: The continuous offering program that may be undertaken pursuant to the registration statement filed with the SEC in July 2017 for the issuance of up to an aggregate of $500.0 million of our common units.

5

PART I.  FINANCIAL INFORMATION (UNAUDITED)

Item 1.Financial Statements

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except per-unit amounts	2018			2017			2018			2017
Revenues and other – affiliates
Service revenues – fee based	$	192,488		$	154,984		$	378,489		$	327,298
Service revenues – product based	285			—			527			—
Product sales	45,256			161,329			100,075			304,170
Total revenues and other – affiliates	238,029			316,313			479,091			631,468
Revenues and other – third parties
Service revenues – fee based	167,056			144,451			319,474			279,951
Service revenues – product based	21,820			—			44,171			—
Product sales	8,821			63,495			29,939			127,179
Other	223			1,191			442			3,045
Total revenues and other – third parties	197,920			209,137			394,026			410,175
Total revenues and other	435,949			525,450			873,117			1,041,643
Equity income, net – affiliates	39,218			21,728			59,642			41,189
Operating expenses
Cost of product (1)	68,149			203,277			145,948			392,636
Operation and maintenance (1)	100,628			76,148			188,907			149,908
General and administrative (1)	14,035			10,585			28,167			23,244
Property and other taxes	11,754			11,924			24,136			24,218
Depreciation and amortization	78,792			74,031			155,634			143,733
Impairments	127,243			3,178			127,391			167,920
Total operating expenses	400,601			379,143			670,183			901,659
Gain (loss) on divestiture and other, net(2)	170			15,458			286			134,945
Proceeds from business interruption insurance claims	—			24,115			—			29,882
Operating income (loss)	74,736			207,608			262,862			346,000
Interest income – affiliates	4,225			4,225			8,450			8,450
Interest expense (3)	(44,389		)	(35,746		)	(83,672		)	(71,250		)
Other income (expense), net	1,229			253			2,011			683
Income (loss) before income taxes	35,801			176,340			189,651			283,883
Income tax (benefit) expense	282			843			1,784			4,395
Net income (loss)	35,519			175,497			187,867			279,488
Net income attributable to noncontrolling interest	2,811			2,046			5,796			4,148
Net income (loss) attributable to Western Gas Partners, LP	$	32,708		$	173,451		$	182,071		$	275,340
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Gas Partners, LP	$	32,708		$	173,451		$	182,071		$	275,340
Series A Preferred units interest in net (income) loss	—			(14,199		)	—			(42,373		)
General partner interest in net (income) loss (4)	(84,176		)	(76,365		)	(167,615		)	(144,527		)
Common and Class C limited partners’ interest in net income (loss) (4)	(51,468		)	82,887			14,456			88,440
Net income (loss) per common unit – basic and diluted (5)	$	(0.32	)	$	0.49		$	0.06		$	0.53

⁽¹⁾  Cost of product includes product purchases from Anadarko (as defined in Note 1) of $12.6 million and $32.9 million for the three and six months ended June 30, 2018, respectively, and $21.6 million and $37.6 million for the three and six months ended June 30, 2017, respectively. Operation and maintenance includes charges from Anadarko of $23.4 million and $43.7 million for the three and six months ended June 30, 2018, respectively, and $18.5 million and $35.6 million for the three and six months ended June 30, 2017, respectively. General and administrative includes charges from Anadarko of $11.2 million and $22.8 million for the three and six months ended June 30, 2018, respectively, and $9.4 million and $18.9 million for the three and six months ended June 30, 2017, respectively. See Note 6.

⁽²⁾  Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

⁽³⁾  Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and six months ended June 30, 2017, respectively. See Note 10.

⁽⁴⁾  Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 5.

⁽⁵⁾  See Note 5 for the calculation of net income (loss) per common unit.

See accompanying Notes to Consolidated Financial Statements.

6

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

thousands except number of units	June 30,   2018		December 31,   2017
ASSETS
Current assets
Cash and cash equivalents	$	53,235	$	78,814
Accounts receivable, net (1)	167,175		160,432
Other current assets (2)	26,728		14,816
Total current assets	247,138		254,062
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	8,618,993		7,864,535
Less accumulated depreciation	2,405,419		2,133,644
Net property, plant and equipment	6,213,574		5,730,891
Goodwill	416,160		416,160
Other intangible assets	761,054		775,269
Equity investments	754,300		566,211
Other assets (3)	14,384		11,757
Total assets	$	8,666,610	$	8,014,350
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables (4)	$	331,447	$	349,801
Accrued ad valorem taxes	26,318		26,633
Accrued liabilities (5)	131,352		47,899
Total current liabilities	489,117		424,333
Long-term liabilities
Long-term debt	4,177,353		3,464,712
Deferred income taxes	8,753		7,409
Asset retirement obligations	151,412		143,394
Other liabilities (6)	138,493		3,491
Total long-term liabilities	4,476,011		3,619,006
Total liabilities	4,965,128		4,043,339
Equity and partners’ capital
Common units (152,609,285 and 152,602,105 units issued and outstanding at June 30, 2018, and December 31, 2017, respectively)	2,666,799		2,950,010
Class C units (13,778,265 and 13,243,883 units issued and outstanding at June 30, 2018, and December 31, 2017, respectively) (7)	781,057		780,040
General partner units (2,583,068 units issued and outstanding at June 30, 2018, and December 31, 2017)	191,564		179,232
Total partners’ capital	3,639,420		3,909,282
Noncontrolling interest	62,062		61,729
Total equity and partners’ capital	3,701,482		3,971,011
Total liabilities, equity and partners’ capital	$	8,666,610	$	8,014,350

⁽¹⁾  Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $16.1 million and $36.3 million as of June 30, 2018, and December 31, 2017, respectively.

⁽²⁾  Other current assets includes affiliate amounts of $9.3 million and zero as of June 30, 2018, and December 31, 2017, respectively.

⁽³⁾  Other assets includes affiliate amounts of $0.2 million and zero as of June 30, 2018, and December 31, 2017, respectively.

⁽⁴⁾  Accounts and imbalance payables includes affiliate amounts of zero and $0.3 million as of June 30, 2018, and December 31, 2017, respectively.

⁽⁵⁾  Accrued liabilities includes affiliate amounts of $2.3 million and $0.2 million as of June 30, 2018, and December 31, 2017, respectively.

⁽⁶⁾  Other liabilities includes affiliate amounts of $48.4 million and $0.7 million as of June 30, 2018, and December 31, 2017, respectively.

⁽⁷⁾  The Class C units will convert into common units on a one-for-one basis on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 5.

See accompanying Notes to Consolidated Financial Statements.

7

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(UNAUDITED)

	Partners’ Capital
thousands	Common Units			Class C Units			General Partner  Units			Noncontrolling Interest			Total
Balance at December 31, 2017	$	2,950,010		$	780,040		$	179,232		$	61,729		$	3,971,011
Cumulative effect of accounting change (1)	(41,108		)	(3,533		)	(696		)	958			(44,379		)
Net income (loss)	11,528			2,928			167,615			5,796			187,867
Above-market component of swap agreements with Anadarko (2)	28,121			—			—			—			28,121
Amortization of beneficial conversion feature of Class C units	(1,622		)	1,622			—			—			—
Distributions to noncontrolling interest owner	—			—			—			(6,421		)	(6,421		)
Distributions to unitholders	(283,077		)	—			(154,642		)	—			(437,719		)
Contributions of equity-based compensation from Anadarko	2,737			—			55			—			2,792
Other	210			—			—			—			210
Balance at June 30, 2018	$	2,666,799		$	781,057		$	191,564		$	62,062		$	3,701,482

⁽¹⁾  See Note 1.

⁽²⁾  See Note 6.

See accompanying Notes to Consolidated Financial Statements.

8

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended   June 30,
thousands	2018			2017
Cash flows from operating activities
Net income (loss)	$	187,867		$	279,488
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	155,634			143,733
Impairments	127,391			167,920
Non-cash equity-based compensation expense	3,017			2,393
Deferred income taxes	1,523			3,767
Accretion and amortization of long-term obligations, net	2,626			2,139
Equity income, net – affiliates	(59,642		)	(41,189		)
Distributions from equity investment earnings – affiliates	48,396			42,202
(Gain) loss on divestiture and other, net (1)	(286		)	(134,945		)
Lower of cost or market inventory adjustments	151			140
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(7,009		)	9,363
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net	40,573			(41,975		)
Change in other items, net	14,670			116
Net cash provided by operating activities	514,911			433,152
Cash flows from investing activities
Capital expenditures	(650,096		)	(260,480		)
Contributions in aid of construction costs from affiliates	—			1,343
Acquisitions from affiliates	—			(3,910		)
Acquisitions from third parties	(161,858		)	(155,287		)
Investments in equity affiliates	(27,490		)	(287		)
Distributions from equity investments in excess of cumulative earnings – affiliates	12,505			9,221
Proceeds from the sale of assets to third parties	286			23,292
Proceeds from property insurance claims	—			22,977
Net cash used in investing activities	(826,653		)	(363,131		)
Cash flows from financing activities
Borrowings, net of debt issuance costs	1,337,539			159,989
Repayments of debt	(630,000		)	—
Settlement of the Deferred purchase price obligation – Anadarko (2)	—			(37,346		)
Increase (decrease) in outstanding checks	(5,357		)	(2,763		)
Proceeds from the issuance of common units, net of offering expenses	—			(183		)
Distributions to unitholders (3)	(437,719		)	(381,771		)
Distributions to noncontrolling interest owner	(6,421		)	(6,375		)
Net contributions from (distributions to) Anadarko	—			30
Above-market component of swap agreements with Anadarko (3)	28,121			28,670
Net cash provided by (used in) financing activities	286,163			(239,749		)
Net increase (decrease) in cash and cash equivalents	(25,579		)	(169,728		)
Cash and cash equivalents at beginning of period	78,814			357,925
Cash and cash equivalents at end of period	$	53,235		$	188,197
Supplemental disclosures
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko	$	—		$	(4,094	)
Net distributions to (contributions from) Anadarko of other assets	—			(376		)
Interest paid, net of capitalized interest	62,924			68,396
Taxes paid (reimbursements received)	(87		)	189
Accrued capital expenditures	182,212			100,038
Fair value of properties and equipment from non-cash third party transactions (2)	—			551,453

⁽¹⁾  Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

⁽²⁾  See Note 3.

⁽³⁾  See Note 6.

See accompanying Notes to Consolidated Financial Statements.

9

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 (“MLP”) formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop and operate midstream 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”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP 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. WGP has no independent operations or material assets other than owning the partnership interests in the Partnership (see Holdings of Partnership equity in Note 5). 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 subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including 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”), Front Range Pipeline LLC (“FRP”), Whitethorn Pipeline Company LLC (“Whitethorn LLC”) and Cactus II Pipeline LLC (“Cactus II”). See Note 3. The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “MGR assets” refers to the Red Desert complex and the Granger straddle plant.

The Partnership is engaged in the business of gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, natural gas liquids (“NGLs”) and crude oil; and gathering and disposing of produced water. In addition, in its capacity as a processor of natural gas, the Partnership also buys and sells natural gas, NGLs and condensate on behalf of itself and as agent for its customers under certain of its contracts. The Partnership provides these midstream services for Anadarko, as well as for third-party producers and customers. As of June 30, 2018, the Partnership’s assets and investments consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems (1)	12	3	3	2
Treating facilities	19	3	—	3
Natural gas processing plants/trains	20	4	—	2
NGL pipelines	2	—	—	3
Natural gas pipelines	5	—	—	—
Oil pipelines	—	1	—	2

⁽¹⁾  Includes the DBM water systems.

These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. Mentone Train I, a processing train at the DBM complex, is expected to commence operations at the end of the third quarter of 2018.

10

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Basis of presentation. The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements for entities not wholly owned:

	Percentage Interest
Equity investments (1)
Fort Union	14.81	%
White Cliffs	10	%
Rendezvous	22	%
Mont Belvieu JV	25	%
TEP	20	%
TEG	20	%
FRP	33.33	%
Whitethorn	20	%
Cactus II	15	%
Proportionate consolidation (2)
Marcellus Interest systems	33.75	%
Newcastle system	50	%
Springfield system	50.1	%
Full consolidation
Chipeta (3)	75	%

⁽¹⁾  Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.

⁽²⁾  The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.

⁽³⁾  The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

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.

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 2017 Form 10-K, as filed with the SEC on February 16, 2018. Management believes that the disclosures made are adequate to make the information not misleading.

11

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Presentation of Partnership assets. The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by the Partnership as of June 30, 2018 (see Note 8). Because Anadarko controls the Partnership through its control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko are 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 Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.

Use of estimates.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. 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.

Shutdown of gathering systems. In May 2018, after assessing a number of factors, with safety and protection of the environment as the primary focus, the Partnership decided to take the Kitty Draw gathering system in Wyoming (part of the Hilight system) and the Third Creek gathering system in Colorado (part of the DJ Basin complex) permanently out of service. Results for the three and six months ended June 30, 2018, reflect (i) an accrual of $10.9 million in anticipated costs associated with the shutdown of the systems, recorded as a reduction in affiliate Product sales in the consolidated statements of operations and (ii) impairment expense of $127.2 million associated with reducing the net book value of the gathering systems and additional asset retirement obligation.

Insurance recoveries. In December 2015, there was an initial fire and secondary explosion at the processing facility within the Delaware Basin Midstream, LLC (“DBM”) complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. During the six months ended June 30, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to a change in the Partnership’s estimate of the amount that would be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, the Partnership reached a settlement with insurers and final proceeds were received. During the six months ended June 30, 2017, the Partnership received $52.9 million in cash proceeds from insurers, including $29.9 million in proceeds from business interruption insurance claims and $23.0 million in proceeds from property insurance claims.

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Partnership adopted this ASU using a retrospective approach on January 1, 2018, and the adoption did not impact the consolidated financial statements.

12

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Revenue from contracts with customers (Topic 606). The Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Topic 606”) on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The cumulative effect adjustment that was recognized in the opening balance of equity and partners’ capital was a decrease of $44.4 million. The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition (Topic 605) (“Topic 605”).

Effective January 1, 2018, the Partnership changed its accounting policy for revenue recognition as detailed below:

• Fee-based gathering / processing. Under Topic 605, fee revenues were recognized based on the rate in effect for the month of service, even when certain fees were charged on an upfront or limited-term basis. In addition, deficiency fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, revenues continue to be recognized based on the rate in effect when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Under Topic 606, the Partnership recognizes revenue associated with upfront or limited-term fees over the expected period of customer benefit, which is generally the life of the related properties. In addition, deficiency fees are estimated and recognized during the performance period as the services are performed for the customer’s delivered volumes. Under Topic 606, differences between Service revenues – fee based recognized and amounts billed to customers are recognized as contract assets or contract liabilities, as appropriate. This results in a change in the timing of revenue and changes to net income as a result of the revenue contract’s consideration provisions.

• Cost of service rate adjustments. Under Topic 605, revenue was recognized based on the amounts billed to customers each period. Under Topic 606, fixed minimum volume commitment demand fees and variable fees that are also billed on these minimum volumes are recognized as Service revenues – fee based on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and, as a result, a cumulative catch-up revenue adjustment related to the services already provided under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate. Fees received on volumes in excess of the minimum volumes are recognized as Service revenues – fee based as service is provided to the customer based on the billing rate in effect for the performance period. This revenue recognition timing does not affect billings to customers, and differences between amounts billed and revenue recognized are recorded as contract assets or liabilities, as appropriate.

• Aid in construction. Under Topic 605, aid in construction reimbursements were reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Under Topic 606, reimbursement of capital costs received from customers is reflected as a contract liability (deferred revenue) upon receipt. The contract liability is amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

• Percent-of-proceeds gathering / processing. Under Topic 605, the Partnership recognized cost of product expense when the product was purchased from a producer to whom it provides services, and the Partnership recognized revenue when the product was sold to Anadarko or a third party. Under Topic 606, in some instances, where all or a percentage of the proceeds from the sale must be returned to the producer, the net margin from the purchase and sale transactions is presented net within Service revenues – product based because the Partnership is acting as the producer’s agent in the product sale.

13

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

• Noncash consideration - keep-whole and percent-of-product agreements. Under Topic 605, the Partnership recognized revenues only upon the sale of the related products. Under Topic 606, the Partnership recognizes Service revenues – product based for the products received as noncash consideration in exchange for the services provided, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas cost. Under Topic 606, revenue from product sales is recognized, along with cost of product expense related to the sale, when the product is sold to Anadarko or a third party.

• Wellhead purchase / sale incorporated into gathering / processing. Under Topic 605, the natural gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenues. Under Topic 606, the fees charged to the producer under this contract type are recognized as adjustments to the amount recognized in cost of product expense instead of revenues when such fees relate to services performed after control of the product transfers to the Partnership.

The following tables summarize the impact of adopting Topic 606 on the impacted line items within the consolidated statements of operations and the consolidated balance sheet. The differences between revenue as reported following Topic 606 and revenue as it would have been reported under Topic 605 are due to the changes described above.

	Three Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	359,544	$	358,209	$	1,335
Service revenues – product based	22,105		—		22,105
Product sales	54,077		319,233		(265,156		)
Expenses
Cost of product	68,149		312,329		(244,180		)
Operation and maintenance	100,628		100,632		(4		)
Depreciation and amortization	78,792		78,125		667
Impairments	127,243		127,198		45
Income tax (benefit) expense	282		272		10
Net income attributable to noncontrolling interest	2,811		2,054		757
Net income (loss) attributable to Western Gas Partners, LP	32,708		31,719		989

14

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	Six Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	697,963	$	700,547	$	(2,584	)
Service revenues – product based	44,698		—		44,698
Product sales	130,014		611,524		(481,510		)
Expenses
Cost of product	145,948		587,295		(441,347		)
Operation and maintenance	188,907		188,771		136
Depreciation and amortization	155,634		154,278		1,356
Impairments	127,391		127,346		45
Income tax (benefit) expense	1,784		1,781		3
Net income attributable to noncontrolling interest	5,796		4,552		1,244
Net income (loss) attributable to Western Gas Partners, LP	182,071		182,904		(833		)

	June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Assets
Other current assets	$	26,728	$	17,388	$	9,340
Net property, plant and equipment	6,213,574		6,117,733		95,841
Other assets	14,384		14,138		246
Liabilities
Accrued liabilities	131,352		124,913		6,439
Deferred income taxes	8,753		8,930		(177		)
Other liabilities	138,493		2,810		135,683
Equity and partners’ capital
Total equity and partners’ capital	3,701,482		3,738,000		(36,518		)

New accounting standards issued but not yet adopted.ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Partnership plans to make certain elections allowing the Partnership not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements and not to recognize ROU assets or lease liabilities for short-term leases. The Partnership continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU, which is expected to primarily impact other assets and other liabilities. To facilitate compliance with this ASU, the Partnership is implementing new accounting software and continuing to evaluate its systems, processes and internal controls during 2018. The Partnership will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Partnership does not expect to adjust comparative period financial statements.

15

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Revenue and cost of product. Upon adoption of the new revenue recognition standard on January 1, 2018 (discussed in Recently adopted accounting standards), the Partnership changed its accounting policy for revenue recognition as described below.

The Partnershipprovides gathering, processing, treating, transportation and disposal services pursuant to a variety of contracts. Under these arrangements, the Partnership receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in Service revenues and Product sales in the consolidated statements of operations. Payment is generally received from the customer in the month following the service or delivery of the product. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Service revenues – fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation and disposal of natural gas, NGLs, condensate, crude oil and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed upon completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties.

The Partnership also receives Service revenues – fee based from contracts that have minimum volume commitment demand fees and fees that require periodic rate redeterminations based upon the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate.

Service revenues – product based includes service revenues from percent-of-proceeds gathering and processing contracts that are recognized net of the cost of product for purchases from the Partnership’s customers since it is acting as the agent in the product sale. Keep-whole and percent-of-product agreements result in Service revenues – product based being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. Noncash consideration for these services is valued at the time the services are provided. Revenue from product sales is also recognized, along with the cost of product expense related to the sale, when the product received as noncash consideration is sold to either Anadarko or a third party.

The Partnership also purchases natural gas volumes from producers at the wellhead or from a production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. When the fees relate to services performed after control of the product has transferred to the Partnership, the fees are treated as a reduction of the purchase cost. Revenue from product sales is recognized, along with cost of product expense related to the sale, when the purchased product is sold to either Anadarko or a third party.

The Partnership receives aid in construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs, etc.) under certain service contracts. Aid in construction reimbursements are reflected as a contract liability upon receipt and amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

16

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes the Partnership’s revenue from contracts with customers:

thousands	Three Months Ended   June 30, 2018			Six Months Ended   June 30, 2018
Revenue from customers
Service revenues – fee based	$	359,544		$	697,963
Service revenues – product based	22,105			44,698
Product sales	55,449			132,629
Total revenue from customers	437,098			875,290
Revenue from other than customers
Net gains (losses) on commodity price swap agreements	(1,372		)	(2,615		)
Other	223			442
Total revenues and other	$	435,949		$	873,117

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $267.1 million and $244.4 million as of June 30, 2018, and December 31, 2017, respectively.

Contract assets primarily relate to accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed. The following table summarizes the current period activity related to contract assets from contracts with customers:

thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	5,129
Amounts transferred to Accounts receivable, net from contract assets recognized in the adoption effect (1)	(2,677		)
Additional estimated revenues recognized (2)	7,134
Balance at June 30, 2018	$	9,586
Contract assets at June 30, 2018
Other current assets	$	9,340
Other assets	246
Total contract assets from contracts with customers	$	9,586

⁽¹⁾  Includes $(0.2) million for the three months ended June 30, 2018.

⁽²⁾  Includes $3.7 million for the three months ended June 30, 2018.

17

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)

Contract liabilities primarily relate to (i) fees that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of customer benefit, (ii) fixed and variable fees under cost of service contracts that are received from customers for which revenue recognition is deferred and (iii) aid in construction payments received from customers that must be recognized over the expected period of customer benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:

thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	120,717
Cash received or receivable, excluding revenues recognized during the period (1)	41,076
Revenues recognized during the period that were included in the adoption effect (2)	(2,009		)
Balance at June 30, 2018	$	159,784
Contract liabilities at June 30, 2018
Accrued liabilities	$	24,101
Other liabilities	135,683
Total contract liabilities from contracts with customers	$	159,784

⁽¹⁾  Includes $12.5 million for the three months ended June 30, 2018.

⁽²⁾  Includes $(1.0) million for the three months ended June 30, 2018.

Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that are unsatisfied (or partially unsatisfied) as of June 30, 2018, are reflected in the following table. The Partnership applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a small portion of expected future consolidated revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and in some cases variable commodity prices for those volumes.

thousands
Remainder of 2018	$	220,037
2019	492,806
2020	542,214
2021	527,151
2022	527,103
Thereafter	2,168,028
Total	$	4,477,339

18

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

3. ACQUISITIONS AND DIVESTITURES

Whitethorn LLC acquisition. In June 2018, the Partnership acquired a 20% interest in Whitethorn LLC, which owns the crude oil and condensate pipeline that originates in Midland, Texas and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with its investment in Whitethorn, the Partnership will share proportionally in the commercial activities. The Partnership acquired its 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 8.

Cactus II acquisition. In June 2018, the Partnership acquired a 15% interest in Cactus II, which will own a crude oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline is under construction and expected to become operational in the fourth quarter of 2019. The Partnership acquired its 15% interest from a third party via an $11.3 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 8.

Property exchange. On March 17, 2017, the Partnership acquired an additional 50% interest in the Delaware Basin JV Gathering LLC (“DBJV”) system (the “Additional DBJV System Interest”) from a third party in exchange for (a) the Partnership’s 33.75% non-operated interest in two natural gas gathering systems located in northern Pennsylvania (the “Non-Operated Marcellus Interest”), commonly referred to as the Liberty and Rome systems, and (b) $155.0 million of cash consideration (collectively, the “Property Exchange”). The Partnership previously held a 50% interest in, and operated, the DBJV system.

The Property Exchange was reflected as a nonmonetary transaction whereby the acquired Additional DBJV System Interest was recorded at the fair value of the divested Non-Operated Marcellus Interest plus the $155.0 million of cash consideration. The Property Exchange resulted in a net gain of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributable to the Property Exchange were included in the consolidated statements of operations beginning on the acquisition date in the first quarter of 2017.

DBJV acquisition - Deferred purchase price obligation - Anadarko.Prior to the Partnership’s agreement with Anadarko to settle its deferred purchase price obligation early, the consideration that would have been paid by the Partnership for the March 2015 acquisition of DBJV from Anadarko consisted of a cash payment to Anadarko due on March 31, 2020. In May 2017, the Partnership reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.

Helper and Clawson systems divestiture. During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of $16.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

19

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors of the Partnership’s general partner (the “Board of Directors”) declared the following cash distributions to the Partnership’s common and general partner unitholders for the periods presented:

thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
2017
March 31	$	0.875	$	188,753	May 2017
June 30	0.890		207,491		August 2017
September 30	0.905		212,038		November 2017
December 31	0.920		216,586		February 2018
2018
March 31	$	0.935	$	221,133	May 2018
June 30 (1)	0.950		225,691		August 2018

⁽¹⁾  The Board of Directors declared a cash distribution to the Partnership’s unitholders for the second quarter of 2018 of $0.950 per unit, or $225.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution is payable on August 13, 2018, to unitholders of record at the close of business on August 1, 2018.

Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments or other agreements; or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. Working capital borrowings may only be those that, at the time of such borrowings, were intended to be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.

Class C unit distributions. The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on March 1, 2020 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted into common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a 6% discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value. See Note 5 for further discussion of the Class C units.

20

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)

Series A Preferred unit distributions. As further described in Note 5, the Partnership issued Series A Preferred units representing limited partner interests in the Partnership to private investors in 2016. The Series A Preferred unitholders received quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis. Such converted common units were entitled to distributions made to common unitholders with respect to the quarter during which the applicable conversion occurred and did not include a prorated Series A Preferred unit distribution. For the quarter ended March 31, 2017, the Series A Preferred unitholders received an aggregate cash distribution of $7.5 million (paid in May 2017).

General partner interest and incentive distribution rights. As of June 30, 2018, the general partner was entitled to 1.5% of all quarterly distributions that the Partnership makes prior to its liquidation and, as the holder of the incentive distribution rights (“IDRs”), was entitled to incentive distributions at the maximum distribution sharing percentage of 48.0% for all periods presented, after the minimum quarterly distribution and the target distribution levels had been achieved. The maximum distribution sharing percentage of 49.5% does not include any distributions that the general partner may receive on common units that it may acquire.

5. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. In July 2017, the Partnership filed a registration statement with the SEC for the issuance of up to an aggregate of $500.0 million of common units pursuant to a new continuous offering program that has not yet been initiated.

Class C units. In November 2014, the Partnership issued 10,913,853 Class C units to APC Midstream Holdings, LLC (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund the acquisition of DBM.

When issued, the Class C units were scheduled to convert into common units on a one-for-one basis on December 31, 2017. In February 2017, Anadarko elected to extend the conversion date of the Class C units to March 1, 2020. The Partnership can elect to convert the Class C units earlier or Anadarko can extend the conversion date again.

The Class C units were issued at a discount to the then-current market price of the common units into which they are convertible. This discount, totaling $34.8 million, represents a beneficial conversion feature, and at issuance, was reflected as an increase in common unitholders’ capital and a decrease in Class C unitholder capital to reflect the fair value of the Class C units at issuance. The beneficial conversion feature is considered a non-cash distribution that is recognized from the date of issuance through the date of conversion, resulting in an increase in Class C unitholder capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature is amortized assuming the extended conversion date of March 1, 2020, using the effective yield method. The impact of the beneficial conversion feature amortization is included in the calculation of earnings per unit.

Series A Preferred units. In 2016, the Partnership issued 21,922,831 Series A Preferred units to private investors. The Series A Preferred units were issued at a discount to the then-current market price of the common units into which they were convertible, representing a beneficial conversion feature at issuance. The impact of the beneficial conversion feature amortization was included in the calculation of earnings per unit. For the six months ended June 30, 2017, the amortization for the beneficial conversion feature of the Series A Preferred units was $62.3 million.

Pursuant to an agreement between the Partnership and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units converted into common units on a one-for-one basis on May 2, 2017.

21

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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

The following table summarizes the Partnership’s units issued during the six months ended June 30, 2018:

	Common Units	Class C Units	General Partner Units	Total
Balance at December 31, 2017	152,602,105	13,243,883	2,583,068	168,429,056
PIK Class C units	—	534,382	—	534,382
Long-Term Incentive Plan award vestings	7,180	—	—	7,180
Balance at June 30, 2018	152,609,285	13,778,265	2,583,068	168,970,618

Holdings of Partnership equity. As of June 30, 2018, WGP held50,132,046common units, representing a29.7%limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held2,583,068general partner units, representing a1.5%general partner interest in the Partnership, and100%of the IDRs. As ofJune 30, 2018, other subsidiaries of Anadarko collectively held2,011,380common units and13,778,265Class C units, representing an aggregate9.3%limited partner interest in the Partnership. As ofJune 30, 2018, the public held100,465,859common units, representing the remaining59.5%limited partner interest in the Partnership.

Net income (loss) per common unit. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the unitholders for purposes of calculating net income (loss) per common unit. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of acquisition of the Partnership assets is allocated as follows:

General partner. The general partner’s allocation is equal to cash distributions plus its portion of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner consistent with actual cash distributions and capital account allocations, including incentive distributions. 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 in accordance with its weighted-average ownership percentage during each period.

Series A Preferred unitholders. The Series A Preferred units were not considered a participating security as they only had distribution rights up to the specified per-unit quarterly distribution and had no rights to the Partnership’s undistributed earnings and losses. As such, the Series A Preferred unitholders’ allocation was equal to their cash distribution plus the amortization of the Series A Preferred units beneficial conversion feature (see Series A Preferred units above).

Common and Class C unitholders. The Class C units are considered a participating security because they participate in distributions with common units according to a predetermined formula (see Note 4). The common and Class C unitholders’ allocation is equal to their cash distributions plus their respective portions of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the common and Class C unitholders consistent with actual cash distributions and capital account allocations. Undistributed earnings or undistributed losses are then allocated to the common and Class C unitholders in accordance with their respective weighted-average ownership percentages during each period. The common unitholder allocation also includes the impact of the amortization of the Series A Preferred units and Class C units beneficial conversion features. The Class C unitholder allocation is similarly impacted by the amortization of the Class C units beneficial conversion feature (see Class C units above).

22

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Calculation of net income (loss) per unit. Basic net income (loss) per common unit is calculated by dividing the net income (loss) attributable to common unitholders 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. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest in net income (loss) assuming, prior to the actual conversion, conversion of the Series A Preferred units into common units, and (ii) the net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming, prior to the actual conversion, conversion of the Series A Preferred units.

The following table illustrates the Partnership’s calculation of net income (loss) per common unit:

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except per-unit amounts	2018			2017			2018			2017
Net income (loss) attributable to Western Gas Partners, LP	$	32,708		$	173,451		$	182,071		$	275,340
Series A Preferred units interest in net (income) loss (1)	—			(14,199		)	—			(42,373		)
General partner interest in net (income) loss	(84,176		)	(76,365		)	(167,615		)	(144,527		)
Common and Class C limited partners’ interest in net income (loss)	$	(51,468	)	$	82,887		$	14,456		$	88,440
Net income (loss) allocable to common units (1)	$	(48,417	)	$	73,383		$	9,906		$	75,097
Net income (loss) allocable to Class C units (1)	(3,051		)	9,504			4,550			13,343
Common and Class C limited partners’ interest in net income (loss)	$	(51,468	)	$	82,887		$	14,456		$	88,440
Net income (loss) per unit
Common units – basic and diluted (2)	$	(0.32	)	$	0.49		$	0.06		$	0.53
Weighted-average units outstanding
Common units – basic and diluted	152,604			148,864			152,603			141,696
Excluded due to anti-dilutive effect:
Class C units (2)	13,649			12,650			13,516			12,552
Series A Preferred units assuming conversion to common units (2)	—			3,734			—			10,901

⁽¹⁾  Adjusted to reflect amortization of the beneficial conversion features.

⁽²⁾  The impact of Class C units would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the three and six months ended June 30, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

23

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. 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 and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operation 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.

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. 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. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

Note receivable - 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 $304.7 million and $325.2 million at June 30, 2018, and December 31, 2017, 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 a majority of the commodity price risk inherent in its percent-of-proceeds, percent-of-product and keep-whole contracts. 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. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. The Partnership’s net gains (losses) on commodity price swap agreements were $(1.4) million and $(2.6) million for the three and six months ended June 30, 2018, respectively, and $1.0 million and $0.5 million for the three and six months ended June 30, 2017, respectively, and are reported in the consolidated statements of operations as affiliate Product sales in 2018 and as affiliate Product sales and Cost of product expense in 2017 (see Note 1).

24

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Revenues or costs attributable to volumes sold and purchased during 2017 and 2018 for the DJ Basin complex and MGR assets are recognized in the consolidated statements of operations at the applicable market price in the tables below. The Partnership also records a capital contribution from Anadarko in the Partnership’s consolidated statement of equity and partners’ capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price in the tables below, minus (ii) the amount by which the swap price for product purchases exceeds the market price in the tables below. For the six months ended June 30, 2018, the capital contribution from Anadarko was $28.1 million. The tables below summarize the swap prices compared to the forward market prices:

	DJ Basin Complex
per barrel except natural gas	2017 - 2018 Swap Prices		2017 Market Prices (1)		2018 Market Prices (1)
Ethane	$	18.41	$	5.09	$	5.41
Propane	47.08		18.85		28.72
Isobutane	62.09		26.83		32.92
Normal butane	54.62		26.20		32.71
Natural gasoline	72.88		41.84		48.04
Condensate	76.47		45.40		49.36
Natural gas (per MMBtu)	5.96		3.05		2.21

	MGR Assets
per barrel except natural gas	2017 - 2018 Swap Prices		2017 Market Prices (1)		2018 Market Prices (1)
Ethane	$	23.11	$	4.08	$	2.52
Propane	52.90		19.24		25.83
Isobutane	73.89		25.79		30.03
Normal butane	64.93		25.16		29.82
Natural gasoline	81.68		45.01		47.25
Condensate	81.68		53.55		56.76
Natural gas (per MMBtu)	4.87		3.05		2.21

⁽¹⁾  Represents the New York Mercantile Exchange forward strip price as of December 1, 2016, and December 20, 2017, for the 2017 Market Prices and 2018 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

Gathering and processing agreements. The Partnership has significant gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The Partnership’s natural gas gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 35% for both the three and six months ended June 30, 2018, and 38% and 34% for the three and six months ended June 30, 2017, respectively. The Partnership’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 35% for both the three and six months ended June 30, 2018, and 39% and 44% for the three and six months ended June 30, 2017, respectively. The Partnership’s crude oil, NGL and produced water gathering, treating, transportation and disposal throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 72% and 68% for the three and six months ended June 30, 2018, respectively, and 41% and 47% for the three and six months ended June 30, 2017, respectively.

25

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Commodity purchase and sale agreements. The Partnership sells a significant amount of its natural gas, condensate and NGLs to Anadarko Energy Services Company (“AESC”), Anadarko’s marketing affiliate. In addition, the Partnership purchases natural gas, condensate and NGLs from AESC pursuant to purchase agreements. The Partnership’s purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal.

WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2017 Long-Term Incentive Plan, effective October 17, 2017. Awards granted prior to October 17, 2017, were awarded under the Western Gas Partners, LP 2008 Long-Term Incentive Plan. These awards are primarily granted to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. 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 June 30, 2018 and 2017, and $0.2 million for each of the six months ended June 30, 2018 and 2017.

Anadarko Incentive Plan. General and administrative expenses included $1.7 million and $3.8 million for the three and six months ended June 30, 2018, respectively, and $0.9 million and $2.1 million for the three and six months ended June 30, 2017, respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (“Anadarko Incentive Plan”). Of this amount, $2.8 million is reflected as contributions to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the six months ended June 30, 2018.

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

	Six Months Ended June 30,
thousands	2018			2017
Cash consideration	$	—		$	3,910
Payable to affiliate	254			—
Net carrying value	(254		)	(4,286		)
Partners’ capital adjustment	$	—		$	(376	)

Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. For periods prior to January 1, 2018, the cash receipts resulting from such reimbursements were presented as “Contributions in aid of construction costs from affiliates” within the investing section of the consolidated statements of cash flows. As discussed in Recently adopted accounting standards in Note 1,upon adoption of Topic 606, affiliate reimbursements of capital costs are reflected as contract liabilities upon receipt, amortized to Service revenues – fee based over the expected period of customer benefit, and presented within the operating section of the consolidated statements of cash flows.

26

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes material affiliate transactions:

	Three Months Ended   June 30,					Six Months Ended   June 30,
thousands	2018		2017			2018		2017
Revenues and other (1)	$	238,029	$	316,313		$	479,091	$	631,468
Equity income, net– affiliates (1)	39,218		21,728			59,642		41,189
Cost of product (1)	12,609		21,607			32,853		37,595
Operation and maintenance (2)	23,437		18,462			43,685		35,551
General and administrative (3)	11,178		9,365			22,792		18,900
Operating expenses	47,224		49,434			99,330		92,046
Interest income (4)	4,225		4,225			8,450		8,450
Interest expense (5)	—		—			—		71
Settlement of the Deferred purchase price obligation – Anadarko (6)	—		(37,346		)	—		(37,346		)
Distributions to unitholders (7)	127,204		110,449			251,368		213,572
Above-market component of swap agreements with Anadarko	13,839		16,373			28,121		28,670

⁽¹⁾  Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, 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 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.

⁽³⁾  Represents general and administrative expense incurred on and subsequent to the date of the acquisition of 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 Anadarko Incentive Plan within this Note 6).

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

⁽⁵⁾  Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3andNote 10).

⁽⁶⁾  Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).

⁽⁷⁾  Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

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 operations.

27

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7. PROPERTY, PLANT AND EQUIPMENT

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

thousands	Estimated Useful Life	June 30,   2018		December 31,   2017
Land	n/a	$	4,653	$	4,450
Gathering systems and processing complexes	3 to 47 years	7,565,998		7,113,114
Pipelines and equipment	15 to 45 years	137,769		137,644
Assets under construction	n/a	879,095		579,501
Other	3 to 40 years	31,478		29,826
Total property, plant and equipment		8,618,993		7,864,535
Less accumulated depreciation		2,405,419		2,133,644
Net property, plant and equipment		$	6,213,574	$	5,730,891

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.

Impairments.During the six months ended June 30, 2018, the Partnership recognized impairments of $127.4 million, including impairments of $120.8 million at the Third Creek gathering system and $6.4 million at the Kitty Draw gathering system. These assets were impaired to their estimated salvage values of $1.0 million and zero, respectively, using the market approach and Level 3 fair value inputs, due to the shutdown of the systems. See Note 1 for further information.

During the year ended December 31, 2017, the Partnership recognized impairments of $178.4 million, including an impairment of $158.8 million at the Granger complex, which was impaired to its estimated fair value of $48.5 million using the income approach and Level 3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. The remaining $19.6 million of impairments was primarily related to (i) an $8.2 million impairment due to the cancellation of a plant project at the Hilight system, (ii) a $3.7 million impairment at the Granger straddle plant, which was impaired to its estimated salvage value of $0.6 million using the income approach and Level 3 fair value inputs, (iii) a $3.1 million impairment of the Fort Union equity investment, (iv) a $2.0 million impairment of an idle facility in northeast Wyoming, which was impaired to its estimated salvage value of $0.4 million using the market approach and Level 3 fair value inputs, and (v) the cancellation of a pipeline project in West Texas.

28

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. EQUITY INVESTMENTS

The following table presents the activity in the Partnership’s equity investments for the six months ended June 30, 2018:

thousands	Fort Union			White Cliffs			Rendezvous			Mont Belvieu JV			TEFR Interests			Whitethorn		Cactus II		Total
Balance at December 31, 2017	$	7,030		$	44,945		$	42,528		$	110,299		$	361,409		$	—	$	—	$	566,211
Acquisitions	—			—			—			—			—			150,563		11,295		161,858
Investment earnings (loss), net of amortization	(444		)	5,898			439			15,200			33,037			5,512		—		59,642
Contributions	—			1,278			—			—			—			7,069		19,127		27,474
Capitalized interest	—			—			—			—			—			—		16		16
Distributions	(194		)	(5,607		)	(1,410		)	(15,219		)	(25,966		)	—		—		(48,396		)
Distributions in excess of cumulative earnings (1)	(2,658		)	(1,958		)	(1,784		)	(2,131		)	(3,974		)	—		—		(12,505		)
Balance at June 30, 2018	$	3,734		$	44,556		$	39,773		$	108,149		$	364,506		$	163,144	$	30,438	$	754,300

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

9. COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:

thousands	June 30, 2018		December 31, 2017
Trade receivables, net	$	167,116	$	160,387
Other receivables, net	59		45
Total accounts receivable, net	$	167,175	$	160,432

A summary of other current assets is as follows:

thousands	June 30, 2018		December 31, 2017
Natural gas liquids inventory	$	9,421	$	10,788
Imbalance receivables	7,703		1,640
Prepaid insurance	264		2,388
Contract assets	9,340		—
Total other current assets	$	26,728	$	14,816

A summary of accrued liabilities is as follows:

thousands	June 30, 2018		December 31, 2017
Accrued interest expense	$	58,753	$	40,632
Short-term asset retirement obligations (1)	42,312		2,304
Short-term remediation and reclamation obligations	833		833
Income taxes payable	2,756		2,495
Contract liabilities	24,101		—
Other	2,597		1,635
Total accrued liabilities	$	131,352	$	47,899

⁽¹⁾  As of June 30, 2018, includes $40.2 million of short-term liabilities incurred related to the shutdowns at the Third Creek and Kitty Draw gathering systems. See Note 1 for further information.

29

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

10. DEBT AND INTEREST EXPENSE

At June 30, 2018, the Partnership’s debt consisted of 2.600% Senior Notes due 2018 (the “2018 Notes”), 5.375% Senior Notes due 2021 (the “2021 Notes”), 4.000% Senior Notes due 2022 (the “2022 Notes”), 3.950% Senior Notes due 2025 (the “2025 Notes”), 4.650% Senior Notes due 2026 (the “2026 Notes”), 4.500% Senior Notes due 2028 (the “2028 Notes”), 5.450% Senior Notes due 2044 (the “2044 Notes”) and 5.300% Senior Notes due 2048 (the “2048 Notes”).

The following table presents the Partnership’s outstanding debt:

	June 30, 2018						December 31, 2017
thousands	Principal		Carrying Value		Fair Value(1)		Principal		Carrying Value		Fair Value (1)
2018 Notes	$	350,000	$	349,937	$	349,832	$	350,000	$	349,684	$	350,631
2021 Notes	500,000		496,380		520,037		500,000		495,815		530,647
2022 Notes	670,000		668,962		665,356		670,000		668,849		684,043
2025 Notes	500,000		492,356		475,739		500,000		491,885		500,885
2026 Notes	500,000		495,475		492,415		500,000		495,245		520,144
2028 Notes	400,000		394,399		386,234		—		—		—
2044 Notes	600,000		593,290		569,855		600,000		593,234		637,827
2048 Notes	700,000		686,554		651,984		—		—		—
RCF	—		—		—		370,000		370,000		370,000
Total long-term debt	$	4,220,000	$	4,177,353	$	4,111,452	$	3,490,000	$	3,464,712	$	3,594,177

⁽¹⁾  Fair value is measured using the market approach and Level 2 inputs.

Debt activity. The following table presents the debt activity of the Partnership for the six months ended June 30, 2018:

thousands	Carrying Value
Balance at December 31, 2017	$	3,464,712
RCF borrowings	260,000
Issuance of 2028 Notes	400,000
Issuance of 2048 Notes	700,000
Repayments of RCF borrowings	(630,000		)
Other	(17,359		)
Balance at June 30, 2018	$	4,177,353

Senior Notes. The 2018 Notes, which are due in August 2018, were classified as long-term debt on the consolidated balance sheet at June 30, 2018, as the Partnership has the ability and intent to refinance these obligations using long-term debt.

The 2028 Notes and 2048 Notes issued in March 2018 were offered at prices to the public of 99.435% and 99.169%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the 2028 Notes and 2048 Notes are 4.682% and 5.431%, respectively. Interest is paid on each such series semi-annually on March 1 and September 1 of each year, beginning September 1, 2018. The proceeds (net of underwriting discounts, original issue discounts and debt issuance costs) were used to repay amounts outstanding under the senior unsecured revolving credit facility (“RCF”) and for general partnership purposes, including to fund capital expenditures.

At June 30, 2018, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.

30

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

10. DEBT AND INTEREST EXPENSE (CONTINUED)

Revolving credit facility. In February 2018, the Partnership entered into the five-year $1.5 billion RCF by amending and restating the $1.2 billion credit facility that was originally entered into in February 2014. The RCF is expandable to a maximum of $2.0 billion, matures in February 2023, with options to extend maturity by up to two additional one year increments, and bears interest at the London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based upon the Partnership’s senior unsecured debt rating. The Partnership is required to pay a quarterly facility fee ranging from 0.125% to 0.250% of the commitment amount (whether used or unused), also based upon its senior unsecured debt rating.

As of June 30, 2018, the Partnership had no outstanding borrowings and $4.6 million in outstanding letters of credit, resulting in $1,495.4 million available borrowing capacity under the RCF. As of June 30, 2018 and 2017, the interest rate on any outstanding RCF borrowings was 3.39% and 2.53%, respectively. The facility fee rate was 0.20% at June 30, 2018 and 2017. At June 30, 2018, the Partnership was in compliance with all covenants under the RCF.

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

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands	2018			2017			2018			2017
Third parties
Long-term debt	$	(48,394	)	$	(35,161	)	$	(89,677	)	$	(69,780	)
Amortization of debt issuance costs and commitment fees	(2,006		)	(1,645		)	(4,060		)	(3,275		)
Capitalized interest	6,011			1,060			10,065			1,876
Total interest expense – third parties	(44,389		)	(35,746		)	(83,672		)	(71,179		)
Affiliates
Deferred purchase price obligation – Anadarko (1)	—			—			—			(71		)
Total interest expense – affiliates	—			—			—			(71		)
Interest expense	$	(44,389	)	$	(35,746	)	$	(83,672	)	$	(71,250	)

⁽¹⁾  See Note 3 for a discussion of the Deferred purchase price obligation - Anadarko.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

11. COMMITMENTS AND CONTINGENCIES

Litigation and legal proceedings. In February 2017, DBJV, at the time a 50/50 joint venture between a third party and the Partnership, initiated an arbitration against SWEPI LP (“SWEPI”) for breach of a 2007 gas gathering agreement between it and DBJV (the “GGA”). Specifically, DBJV seeks to collect approximately $194.2 million in gathering fees under the GGA for the period January 1, 2016 to July 1, 2017. SWEPI disputes DBJV’s calculation of the cost of service based rate and filed a counterclaim for $14.9 million alleging overpayment of fees under the GGA for the years 2013 through 2015. The final arbitration hearing concluded on June 27, 2018, and the Partnership expects to receive a decision by the end of the third quarter of 2018. Under the terms of the Property Exchange, the Partnership’s former joint venture partner in DBJV will owe 50% of any amounts to be paid, and have a right to 50% of any amounts received, by the Partnership as a result of this arbitration proceeding. Pursuant to an agreement between the parties, if the arbitrators determine that DBJV is owed an amount of money by SWEPI for underpaid gathering fees for the period from January 1, 2016 to July 1, 2017, that amount will be paid to DBJV over five years as a supplemental gathering fee under the currently effective gas gathering agreement between the parties. Any other amounts owed by either party will be paid in cash within ninety days of the conclusion of the arbitration. As part of the adoption of Topic 606 (see Note 1), during the first quarter of 2018, the Partnership recorded a $7.5 million contract liability and reduced total equity and partners’ capital related to the counterclaim for the years 2013 through 2015 under the GGA revenue contract. Any amounts awarded to DBJV under the arbitration would be recognized in the period the arbitration decision is received. Management does not believe the outcome of this proceeding will have a materially unfavorable effect on the Partnership’s financial condition, results of operations or cash flows.

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 the 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, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to construction and expansion projects at the DBJV system and the DJ Basin and DBM complexes.

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease arrangements for corporate offices, shared field offices and equipment supporting the Partnership’s operations, for which Anadarko charges the Partnership lease expense. The leases for the corporate offices and shared field offices extend through 2028 and 2033, respectively. Lease expense charged to the Partnership associated with these lease arrangements was $12.2 million and $25.9 million for the three and six months ended June 30, 2018, respectively, and $12.2 million and $20.7 million for the three and six months ended June 30, 2017, 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 under Part II, Item 8 of our 2017 Form 10-K as filed with the SEC on February 16, 2018.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made in this Form 10-Q, and may from time to time make in other public filings, press releases and statements by management, forward-looking statements concerning our operations, economic performance and financial condition. These forward-looking statements include statements preceded by, followed by or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition or include other “forward-looking” information.

Although we and our general partner believe that the expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurance that such expectations will prove to have been correct. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following:

• our ability to pay distributions to our unitholders;

• our and Anadarko’s assumptions about the energy market;

• future throughput (including Anadarko production) that is gathered or processed by or transported through our assets;

• our operating results;

• competitive conditions;

• technology;

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

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

• our ability to mitigate exposure to the commodity price risks inherent in our percent-of-proceeds, percent-of-product and keep-whole contracts through the extension of our commodity price swap agreements with Anadarko, or otherwise;

• weather and natural disasters;

• inflation;

• the availability of goods and services;

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

• federal, state and local laws, including those that limit Anadarko and other producers’ hydraulic fracturing or other oil and natural gas operations;

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• environmental liabilities;

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

• changes in the financial or operational condition of Anadarko;

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

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

• our commitments to capital projects;

• our ability to use the RCF;

• our ability to repay debt;

• 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 from Anadarko or third parties, and Anadarko’s ability to generate an inventory of assets suitable for acquisition;

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

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

• the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board related to Anadarko’s operations in Colorado, and continued or additional disruptions in operations that may occur as Anadarko and we comply with regulatory orders or other state or local changes in laws or regulations in Colorado; and

• other factors discussed below, in “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in our 2017 Form 10-K, and in our quarterly reports on Form 10-Q, and in our other public filings and press releases.

The risk factors and other factors noted throughout or incorporated by reference in this Form 10-Q could cause actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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EXECUTIVE SUMMARY

We are a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream assets. We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. We are engaged in the business of gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, NGLs and crude oil; and gathering and disposing of produced water. In addition, in our capacity as a processor of natural gas, we also buy and sell natural gas, NGLs and condensate on behalf of ourselves and as agent for our customers under certain of our contracts. We provide these midstream services for Anadarko, as well as for third-party producers and customers. As of June 30, 2018, our assets and investments consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems (1)	12	3	3	2
Treating facilities	19	3	—	3
Natural gas processing plants/trains	20	4	—	2
NGL pipelines	2	—	—	3
Natural gas pipelines	5	—	—	—
Oil pipelines	—	1	—	2

⁽¹⁾  Includes the DBM water systems.

Significant financial and operational events during the six months ended June 30, 2018, included the following:

• In June 2018, we acquired a 20% interest in Whitethorn and a 15% interest in Cactus II, both from third parties. See Acquisitions and Divestitures below for additional information.

• In March 2018, we completed an offering of $400.0 million aggregate principal amount of 2028 Notes and $700.0 million aggregate principal amount of 2048 Notes. The net proceeds were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures. See Liquidity and Capital Resources within this Item 2 for additional information.

• In February 2018, we entered into the five-year $1.5 billion (expandable to $2.0 billion) RCF by amending and restating the $1.2 billion credit facility originally entered into in February 2014. See Liquidity and Capital Resources within this Item 2 for additional information.

• We raised our distribution to $0.950 per unit for the second quarter of 2018, representing a 2%increase over the distribution for the first quarter of 2018 and a 7%increase over the distribution for the second quarter of 2017.

• Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,794 MMcf/d for the three months ended June 30, 2018, representing a 9%increase compared to the same period in 2017. Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,711 MMcf/d for the six months ended June 30, 2018, which was approximately the same compared to the same period in 2017.

• Throughput for crude oil, NGL and produced water assets totaled 343 MBbls/d and 301 MBbls/d for the three and six months ended June 30, 2018, respectively, representing an 88% and 71%increase, respectively, compared to the same periods in 2017.

• Operating income (loss) was $74.7 million and $262.9 million for the three and six months ended June 30, 2018, respectively, representing a 64% and 24%decrease, respectively, compared to the same periods in 2017.

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• Adjusted gross margin for natural gas assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $0.95 per Mcf and $0.98 per Mcf for the three and six months ended June 30, 2018, respectively, representing a 1% and 10%increase, respectively, compared to the same periods in 2017.

• Adjusted gross margin for crude oil, NGL and produced water assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $1.56 per Bbl and $1.68 per Bbl for the three and six months ended June 30, 2018, respectively, representing a 27% and 19%decrease, respectively, compared to the same periods in 2017.

Significant Item Affecting Comparability. On January 1, 2018, we adopted Revenue from Contracts with Customers (Topic 606) (“Topic 606”). The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition(Topic 605). The following tables summarize the impact of adopting Topic 606 on the consolidated statements of operations:

	Three Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	359,544	$	358,209	$	1,335
Service revenues – product based	22,105		—		22,105
Product sales	54,077		319,233		(265,156		)
Expenses
Cost of product	68,149		312,329		(244,180		)
Operation and maintenance	100,628		100,632		(4		)
Depreciation and amortization	78,792		78,125		667
Impairments	127,243		127,198		45
Income tax (benefit) expense	282		272		10

	Six Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	697,963	$	700,547	$	(2,584	)
Service revenues – product based	44,698		—		44,698
Product sales	130,014		611,524		(481,510		)
Expenses
Cost of product	145,948		587,295		(441,347		)
Operation and maintenance	188,907		188,771		136
Depreciation and amortization	155,634		154,278		1,356
Impairments	127,391		127,346		45
Income tax (benefit) expense	1,784		1,781		3

For more information on the adoption of Topic 606, see Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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ACQUISITIONS AND DIVESTITURES

Whitethorn LLC acquisition. In June 2018, we acquired a 20% interest in Whitethorn LLC, which owns the crude oil and condensate pipeline that originates in Midland, Texas and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with our investment in Whitethorn, we will share proportionally in the commercial activities. We acquired our 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Cactus II acquisition. In June 2018, we acquired a 15% interest in Cactus II, which will own a crude oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline is under construction and expected to become operational in the fourth quarter of 2019. We acquired our 15% interest from a third party via an $11.3 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Property exchange. On March 17, 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration. We previously held a 50% interest in, and operated, the DBJV system. The Property Exchange resulted in a net gain of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Divestitures. During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of $16.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

Presentation of Partnership assets.The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by us as of June 30, 2018 (see Note 8—Equity Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). Because Anadarko controls us through its control of WGP, which owns the entire interest in our general partner, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us. Further, after an acquisition of Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of such Partnership assets from the date of common control.

For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of the Partnership assets 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 we had owned the Partnership assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership assets prior to our acquisitions from Anadarko as being “our” historical financial results.

EQUITY OFFERINGS

Series A Preferred units. In 2016, we issued 21,922,831 Series A Preferred units to private investors. Pursuant to an agreement between us and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units converted into common units on a one-for-one basis on May 2, 2017. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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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   June 30,						Six Months Ended   June 30,
thousands	2018			2017			2018			2017
Total revenues and other(1)	$	435,949		$	525,450		$	873,117		$	1,041,643
Equity income, net – affiliates	39,218			21,728			59,642			41,189
Total operating expenses(1)	400,601			379,143			670,183			901,659
Gain (loss) on divestiture and other, net	170			15,458			286			134,945
Proceeds from business interruption insurance claims (2)	—			24,115			—			29,882
Operating income (loss)	74,736			207,608			262,862			346,000
Interest income – affiliates	4,225			4,225			8,450			8,450
Interest expense	(44,389		)	(35,746		)	(83,672		)	(71,250		)
Other income (expense), net	1,229			253			2,011			683
Income (loss) before income taxes	35,801			176,340			189,651			283,883
Income tax (benefit) expense	282			843			1,784			4,395
Net income (loss)	35,519			175,497			187,867			279,488
Net income attributable to noncontrolling interest	2,811			2,046			5,796			4,148
Net income (loss) attributable to Western Gas Partners, LP	$	32,708		$	173,451		$	182,071		$	275,340
Key performance metrics(3)
Adjusted gross margin	$	378,293		$	333,548		$	746,839		$	665,104
Adjusted EBITDA	271,659			274,835			543,778			529,829
Distributable cash flow	221,799			247,225			453,235			463,728

⁽¹⁾  Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue 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 Significant Item Affecting Comparability within this Item 2 and Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

⁽²⁾  See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

⁽³⁾  Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are defined under the caption Key Performance Metricswithin this Item 2. For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see Key Performance Metrics–Reconciliation of non-GAAP measures within this Item 2.

For purposes of the following discussion, any increases or decreases “for the three months ended June 30, 2018” refer to the comparison of the three months ended June 30, 2018, to the three months ended June 30, 2017; any increases or decreases “for the six months ended June 30, 2018” refer to the comparison of the six months ended June 30, 2018, to the six months ended June 30, 2017; and any increases or decreases “for the three and six months ended June 30, 2018” refer to the comparison of these 2018 periods to the corresponding three and six month periods ended June 30, 2017.

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Throughput

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2018	2017	Inc/ (Dec)		2018	2017	Inc/ (Dec)
Throughput for natural gas assets (MMcf/d)
Gathering, treating and transportation	887	866	2	%	852	1,155	(26	)%
Processing	2,860	2,555	12	%	2,808	2,498	12	%
Equity investment (1)	141	158	(11	)%	146	160	(9	)%
Total throughput for natural gas assets	3,888	3,579	9	%	3,806	3,813	—	%
Throughput attributable to noncontrolling interest for natural gas assets	94	107	(12	)%	95	108	(12	)%
Total throughput attributable to Western Gas Partners, LP for natural gas assets	3,794	3,472	9	%	3,711	3,705	—	%
Throughput for crude oil, NGL and produced water assets (MBbls/d)
Gathering, treating, transportation and disposal	145	50	190	%	134	47	185	%
Equity investment (2)	198	132	50	%	167	129	29	%
Total throughput for crude oil, NGL and produced water assets	343	182	88	%	301	176	71	%

⁽¹⁾  Represents our 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput.

⁽²⁾  Represents our 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEG and TEP throughput, 33.33% share of average FRP throughput and 20% share of average Whitethorn throughput.

Natural gas assets

Gathering, treating and transportation throughput increased by 21 MMcf/d for the three months ended June 30, 2018, primarily due to (i) increased production in the areas around the DBJV system (increase of 48 MMcf/d) and (ii) increased throughput at the Bison facility due to a new contract effective April 2018 (increase of 35 MMcf/d). These increases were partially offset by (i) the sale of the Helper and Clawson systems in June 2017 (decrease of 33 MMcf/d), (ii) lower throughput at the MIGC system (decrease of 18 MMcf/d) and (iii) lower throughput at the Haley system due to decreased production in the area (decrease of 13 MMcf/d).

Gathering, treating and transportation throughput decreased by 303 MMcf/d for the six months ended June 30, 2018, primarily due to (i) the Property Exchange in March 2017 (decrease of 241 MMcf/d), (ii) the sale of the Helper and Clawson systems in June 2017 (decrease of 33 MMcf/d) and (iii) lower throughput at the MIGC system (decrease of 11 MMcf/d).

Processing throughput increased by 305 MMcf/d and 310 MMcf/d for the three and six months ended June 30, 2018, respectively, primarily due to (i) increased production in the areas around the DJ Basin and DBM complexes, (ii) the start-up of Train VI at the DBM complex in December 2017 and (iii) increased throughput at the MGR assets due to downtime at the nearby Granger straddle plant in 2017. These increases were partially offset by lower throughput at the Chipeta complex due to the expiration and non-renewal of a contract in September 2017.

Equity investment throughput decreased by 17 MMcf/d and 14 MMcf/d for the three and six months ended June 30, 2018, respectively, primarily due to decreased throughput at the Fort Union and Rendezvous systems due to production declines in the area, as well as throughput being diverted from the Fort Union system to other nearby systems.

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Crude oil, NGL and produced water assets

Gathering, treating, transportation and disposal throughput increased by 95 MBbls/d and 87 MBbls/d for the three and six months ended June 30, 2018, respectively, primarily due to increased throughput from the DBM water systems, which commenced operation during the second quarter of 2017.

Equity investment throughput increased by 66 MBbls/d and 38 MBbls/d for the three and six months ended June 30, 2018, respectively, primarily due to (i) the acquisition of the interest in Whitethorn in June 2018 and (ii) increased volumes on FRP and TEP as a result of increased NGL production in the DJ Basin area.

Service Revenues

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except percentages	2018		2017		Inc/ (Dec)		2018		2017		Inc/ (Dec)
Service revenues – fee based	$	359,544	$	299,435	20	%	$	697,963	$	607,249	15	%
Service revenues – product based	22,105		—		NM		44,698		—		NM
Total service revenues	$	381,649	$	299,435	27	%	$	742,661	$	607,249	22	%

NM-Not Meaningful

Service revenues – fee based increased by $60.1 million for the three months ended June 30, 2018, primarily due to increases of (i) $35.6 million at the DJ Basin complex due to increased throughput ($26.7 million) and a higher processing fee ($8.9 million) due to a new contract effective August 2017, (ii) $16.8 million at the DBM complex due to increased throughput and (iii) $8.9 million and $4.5 million at the DBM water and DBJV systems, respectively, due to increased throughput. These increases were partially offset by decreases of (i) $3.3 million at the Chipeta complex due to decreases in throughput and deficiency fees and (ii) $2.5 million at the Springfield system due to a lower cost of service rate.

Service revenues – fee based increased by $90.7 million for the six months ended June 30, 2018, primarily due to increases of (i) $62.0 million at the DJ Basin complex due to increased throughput ($42.6 million) and a higher processing fee ($19.4 million) due to a new contract effective August 2017, (ii) $33.8 million at the DBM complex due to increased throughput and (iii) $15.8 million at the DBM water systems, which commenced operation during the second quarter of 2017. These increases were partially offset by decreases of (i) $6.8 million at the Springfield system due to a lower cost of service rate, (ii) $5.5 million at the Chipeta complex due to decreases in throughput and deficiency fees and (iii) $3.8 million due to the Property Exchange in March 2017.

Service revenues – product based increased by $22.1 million and $44.7 million for the three and six months ended June 30, 2018, respectively, due to the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2. Under Topic 606, certain of our customer agreements result in revenues being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. In addition, retained proceeds from sales of customer products where we are acting as their agent are included in Service revenues – product based.

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Product Sales

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except percentages and per-unit amounts	2018		2017		Inc/ (Dec)		2018		2017		Inc/ (Dec)
Natural gas sales (1)	$	11,210	$	92,946	(88	)%	$	39,578	$	172,861	(77	)%
Natural gas liquids sales (1)	42,867		131,878		(67	)%	90,436		258,488		(65	)%
Total Product sales	$	54,077	$	224,824	(76	)%	$	130,014	$	431,349	(70	)%
Gross average sales price per unit (1):
Natural gas (per Mcf)	$	1.91	$	2.95	(35	)%	$	2.14	$	3.00	(29	)%
Natural gas liquids (per Bbl)	28.04		19.98		40	%	27.98		20.87		34	%

⁽¹⁾  Includes the effects of commodity price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Natural gas sales decreased by $81.7 million for the three months ended June 30, 2018, primarily due to decreases of (i) $56.2 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2, (ii) $5.2 million due to a decrease in average price and $9.3 million due to a system shutdown, both at the Hilight system (see Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q) and (iii) $6.8 million at the DBM complex due to a decrease in average price, partially offset by an increase in volumes sold.

Natural gas sales decreased by $133.3 million for the six months ended June 30, 2018, primarily due to decreases of (i) $124.3 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2 and (ii) $5.9 million due to a decrease in average price and $9.3 million due to a system shutdown, both at the Hilight system (see Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). These decreases were partially offset by an increase of $7.0 million at the DBM complex due to an increase in volumes sold, partially offset by a decrease in average price.

NGLs sales decreased by $89.0 million and $168.1 million for the three and six months ended June 30, 2018, respectively, primarily due to decreases of $209.0 million and $357.2 million, respectively, from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2. These decreases were partially offset by increases of (i) $90.8 million and $137.3 million, respectively, at the DBM complex due to an increase in average price and volumes sold, (ii) $14.3 million and $24.4 million, respectively, at the DJ Basin complex due to an increase in the swap market price and volumes sold, (iii) $5.3 million and $9.3 million, respectively, at the Brasada complex due to volumes sold under a new sales agreement beginning January 1, 2018, and (iv) $3.0 million and $4.7 million, respectively, at the Chipeta complex due to an increase in average price and volumes sold. In addition, for the six months ended June 30, 2018, NGL sales increased by $4.0 million at the DBM water systems, which commenced operation during the second quarter of 2017.

Equity Income, Net – Affiliates

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except percentages	2018		2017		Inc/ (Dec)		2018		2017		Inc/ (Dec)
Equity income, net – affiliates	$	39,218	$	21,728	80	%	$	59,642	$	41,189	45	%

For the three and six months ended June 30, 2018, equity income, net – affiliates increased by $17.5 million and $18.5 million, respectively, primarily due to (i) increased volumes at the TEFR Interests and (ii) the acquisition of the interest in Whitethorn in June 2018. These increases were partially offset by a decrease in volumes at the Fort Union system.

41

Cost of Product and Operation and Maintenance Expenses

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except percentages	2018		2017		Inc/ (Dec)		2018		2017		Inc/ (Dec)
NGL purchases (1)	$	42,905	$	114,607	(63	)%	$	84,507	$	222,980	(62	)%
Residue purchases (1)	19,794		87,807		(77	)%	47,072		166,123		(72	)%
Other	5,450		863		NM		14,369		3,533		NM
Cost of product	68,149		203,277		(66	)%	145,948		392,636		(63	)%
Operation and maintenance	100,628		76,148		32	%	188,907		149,908		26	%
Total Cost of product and Operation and maintenance expenses	$	168,777	$	279,425	(40	)%	$	334,855	$	542,544	(38	)%

⁽¹⁾  For the three and six months ended June 30, 2017, includes the effects of commodity price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

NGL purchases decreased by $71.7 million and $138.5 million for the three and six months ended June 30, 2018, respectively, primarily due to decreases of $188.8 million and $318.6 million, respectively, from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2, partially offset by increases of (i) $92.5 million and $133.4 million, respectively, at the DBM complex due to an increase in average price and volumes purchased, (ii) $14.7 million and $26.4 million, respectively, at the DJ Basin complex due to an increase in average price and volumes purchased, and (iii) $4.7 million and $8.2 million, respectively, at the Brasada complex due to volumes purchased under a new purchase agreement beginning January 1, 2018.

Residue purchases decreased by $68.0 million for the three months ended June 30, 2018, primarily due to decreases of (i) $52.0 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2, (ii) $8.1 million at the DBM complex due to a decrease in average price, partially offset by an increase in volumes purchased, and (iii) $4.6 million at the Hilight system due to a decrease in average price.

Residue purchases decreased by $119.1 million for the six months ended June 30, 2018, primarily due to decreases of (i) $115.9 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2 and (ii) $4.5 million at the Hilight system due to a decrease in average price. These decreases were partially offset by an increase of $4.4 million at the DBM complex due to an increase in volumes purchased.

Other items increased by $4.6 million and $10.8 million for the three and six months ended June 30, 2018, respectively, primarily due to increases of $8.1 million and $15.2 million, respectively, at the DJ Basin complex due to changes in affiliate contract terms in August 2017, partially offset by decreases of $3.4 million and $6.8 million, respectively, from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2.

Operation and maintenance expense increased by $24.5 million for the three months ended June 30, 2018, primarily due to increases of (i) $8.3 million at the DJ Basin complex primarily due to increases in utilities expense and surface maintenance and plant repairs, (ii) $8.1 million at the DBM complex primarily due to increases in surface maintenance and plant repairs, utilities expense, chemicals and treating services, and salaries and wages, and (iii) $3.7 million at the DBJV system primarily due to increases in surface maintenance and plant repairs and salaries and wages.

Operation and maintenance expense increased by $39.0 million for the six months ended June 30, 2018, primarily due to increases of (i) $13.1 million at the DJ Basin complex primarily due to increases in utilities expense, surface maintenance and plant repairs, and salaries and wages, (ii) $12.9 million at the DBM complex primarily due to increases in equipment rentals, utilities expense, surface maintenance and plant repairs, and salaries and wages, (iii) $6.7 million due to the Property Exchange in March 2017 and (iv) $2.6 million at the DBM water systems, which commenced operation during the second quarter of 2017.

42

Other Operating Expenses

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except percentages	2018		2017		Inc/ (Dec)		2018		2017		Inc/ (Dec)
General and administrative	$	14,035	$	10,585	33	%	$	28,167	$	23,244	21	%
Property and other taxes	11,754		11,924		(1	)%	24,136		24,218		—	%
Depreciation and amortization	78,792		74,031		6	%	155,634		143,733		8	%
Impairments	127,243		3,178		NM		127,391		167,920		(24	)%
Total other operating expenses	$	231,824	$	99,718	132	%	$	335,328	$	359,115	(7	)%

General and administrative expenses increased by $3.5 million and $4.9 million for the three and six months ended June 30, 2018, respectively, primarily due to increases in (i) legal and consulting fees incurred in connection with the arbitration against SWEPI LP (see Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q) and (ii) personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement. For the six months ended June 30, 2018, these increases were partially offset by a decrease in bad debt expense.

Depreciation and amortization expense increased by $4.8 million for the three months ended June 30, 2018, primarily due to depreciation expense increases of $1.7 million and $1.5 million related to capital projects being placed into service at the DBM complex and the DBJV system, respectively.

Depreciation and amortization expense increased by $11.9 million for the six months ended June 30, 2018, primarily due to depreciation expense increases of (i) $8.1 million due to the Property Exchange in March 2017 and capital projects being placed into service at the DBJV system and (ii) $3.7 million related to capital projects being placed into service at the DBM complex. These increases were partially offset by a decrease of $2.1 million at the Granger complex due to an impairment recorded in the first quarter of 2017.

Impairment expense for the three and six months ended June 30, 2018, was primarily due to impairments of $120.8 million at the Third Creek gathering system and $6.4 million at the Kitty Draw gathering system. See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Impairment expense for the three months ended June 30, 2017, was primarily due to an impairment of $3.1 million at the Fort Union system.

Impairment expense for the six months ended June 30, 2017, included (i) a $158.8 million impairment at the Granger complex, (ii) a $3.7 million impairment at the Granger straddle plant, (iii) a $3.1 million impairment at the Fort Union system and (iv) the cancellation of a pipeline project in West Texas. For further information on impairment expense for the periods presented, see Note 7—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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Interest Income – Affiliates and Interest Expense

	Three Months Ended   June 30,								Six Months Ended   June 30,
thousands except percentages	2018			2017			Inc/ (Dec)		2018			2017			Inc/ (Dec)
Note receivable – Anadarko	$	4,225		$	4,225		—	%	$	8,450		$	8,450		—	%
Interest income – affiliates	$	4,225		$	4,225		—	%	$	8,450		$	8,450		—	%
Third parties
Long-term debt	$	(48,394	)	$	(35,161	)	38	%	$	(89,677	)	$	(69,780	)	29	%
Amortization of debt issuance costs and commitment fees	(2,006		)	(1,645		)	22	%	(4,060		)	(3,275		)	24	%
Capitalized interest	6,011			1,060			NM		10,065			1,876			NM
Affiliates
Deferred purchase price obligation – Anadarko (1)	—			—			—	%	—			(71		)	(100	)%
Interest expense	$	(44,389	)	$	(35,746	)	24	%	$	(83,672	)	$	(71,250	)	17	%

⁽¹⁾  See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for a discussion of the Deferred purchase price obligation - Anadarko.

Interest expense increased by $8.6 million and $12.4 million for the three and six months ended June 30, 2018, respectively, primarily due to (i) $9.3 million and $12.3 million, respectively, of interest incurred on the 2048 Notes issued in March 2018 and (ii) $4.5 million and $6.0 million, respectively, of interest incurred on the 2028 Notes issued in March 2018. In addition, for the six months ended June 30, 2018, there was a $1.7 million increase in interest incurred on the RCF. These increases were partially offset by increases in capitalized interest of $5.0 million and $8.2 million for the three and six months ended June 30, 2018, respectively, primarily due to continued construction and expansion at the DJ Basin complex, DBJV system and DBM complex, including construction of the Mentone plant beginning in the fourth quarter of 2017.

Income Tax (Benefit) Expense

	Three Months Ended   June 30,								Six Months Ended   June 30,
thousands except percentages	2018			2017			Inc/ (Dec)		2018			2017			Inc/ (Dec)
Income (loss) before income taxes	$	35,801		$	176,340		(80	)%	$	189,651		$	283,883		(33	)%
Income tax (benefit) expense	282			843			(67	)%	1,784			4,395			(59	)%
Effective tax rate	1		%	—		%			1		%	2		%

We are not a taxable entity for U.S. federal income tax purposes. However, our income apportionable to Texas is subject to Texas margin tax. For all periods presented, the variance from the federal statutory rate, which is zero percent as a non-taxable entity, was primarily due to our share of Texas margin tax.

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KEY PERFORMANCE METRICS

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except percentages and per-unit amounts	2018		2017		Inc/ (Dec)		2018		2017		Inc/ (Dec)
Adjusted gross margin for natural gas assets (1)	$	329,653	$	297,778	11	%	$	655,525	$	599,283	9	%
Adjusted gross margin for crude oil, NGL and produced water assets (2)	48,640		35,770		36	%	91,314		65,821		39	%
Adjusted gross margin (3)	378,293		333,548		13	%	746,839		665,104		12	%
Adjusted gross margin per Mcf for natural gas assets (4)	0.95		0.94		1	%	0.98		0.89		10	%
Adjusted gross margin per Bbl for crude oil, NGL and produced water assets (5)	1.56		2.15		(27	)%	1.68		2.07		(19	)%
Adjusted EBITDA (3)	271,659		274,835		(1	)%	543,778		529,829		3	%
Distributable cash flow (3)	221,799		247,225		(10	)%	453,235		463,728		(2	)%

⁽¹⁾  Adjusted gross margin for natural gas assets is calculated as total revenues and other for natural gas assets (less reimbursements for electricity-related expenses recorded as revenue), less cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin for natural gas assets to its most comparable GAAP measure below.

⁽²⁾  Adjusted gross margin for crude oil, NGL and produced water assets is calculated as total revenues and other for crude oil, NGL and produced water assets (less reimbursements for electricity-related expenses recorded as revenue), less cost of product for crude oil, NGL and produced water assets, and plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, the TEFR Interests and Whitethorn. See the reconciliation of Adjusted gross margin for crude oil, NGL and produced water assets to its most comparable GAAP measure below.

⁽³⁾  For a reconciliation of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the description below.

⁽⁴⁾  Average for period. Calculated as Adjusted gross margin for natural gas assets, divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.

⁽⁵⁾  Average for period. Calculated as Adjusted gross margin for crude oil, NGL and produced water assets, divided by total throughput (MBbls/d) for crude oil, NGL and produced water assets.

Adjusted gross margin. We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from equity investments, 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 the midstream industry.

Adjusted gross margin increased by $44.7 million for the three months ended June 30, 2018, primarily due to (i) increased throughput and a higher processing fee at the DJ Basin complex and (ii) increased throughput at the DBM complex and DBM water and DBJV systems. These increases were partially offset by decreases due to (i) a system shutdown at the Hilight system (see Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q) and (ii) a lower cost of service rate at the Springfield system.

Adjusted gross margin increased by $81.7 million for the six months ended June 30, 2018, primarily due to (i) increased throughput and a higher processing fee at the DJ Basin complex, (ii) increased throughput at the DBM complex and (iii) the start-up of the DBM water systems during the second quarter of 2017. These increases were partially offset by decreases due to (i) a system shutdown at the Hilight system (see Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), (ii) a lower cost of service rate at the Springfield system and (iii) the Property Exchange in March 2017.

45

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf for natural gas assets and Adjusted gross margin per Bbl for crude oil, NGL and produced water assets. Adjusted gross margin per Mcf for natural gas assets increased by $0.01 for the three months ended June 30, 2018, primarily due to increased throughput at the DBM complex. Adjusted gross margin per Mcf for natural gas assets increased by $0.09 for the six months ended June 30, 2018, primarily due to (i) the Property Exchange in March 2017 and (ii) increased throughput at the DBM complex, which has a higher-than-average margin as compared to our other natural gas assets.

Adjusted gross margin per Bbl for crude oil, NGL and produced water assets decreased by $0.59 for the three months ended June 30, 2018, primarily due to (i) increased throughput at the DBM water systems, which have lower margins than our crude oil and NGL assets, and (ii) a lower cost of service rate at the Springfield oil gathering system. These decreases were partially offset by higher distributions received from TEP.

Adjusted gross margin per Bbl for crude oil, NGL and produced water assets decreased by $0.39 for the six months ended June 30, 2018, primarily due to (i) the start-up of the DBM water systems during the second quarter of 2017, which have lower margins than our crude oil and NGL assets, and (ii) a lower cost of service rate at the Springfield oil gathering system. These decreases were partially offset by higher distributions received from the TEFR Interests and the Mont Belvieu JV.

Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investments, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, impairments, and other expense (including lower of cost or market inventory adjustments recorded in cost of product), less gain (loss) on divestiture and other, net, 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 industry, without regard to financing methods, capital structure or historical cost basis;

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

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

Adjusted EBITDA decreased by $3.2 million for the three months ended June 30, 2018, primarily due to (i) an $89.5 milliondecrease in total revenues and other, (ii) a $24.5 millionincrease in operation and maintenance expenses, (iii) a $24.1 milliondecrease in business interruption proceeds and (iv) a $2.6 millionincrease in general and administrative expenses excluding non-cash equity-based compensation expense. These amounts were partially offset by (i) a $135.0 milliondecrease in cost of product (net of lower of cost or market inventory adjustments) and (ii) a $3.1 millionincrease in distributions from equity investments.

Adjusted EBITDA increased by $13.9 million for the six months ended June 30, 2018, primarily due to (i) a $246.7 milliondecrease in cost of product (net of lower of cost or market inventory adjustments) and (ii) a $9.5 millionincrease in distributions from equity investments. These amounts were partially offset by (i) a $168.5 milliondecrease in total revenues and other, (ii) a $39.0 millionincrease in operation and maintenance expenses, (iii) a $29.9 milliondecrease in business interruption proceeds and (iv) a $3.1 millionincrease in general and administrative expenses excluding non-cash equity-based compensation expense.

46

Distributable cash flow. We define “Distributable cash flow” as Adjusted EBITDA, plus interest income and the net settlement amounts from the sale and/or purchase of natural gas, condensate and NGLs under our commodity price swap agreements to the extent such amounts are not recognized as Adjusted EBITDA, less Service revenues – fee based recognized in Adjusted EBITDA (less than) in excess of customer billings, net cash paid (or to be paid) for interest expense (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures, Series A Preferred unit distributions 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. Furthermore, to the extent Distributable cash flow includes realized amounts recorded as capital contributions from Anadarko attributable to activity under our commodity price swap agreements, it is not a reflection of our ability to generate cash from operations.

Distributable cash flow decreased by $25.4 million for the three months ended June 30, 2018, primarily due to (i) a $13.6 millionincrease in net cash paid for interest expense, (ii) a $9.5 millionincrease in cash paid for maintenance capital expenditures, (iii) a $3.2 milliondecrease in Adjusted EBITDA and (iv) a $2.5 milliondecrease in the above-market component of the swap agreements with Anadarko. These amounts were partially offset by $3.4 million of customer billings in excess of the amount recognized as Service revenues - fee based.

Distributable cash flow decreased by $10.5 million for the six months ended June 30, 2018, primarily due to (i) a $20.7 millionincrease in net cash paid for interest expense and (ii) a $14.8 millionincrease in cash paid for maintenance capital expenditures. These amounts were partially offset by (i) a $13.9 millionincrease in Adjusted EBITDA, (ii) a $7.5 milliondecrease in Series A Preferred unit distributions and (iii) $3.9 million of customer billings in excess of the amount recognized as Service revenues - fee based.

Reconciliation of non-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 (loss), while net income (loss) 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 (loss) 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 (loss), net income (loss) 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 (loss), net income (loss) attributable to Western Gas Partners, LP 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.

47

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

	Three Months Ended   June 30,				Six Months Ended   June 30,
thousands	2018		2017		2018		2017
Reconciliation of Operating income (loss) to Adjusted gross margin
Operating income (loss)	$	74,736	$	207,608	$	262,862	$	346,000
Add:
Distributions from equity investments	31,947		28,856		60,901		51,423
Operation and maintenance	100,628		76,148		188,907		149,908
General and administrative	14,035		10,585		28,167		23,244
Property and other taxes	11,754		11,924		24,136		24,218
Depreciation and amortization	78,792		74,031		155,634		143,733
Impairments	127,243		3,178		127,391		167,920
Less:
Gain (loss) on divestiture and other, net	170		15,458		286		134,945
Proceeds from business interruption insurance claims	—		24,115		—		29,882
Equity income, net – affiliates	39,218		21,728		59,642		41,189
Reimbursed electricity-related charges recorded as revenues	17,231		14,046		32,684		28,015
Adjusted gross margin attributable to noncontrolling interest	4,223		3,435		8,547		7,311
Adjusted gross margin	$	378,293	$	333,548	$	746,839	$	665,104
Adjusted gross margin for natural gas assets	$	329,653	$	297,778	$	655,525	$	599,283
Adjusted gross margin for crude oil, NGL and produced water assets	48,640		35,770		91,314		65,821

48

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands	2018			2017			2018			2017
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA
Net income (loss) attributable to Western Gas Partners, LP	$	32,708		$	173,451		$	182,071		$	275,340
Add:
Distributions from equity investments	31,947			28,856			60,901			51,423
Non-cash equity-based compensation expense	1,852			975			4,004			2,221
Interest expense	44,389			35,746			83,672			71,250
Income tax expense	282			843			1,784			4,395
Depreciation and amortization (1)	78,066			73,352			154,182			142,401
Impairments	127,243			3,178			127,391			167,920
Other expense (1)	8			95			151			140
Less:
Gain (loss) on divestiture and other, net	170			15,458			286			134,945
Equity income, net – affiliates	39,218			21,728			59,642			41,189
Interest income – affiliates	4,225			4,225			8,450			8,450
Other income (1)	1,223			250			2,000			677
Adjusted EBITDA	$	271,659		$	274,835		$	543,778		$	529,829
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities	$	273,315		$	240,536		$	514,911		$	433,152
Interest (income) expense, net	40,164			31,521			75,222			62,800
Uncontributed cash-based compensation awards	398			(209		)	987			(172		)
Accretion and amortization of long-term obligations, net	(1,248		)	(1,038		)	(2,626		)	(2,139		)
Current income tax (benefit) expense	90			204			261			628
Other (income) expense, net	(1,229		)	(253		)	(2,011		)	(683		)
Distributions from equity investments in excess of cumulative earnings – affiliates	4,492			5,768			12,505			9,221
Changes in assets and liabilities:
Accounts receivable, net	(21,639		)	(10,876		)	7,009			(9,363		)
Accounts and imbalance payables and accrued liabilities, net	(13,498		)	12,035			(40,573		)	41,975
Other items, net	(5,655		)	(131		)	(14,670		)	(116		)
Adjusted EBITDA attributable to noncontrolling interest	(3,531		)	(2,722		)	(7,237		)	(5,474		)
Adjusted EBITDA	$	271,659		$	274,835		$	543,778		$	529,829
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities							$	514,911		$	433,152
Net cash used in investing activities							(826,653		)	(363,131		)
Net cash provided by (used in) financing activities							286,163			(239,749		)

⁽¹⁾  Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex.

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	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except Coverage ratio	2018				2017		2018				2017
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Distributable cash flow and calculation of the Coverage ratio
Net income (loss) attributable to Western Gas Partners, LP	$	32,708			$	173,451	$	182,071			$	275,340
Add:
Distributions from equity investments	31,947				28,856		60,901				51,423
Non-cash equity-based compensation expense	1,852				975		4,004				2,221
Non-cash settled interest expense, net (1)	—				—		—				71
Income tax (benefit) expense	282				843		1,784				4,395
Depreciation and amortization (2)	78,066				73,352		154,182				142,401
Impairments	127,243				3,178		127,391				167,920
Above-market component of swap agreements with Anadarko (3)	13,839				16,373		28,121				28,670
Other expense (2)	8				95		151				140
Less:
Recognized Service revenues – fee based (less than) in excess of customer billings (4)	(3,367		)		—		(3,861		)		—
Gain (loss) on divestiture and other, net	170				15,458		286				134,945
Equity income, net – affiliates	39,218				21,728		59,642				41,189
Cash paid for maintenance capital expenditures (2)	20,891				11,402		37,325				22,524
Capitalized interest	6,011				1,060		10,065				1,876
Cash paid for (reimbursement of) income taxes	—				—		(87		)		189
Series A Preferred unit distributions	—				—		—				7,453
Other income (2)	1,223				250		2,000				677
Distributable cash flow	$	221,799			$	247,225	$	453,235			$	463,728
Distributions declared(5)
Limited partners – common units	$	144,979					$	287,662
General partner	80,712						159,162
Total	$	225,691					$	446,824
Coverage ratio	0.98			x			1.01			x

⁽¹⁾  Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

⁽²⁾  Includes our 75% share of depreciation and amortization; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex.

⁽³⁾  See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

⁽⁴⁾  See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

⁽⁵⁾  Reflects cash distributions of $0.950 and $1.885 per unit declared for the three and six months ended June 30, 2018, respectively.

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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 June 30, 2018, 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 the 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, including the extension of our commodity price swap agreements, and will be determined by the Board of Directors 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 the RCF to pay distributions or fund other short-term working capital requirements.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. The Board of Directors declared a cash distribution to our unitholders for the second quarter of 2018 of $0.950 per unit, or $225.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units. The cash distribution is payable on August 13, 2018, to unitholders of record at the close of business on August 1, 2018. In connection with the closing of the DBM acquisition in November 2014, we issued Class C units that will receive distributions in the form of additional Class C units until March 1, 2020, unless earlier converted (see Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). The Class C unit distribution, if paid in cash, would have been $13.1 million for the second quarter of 2018.

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 potential debt or equity securities offerings, 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. Read Risk Factors under Part II, Item 1A of this Form 10-Q.

Working capital. As of June 30, 2018, we had a $242.0 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Working capital is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable and factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for maintenance and expansion activity. Our working capital deficit as of June 30, 2018, was primarily due to (i) the costs incurred related to continued construction and expansion at the DBJV system and the DBM and DJ Basin complexes and (ii) system shutdowns at the Hilight system and DJ Basin complex. See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. As of June 30, 2018, we had $1,495.4 million available for borrowing under the RCF. See Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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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 2018, the general partner’s Board of Directors has approved Estimated Maintenance Capital Expenditures (as defined in our partnership agreement) of $19.5 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:

	Six Months Ended   June 30,
thousands	2018		2017
Acquisitions	$	161,858	$	159,197
Expansion capital expenditures	$	612,755	$	236,538
Maintenance capital expenditures	37,341		22,599
Total capital expenditures (1) (2)	$	650,096	$	259,137
Capital incurred (2)	$	627,999	$	279,921

⁽¹⁾  Capital expenditures for the six months ended June 30, 2017, are presented net of $1.3 million of contributions in aid of construction costs from affiliates.

⁽²⁾  For the six months ended June 30, 2018 and 2017, included $10.1 million and $1.9 million, respectively, of capitalized interest.

Acquisitions during 2018 included a 20% interest in Whitethorn and a 15% interest in Cactus II. Acquisitions during 2017 included the Additional DBJV System Interest and equipment purchases from Anadarko. See Note 3—Acquisitions and Divestitures and Note 6—Transactions with Affiliatesin the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Capital expenditures, excluding acquisitions, increased by $391.0 million for the six months ended June 30, 2018. Expansion capital expenditures increased by $376.2 million (including an $8.2 millionincrease in capitalized interest) for the six months ended June 30, 2018, primarily due to increases of $285.4 million at the DBJV system, $132.3 million at the DJ Basin complex and $13.7 million at the Haley system, primarily due to pipe, compression and processing projects. These increases were partially offset by decreases of (i) $36.8 million at the DBM water systems, which commenced operation during the second quarter of 2017 and (ii) $21.7 million at the DBM complex due to the start-up of Train VI in December 2017. Maintenance capital expenditures increased by $14.7 million for the six months ended June 30, 2018, primarily due to increases at the DJ Basin complex and DBJV system.

During the first quarter of 2018, we updated our estimated total capital expenditures for the year ending December 31, 2018, (including equity investments and our 75% share of Chipeta’s capital expenditures, but excluding acquisitions) from an originally reported $1.0 billion to $1.1 billion, to a current range of $1.35 billion to $1.45 billion to reflect our acquisition of a 20% interest in Whitethorn and a 15% interest in Cactus II.

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

	Six Months Ended   June 30,
thousands	2018			2017
Net cash provided by (used in):
Operating activities	$	514,911		$	433,152
Investing activities	(826,653		)	(363,131		)
Financing activities	286,163			(239,749		)
Net increase (decrease) in cash and cash equivalents	$	(25,579	)	$	(169,728	)

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2018, increased 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 six months ended June 30, 2018, included the following:

• $650.1 million of capital expenditures, primarily related to construction and expansion at the DBJV system and the DBM and DJ Basin complexes;

• $161.9 million of cash paid for the acquisitions of the interests in Whitethorn and Cactus II;

• $27.5 million of capital contributions paid to Cactus II, Whitethorn and White Cliffs for construction activities; and

• $12.5 million of distributions received from equity investments in excess of cumulative earnings.

Net cash used in investing activities for the six months ended June 30, 2017, included the following:

• $259.1 million of capital expenditures, net of $1.3 million of contributions in aid of construction costs from affiliates, primarily related to plant construction and expansion at the DBM complex and DBJV system; and purchases of long lead items related to the future construction of the Mentone plant, all located in West Texas;

• $155.3 million of cash consideration paid as part of the Property Exchange;

• $23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah;

• $23.0 million of proceeds from property insurance claims attributable to the incident at the DBM complex in 2015;

• $9.2 million of distributions received from equity investments in excess of cumulative earnings; and

• $3.9 million of cash paid for equipment purchases from Anadarko.

Financing Activities. Net cash provided by financing activities for the six months ended June 30, 2018, included the following:

• $1.08 billion of net proceeds from the offering of the 2028 Notes and 2048 Notes in March 2018, after underwriting and original issue discounts and offering costs, which were or will be used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures;

• $630.0 million of repayments of outstanding borrowings under the RCF;

• $437.7 million of distributions paid to our unitholders;

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• $256.8 million of borrowings under the RCF, net of extension costs, which were used for general partnership purposes, including to fund capital expenditures;

• $28.1 million of capital contributions from Anadarko related to the above-market component of swap agreements; and

• $6.4 million of distributions paid to the noncontrolling interest owner of Chipeta.

Net cash used in financing activities for the six months ended June 30, 2017, included the following:

• $381.8 million of distributions paid to our unitholders;

• $160.0 million of borrowings under our RCF, which were used for general partnership purposes;

• $37.3 million of cash paid to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko;

• $28.7 million of capital contributions from Anadarko related to the above-market component of swap agreements; and

• $6.4 million of distributions paid to the noncontrolling interest owner of Chipeta.

Debt and credit facility. At June 30, 2018, our debt consisted of $350.0 million aggregate principal amount of the 2018 Notes, $500.0 million aggregate principal amount of the 2021 Notes, $670.0 million aggregate principal amount of the 2022 Notes, $500.0 million aggregate principal amount of the 2025 Notes, $500.0 million aggregate principal amount of the 2026 Notes, $400.0 million aggregate principal amount of the 2028 Notes, $600.0 million aggregate principal amount of the 2044 Notes and $700.0 million aggregate principal amount of the 2048 Notes. As of June 30, 2018, the carrying value of our outstanding debt was $4.2 billion. See Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Senior Notes. The 2018 Notes, which are due in August 2018, were classified as long-term debt on the consolidated balance sheet at June 30, 2018, as we have the ability and intent to refinance these obligations using long-term debt.

The 2028 Notes and 2048 Notes issued in March 2018 were offered at prices to the public of 99.435% and 99.169%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the 2028 Notes and 2048 Notes are 4.682% and 5.431%, respectively. Interest is paid on each such series semi-annually on March 1 and September 1 of each year, beginning September 1, 2018. The proceeds (net of underwriting discounts, original issue discounts and debt issuance costs) were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures.

At June 30, 2018, we were in compliance with all covenants under the indentures governing our outstanding notes.

Revolving credit facility. In February 2018, we entered into the five-year $1.5 billion RCF by amending and restating the $1.2 billion credit facility that was originally entered into in February 2014. The RCF is expandable to a maximum of $2.0 billion, matures in February 2023, with options to extend maturity by up to two additional one year increments, and bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based upon our senior unsecured debt rating. We are required to pay a quarterly facility fee ranging from 0.125% to 0.250% of the commitment amount (whether used or unused), also based upon our senior unsecured debt rating.

As of June 30, 2018, we had no outstanding borrowings and $4.6 million in outstanding letters of credit, resulting in $1,495.4 million available for borrowing under the RCF. At June 30, 2018, the interest rate on the RCF was 3.39% and the facility fee rate was 0.20%. At June 30, 2018, we were in compliance with all covenants under the RCF.

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Securities. We may issue an indeterminate amount of common units and various debt securities under our effective shelf registration statement on file with the SEC. We may also issue common units under the $500.0 million COP, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of offering. As of June 30, 2018, we had issued no common units under the registration statement associated with the $500.0 million COP.

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

We do not, however, 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, transportation and disposal 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. 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 a majority of the commodity price risk inherent in our percent-of-proceeds, percent-of-product and keep-whole contracts, and are subject to performance risk thereunder. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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, transportation and disposal agreements, our natural gas and NGL purchase agreements, Anadarko’s note payable to us, our omnibus agreement, the services and secondment agreement, the contribution agreements or the commodity price swap agreements.

CONTRACTUAL OBLIGATIONS

Our contractual obligations include, among other things, a revolving credit facility, other third-party long-term debt, capital obligations related to our expansion projects and various operating leases. Refer toNote 10—Debt and Interest Expense and Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for an update to our contractual obligations as of June 30, 2018.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than operating leases and standby letters of credit. The information pertaining to operating leases and our standby letters of credit required for this item is provided under Note 11—Commitments and Contingencies and Note 10—Debt and Interest Expense, respectively, included in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

RECENT ACCOUNTING DEVELOPMENTS

See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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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, condensate and NGLs. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of residue and/or NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced and the processed natural gas, or value of the natural gas, is returned to the producer, and since some of the gas is used and removed during processing, we compensate the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas used.

To mitigate a majority of our exposure to the commodity price risk inherent in our percent-of-proceeds, percent-of-product and keep-whole contracts, we currently have in place commodity price swap agreements with Anadarko covering activity at the DJ Basin complex and the MGR assets. On December 20, 2017, we renewed these commodity price swap agreements through December 31, 2018, with an effective date of January 1, 2018. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

We consider our exposure to commodity price risk associated with the above-described arrangements to be minimal given the existence of the commodity price swap agreements with Anadarko resulting in the relatively small amount of our operating income (loss) that is impacted by changes in market prices. Accordingly, we do not expect that a 10% increase or decrease in commodity prices would have a material impact on our operating income (loss), financial condition or cash flows for the next twelve months, excluding the effect of 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. The Federal Open Market Committee raised its target range for the federal funds rate three separate times during 2017 and twice in 2018. These increases, and any future increases, in the federal funds rate will ultimately result in an increase in our financing costs. As of June 30, 2018, we had no outstanding borrowings under the RCF (which bears interest at a rate based on LIBOR or, at our option, an alternative base rate). A 10% change in LIBOR would have resulted in no change in net income (loss) and the fair value of the borrowings under the RCF at June 30, 2018.

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

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of the Partnership’s general partner (for purposes of this Item 4, “Management”) performed an evaluation of the Partnership’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the 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 or submit 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, Management concluded that the Partnership’s disclosure controls and procedures were effective as of June 30, 2018.

Changes in Internal Control Over Financial Reporting. There were no changes in our internal control over financial reporting during the quarter ended June 30, 2018, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

Kerr-McGee Gathering LLC, a wholly owned subsidiary of the Partnership, is currently in negotiations with the U.S. Environmental Protection Agency (the “EPA”) and the Department of Justice with respect to alleged non-compliance with the leak detection and repair requirements of the federal Clean Air Act (“LDAR requirements”) at its Fort Lupton facility in the DJ Basin complex and WGR Operating, LP, another wholly owned subsidiary of the Partnership, is in negotiations with the EPA with respect to alleged non-compliance with LDAR requirements at its Granger, Wyoming facility. Although management cannot predict the outcome of settlement discussions in these matters, management believes that it is reasonably likely a resolution of these matters will result in a fine or penalty for each matter in excess of $100,000. Additionally, in May 2018, DBM, a wholly owned subsidiary of the Partnership, entered into a consent agreement and final order with the EPA with respect to alleged noncompliance with certain Risk Management Plan regulations under the Clean Air Act at the DBM complex and agreed to pay a penalty of $226,000.

Except as discussed above, 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, or for which disclosure is otherwise required by Item 103 of Regulation S-K.

Item 1A.  Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth under Part I, Item 1A in our Form 10-K for the year ended December 31, 2017, 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, 2017, 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.

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

PIK Class C units. During the six months ended June 30, 2018, in connection with the quarterly distribution for the Class C units, we issued the following additional Class C units (“PIK Class C units”) to APC Midstream Holdings, LLC, a subsidiary of Anadarko and the holder of the Class C units:

thousands except unit amounts Quarters Ended	PIK Class C Units	Implied Fair Value		Date of Distribution
2017
December 31	261,394	$	13,674	February 2018
2018
March 31	272,988	$	12,901	May 2018

No proceeds were received as consideration for the issuance of the PIK Class C units. The PIK Class C units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act. All outstanding Class C units will convert into common units on a one-for-one basis on March 1, 2020, unless we elect to convert such units earlier or Anadarko extends the conversion date. For more information, see Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

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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 Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2014, File No. 001-34046).
2.10#	Agreement and Plan of Merger, dated October 28, 2014, by and among Western Gas Partners, LP, Maguire Midstream LLC and Nuevo Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 28, 2014, File No. 001-34046).
2.11#	Purchase and Sale Agreement, dated as of March 2, 2015, by and among WGR Asset Holding Company LLC, Delaware Basin Midstream, LLC, Western Gas Partners, LP, and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 3, 2015, File No. 001-34046).
2.12#	Amendment No. 1 to Purchase and Sale Agreement, dated as of May 22, 2017, by and between WGR Asset Holding Company LLC and Delaware Basin Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 23, 2017, File No. 001-34046).

58

Exhibit Number	Description
2.13#	Contribution Agreement, dated as of February 24, 2016, 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 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 1, 2016, File No. 001-34046).
2.14#	Interest Swap and Purchase Agreement, dated February 9, 2017, among Western Gas Partners, LP, WGR Operating, LP, Delaware Basin JV Gathering, LLC, Williams Partners L.P., Williams Midstream Gas Services LLC and Appalachia Midstream Services, L.L.C. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 9, 2017, File No. 001-34046).
3.1	Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.2	Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
3.3	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
3.4	Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated February 22, 2017 (incorporated by reference to Exhibit 3.4 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 23, 2017, File No. 001-34046).
3.5	Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated November 9, 2017 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 9, 2017, File No. 001-34046).
3.6	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).
3.7	Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
4.1	Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
4.2	Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.3	First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.4	Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A to Exhibit 4.2, to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.5	Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
4.6	Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A 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	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).
4.8	Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A 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).
4.9	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).

59

Exhibit Number	Description
4.10	Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A 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).
4.11	Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
4.12	Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
4.13	Eighth Supplemental Indenture, dated as of July 12, 2016, 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 July 12, 2016, File No. 001-34046).
4.14	Form of 4.650% Senior Notes due 2026 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
4.15	Ninth Supplemental Indenture, dated as of March 2, 2018, 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 March 2, 2018, File No. 001-34046).
4.16	Form of 4.500% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
4.17	Form of 5.300% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
4.18	Registration Rights Agreement by and between Western Gas Partners, LP and the Purchasers party thereto, dated as of March 14, 2016, (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
4.19	Consent and Conversion Agreement, dated as of February 22, 2017, by and among Western Gas Partners, LP and the holders of the outstanding Series A Preferred Units party thereto (incorporated by reference to Exhibit 4.16 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 23, 2017, File No. 001-34046).
10.1*†	Amendment to Gas Gathering Agreement, dated May 10, 2018, between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP.
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**	Certification 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.
†	Portions of this exhibit, which was previously filed with the Securities and Exchange Commission, were omitted pursuant to a request for confidential treatment. The omitted portions were filed separately with the Securities and Exchange Commission.

60

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 hereunto duly authorized.

	WESTERN GAS PARTNERS, LP
August 1, 2018
	/s/ Benjamin M. Fink
	Benjamin M. Fink President and Chief Executive Officer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)
August 1, 2018
	/s/ Jaime R. Casas
	Jaime R. Casas Senior Vice President, Chief Financial Officer and Treasurer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)

61

EX-10.1

EXHIBIT 10.1

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT FOR THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY FILED WITH THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH ASTERISKS (***).

Contract #8840

AMENDMENT TO GAS GATHERING AGREEMENT

This AMENDMENT (“Amendment”) to the Gas Gathering Agreement between Kerr-McGee Gathering LLC (“Gatherer”) and Kerr-McGee Oil & Gas Onshore LP (“Shipper”), dated July 1, 2010 (“Agreement”), is effective on March 1, 2018 (“Amendment Effective Date”). Gatherer and Shipper may each be referred to in the singular sense as a “Party” or in the collective sense as the “Parties.”

For additional consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree to amend the Agreement as follows:

1.Capitalized terms not defined in this Amendment have the same meaning as set forth in the Agreement.

2.Section 1 of the Commercial Terms is deleted in its entirety and replaced as follows:

Section 1. This Agreement commences on the Effective Date and terminates on the later to occur of: (a) the last day of the 120^th Month in which the North Core Minimum Monthly Volume applies; or (b) the termination date of the last effective SRC Service Level (including any extensions therein) pursuant to the Base Contract for Gas Processing between Shipper, Gatherer, and WGR Asset Holding Company LLC dated to be effective on August 1, 2017.

3.Section 2 of the Commercial Terms is amended by deleting the words “or Shipper’s affiliates” from the last line of Section 2.1(A).

4.Section 2 of the Commercial Terms is amended as follows by adding a new Section 2.1(C):

2.1(C). Shipper expressly dedicates to the performance of this Agreement: (i) all “North Core Dedicated Wells” described on Exhibit A-2; (ii) all Gas produced or producible from North Core Dedicated Wells; and (iii) all Gas produced or producible from Shipper-operated Wells within the North Core Dedicated Area that is owned or controlled by Shipper.

5. A new Section 3(E) is added to the Commercial Terms as follows:

3(E). North Core.

3(E)(1). Shipper shall pay Gatherer a monthly gathering fee (“North Core Gathering Fee”) computed as the product of: (a) the MMBtu equivalent of the North Core Receipt Point Volume for such Month multiplied by (b) the applicable gathering rates set forth in Section 3.C.1 of the Commercial Terms.

Contract #8840

3(E)(2). If the North Core Receipt Point Volume for a particular Month is less than the applicable North Core Minimum Monthly Volume for such Month (“North Core Volumetric Deficiency”), then Shipper shall, in addition to the North Core Gathering Fee for such Month, pay Gatherer a deficiency fee computed as the product of: (a) the MMBtu equivalent of North Core Volumetric Deficiency for such Month (based on the average MMBtu equivalent of the Gas actually delivered during such Month, or if no Gas is delivered during such Month, during the most recent Month during which Gas was delivered) multiplied by (b) the applicable gathering rates set forth in Section 3.C.1 of the Commercial Terms. This Section 3(E)(2) shall not be applicable after the last Day of the Month during which the sum of (a) Shipper’s aggregate North Core Receipt Point Volumes plus (b) Shipper’s aggregate North Core Volumetric Deficiency volumes for which deficiency fees have been remitted, exceeds *** Mcf.

3(E)(3). If the North Core Receipt Point Volume for a particular Month exceeds the applicable North Core Minimum Monthly Volume for such Month (“North Core Volumetric Excess”), then Gatherer shall carry forward and apply such North Core Volumetric Excess to reduce North Core Volumetric Deficiencies occurring in subsequent Months. For purposes of the carry forward and application set forth herein, each North Core Volumetric Excess: (i) will be carried forward and applied, in part or in full until fully eliminated, on a first-in first-out basis by reference to and in priority of the Month of its occurrence; (ii) will expire, and will no longer be carried forward, refunded, offset, recouped, or utilized in any manner, after the last Day of the ***^th Month following the Month of its occurrence; and (iii) as applied, either singly or in the aggregate with the application of other North Core Volumetric Excesses, may not exceed ***% of the applicable North Core Minimum Monthly Volume for such Month.

3(E)(4). If Gatherer is unable to accept delivery of the entirety of the North Core Receipt Point Volume during a particular Month due to unavailability of gathering capacity on the System, and such unavailability is not caused by Shipper or Shipper’s downstream marketing or transportation arrangements, then the North Core Volumetric Deficiency for such Month will be the positive difference (if any) of (i) the aggregate capacity available to gather the applicable North Core Minimum Monthly Volumes less (ii) the aggregate volume of North Core Receipt Point Volumes.

3(E)(5). The gathering and deficiency fees described in this Section 3(E) are applicable only to North Core Receipt Point Volumes, and Shipper shall not pay any gathering fees other than the gathering fees set forth in this Section 3(E) with respect to such North Core Receipt Point Volumes.

3(E)(6). Except as provided in Section 3(E)(9), Shipper’s payment obligations herein that are determined by reference to the North Core Minimum Monthly Volume shall not be subject to downward adjustment for any reason, including Shipper’s conveyance or assignment to a third party of an interest in the North Core Dedicated Area or a North Core Dedicated Well, shut in or abandonment of a North Core Dedicated Well, cessation of production from a North Core Dedicated Well resulting from future rules, orders or laws of governmental, judicial, or regulatory authorities (federal, state or local) or the actions or omissions of such governmental, judicial, or regulatory authorities, or any event or condition of Shipper’s Force Majeure.

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Contract #8840

3(E)(7). Notwithstanding anything to the contrary in the Agreement, Shipper may elect to terminate the entirety of the commercial terms set forth in this Section 3(E), other than the terms of this Section 3(E)(7), by delivering written notice to Gatherer on or before February 28, 2019. Upon such termination Shipper shall have no further obligation to deliver the North Core Minimum Monthly Volume or to make payment pursuant to Section 3(E)(2), and Shipper shall reimburse Gatherer for all non-recoverable capital costs actually incurred as of the date of such termination (plus all post-termination capital costs related to winding down, demobilization, and payment for materials ordered prior to termination) in connection with Gatherer’s construction and installation of facilities to gather Shipper’s production within the North Core Project Area, provided that the amount of such reimbursement shall not exceed $*** if notice of termination is given on or before August 31, 2018, and shall not exceed $*** if notice of termination is given after August 31, 2018 and on or before February 28, 2019. In addition to Shipper’s reimbursement of Gatherer’s non-recoverable capital costs as set forth in this Section 3(E)(7), Shipper shall also pay Gatherer an amount equal to ***% of such non-recoverable capital costs. Gatherer shall deliver an invoice and supporting documentation to Shipper for all reimbursements pursuant to this Section 3(E)(7), and Shipper shall remit payment of such reimbursements on or before the 30^th day following receipt of such invoice.

3(E)(8). Notwithstanding anything to the contrary in the Agreement, (i) if Shipper is unable, in whole or in part, to drill or complete additional wells within the North Core Project Area; or (ii) if Gatherer is unable, in whole or in part, to connect to, or gather Gas from, additional wells within the North Core Project Area, in either case as a result of future rules, orders or laws of governmental, judicial, or regulatory authorities (federal, state or local) or the actions or omissions of such governmental, judicial, or regulatory authorities, then the affected Party may deliver written notice (“Notice”) to the other Party of such inability. On or before the 30^th Day following delivery of such Notice by either Party, Shipper shall provide Gatherer its projected volumes from the North Core Project Area for the period commencing on the first Day of the Month following the Month in which the Notice is provided and ending on the last day of the 120^th Month for which Shipper is obligated to deliver the North Core Minimum Monthly Volume.

3(E)(9). On or before the first day of the Month following the 90th Day following Gatherer’s receipt of Shipper’s projected volumes pursuant to Section 3(E)(8), Gatherer shall calculate a before-tax internal rate of return from the Amendment Effective Date to the last day of the 120^th Month for which Shipper is obligated to deliver the North Core Minimum Monthly Volume, based upon: (i) actual free cash flow from the Amendment Effective Date to the last Day of the Month in which the Notice was provided, computed as gross revenues received by Gatherer from Shipper within the North Core Project Area, net of associated operating expenditures, ad valorem taxes and capital expenditures; and (ii) projected free cash flow from the first Day of the Month following the Month in which the Notice was provided to the last day of such 120^th Month, computed as gross revenues from within the North Core Project Area based upon Shipper’s projected volumes, net of associated operating expenditures, ad valorem taxes and capital investment. If such calculated before-tax internal rate of return is more or less than ***%, then the Parties shall amend Shipper’s North Core Minimum Monthly Volume obligation set forth in Exhibit B-2 to reflect prospective North Core Minimum Monthly Volume obligations for all Months after the Month in which the

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Contract #8840

Notice was provided that result in Gatherer’s before-tax internal rate of return from the Amendment Effective Date to the last Day of such 120^th Month being equal to ***%.

6. The following defined terms are added to the General Terms and Conditions:

“North Core Dedicated Area” has the meaning set forth on Exhibit A-2.

“North Core Dedicated Wells” has the meaning set forth on Exhibit A-2.

“North Core Gathering Fee” has the meaning set forth in Section 3(E)(1) of the Commercial Terms.

“North Core Minimum Monthly Volume” means the volume in Mcf set forth on Exhibit B-2 for the applicable Month and Year beginning on the first to occur of (i) the Month immediately following the first delivery of North Core Receipt Point Volume hereunder or (ii) November 1, 2020.

“North Core Project Area” means the lands within the bounds of T4N R67W 6^th PM, T4N R68W 6^th PM, T5N R67W 6^th PM, and T5N R68W 6^th PM (specifically excluding Sections 25, 26, and 27 of T4N R68W, 6^th PM).

“North Core Receipt Point Volume” means the volume in Mcf of Dedicated Production produced from North Core Dedicated Wells that is delivered and accepted at the Receipt Points.

“North Core Volumetric Deficiency” has the meaning set forth in Section 3(E)(2) of the Commercial Terms.

“North Core Volumetric Excess” has the meaning set forth in Section 3(E)(3) of the Commercial Terms.

“Notice” has the meaning set forth in Section 3(E)(8) of the Commercial Terms.

7.The defined terms “Dedicated Production” and “Wells” in the General Terms and Conditions are stricken in their entirety and replaced with the following:

“Dedicated Production” means all Gas now or hereinafter owned, controlled or produced by Shipper: (i) from all Dedicated Wells located within the Dedicated Area; (ii) from all Wilson Ranch Dedicated Wells located within the Wilson Ranch Dedicated Area; and (iii) from all North Core Dedicated Wells located within the North Core Dedicated Area; with the exception of Gas required for operations on the leasehold, pressure maintenance, and the fulfillment of Shipper’s obligations to Shipper’s lessor.

“Well” means an oil or gas well. For purposes of this Agreement, the location of a well is determined by reference to the location of its wellbore.

8.Exhibit A-2 “North Core Dedicated Wells and North Core Dedicated Area” is attached hereto and incorporated into the Agreement.

9.Exhibit B-2 “North Core Minimum Monthly Volume” is attached hereto and incorporated into the Agreement.

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Contract #8840

10.Except as amended herein, all other provisions of the Agreement remain in full effect as originally written or previously amended.

11.This Amendment shall be construed, enforced, and interpreted according to the laws of the State of Texas, without regard to the conflicts of law rules thereof.

12.The Agreement constitutes the entire agreement between and among the Parties regarding the subject matter herein.

13.The Parties may execute and deliver this Amendment in any number of counterparts, including facsimile and *.pdf format counterparts, each of which is deemed an original, but all of which constitute one and the same instrument.

[Execution Page Follows]

-5-

Contract #8840

The Parties have executed this AMENDMENT to be effective on the Amendment Effective Date.

GATHERER KERR-MCGEE GATHERING LLC		SHIPPER KERR-MCGEE OIL & GAS ONSHORE LP
By:	/s/ Gennifer Kelly	By:	/s/ Carrie Horton
Name:	Gennifer Kelly	Name:	Carrie Horton
Title:	Senior Vice President and Chief Operating Officer	Title:	Vice President, DJ Basin Development

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Contract #8840

EXHIBIT A-2

North Core Dedicated Wells

1.“North Core Dedicated Wells” means Shipper’s interests in all Wells connected to the System within the North Core Project Area, now or in the future, in which Shipper owns or controls Gas, in and to all depths and formations respecting such interests.

2.“North Core Dedicated Area” means the area within the greater of (a) a one-mile radius extending from each North Core Dedicated Well existing now or in the future or (b) a one-mile radius extending from any point on the System, as it exists now or in the future.

[End of Exhibit A-2]

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Contract #8840

EXHIBIT B-2

North Core Minimum Monthly Volume (Mcf)

	Year 1	Year 2	Year 3	Year 4	Year 5	Year 6	Year 7	Year 8	Year 9	Year 10
Month 1	***	***	***	***	***	***	***	***	***	***
Month 2	***	***	***	***	***	***	***	***	***	***
Month 3	***	***	***	***	***	***	***	***	***	***
Month 4	***	***	***	***	***	***	***	***	***	***
Month 5	***	***	***	***	***	***	***	***	***	***
Month 6	***	***	***	***	***	***	***	***	***	***
Month 7	***	***	***	***	***	***	***	***	***	***
Month 8	***	***	***	***	***	***	***	***	***	***
Month 9	***	***	***	***	***	***	***	***	***	***
Month 10	***	***	***	***	***	***	***	***	***	***
Month 11	***	***	***	***	***	***	***	***	***	***
Month 12	***	***	***	***	***	***	***	***	***	***

[End of Exhibit B]

-8-

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Benjamin M. Fink, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Western Gas Partners, LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 1, 2018

/s/ Benjamin M. Fink

Benjamin M. Fink

President and Chief Executive Officer

Western Gas Holdings, LLC

(as general partner of Western Gas Partners, LP)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Jaime R. Casas, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Western Gas Partners, LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, includingits consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 1, 2018

/s/ Jaime R. Casas

Jaime R. Casas

Senior Vice President, Chief Financial Officer and Treasurer

Western Gas Holdings, LLC

(as general partner of Western Gas Partners, LP)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, Benjamin M. Fink, President and Chief Executive Officer of Western Gas Holdings, LLC, the general partner of Western Gas Partners, LP (the “Partnership”) and Jaime R. Casas, Senior Vice President, Chief Financial Officer and Treasurer of Western Gas Holdings, LLC, certify to the best of our knowledge that:

(1) the Quarterly Report on Form 10-Q of the Partnership for the period ending June 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

August 1, 2018
	/s/ Benjamin M. Fink
	Benjamin M. Fink President and Chief Executive Officer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)
August 1, 2018
	/s/ Jaime R. Casas
	Jaime R. Casas Senior Vice President, Chief Financial Officer and Treasurer Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)

The foregoing certifications are being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, are not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and are not incorporated by reference into any filing of the Partnership, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 30, 2018
Document And Entity Information [Abstract]
Trading Symbol	WES
Entity Registrant Name	Western Gas Partners LP
Entity Central Index Key	0001414475
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Units Outstanding		152,609,285

XML

Consolidated Statements of Operations - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017
Revenues and Other
Revenues and other		$ 435,949	$ 525,450	$ 873,117		$ 1,041,643
Equity income, net – affiliates	[1]	39,218	21,728	59,642		41,189
Operating expenses
Cost of product	[2]	68,149	203,277	145,948		392,636
Operation and maintenance	[2]	100,628	76,148	188,907		149,908
General and administrative	[2]	14,035	10,585	28,167		23,244
Property and other taxes		11,754	11,924	24,136		24,218
Depreciation and amortization		78,792	74,031	155,634		143,733
Impairments		127,243	3,178	127,391		167,920
Total operating expenses		400,601	379,143	670,183		901,659
Gain (loss) on divestiture and other, net	[3]	170	15,458	286	[4]	134,945	[4]
Proceeds from business interruption insurance claims		0	24,115	0		29,882
Operating income (loss)		74,736	207,608	262,862		346,000
Interest income - affiliates	[5]	4,225	4,225	8,450		8,450
Interest expense	[6]	(44,389)	(35,746)	(83,672)		(71,250)
Other income (expense), net		1,229	253	2,011		683
Income (loss) before income taxes		35,801	176,340	189,651		283,883
Income tax (benefit) expense		282	843	1,784		4,395
Net income (loss)		35,519	175,497	187,867		279,488
Net income attributable to noncontrolling interest		2,811	2,046	5,796		4,148
Net income (loss) attributable to Western Gas Partners, LP		32,708	173,451	182,071		275,340
Limited partners' interest in net income (loss):
General partner interest in net (income) loss	[7]	(84,176)	(76,365)	(167,615)		(144,527)
Series A Preferred Units [Member]
Limited partners' interest in net income (loss):
Limited partners’ interest in net income (loss)	[8]	0	(14,199)	0		(42,373)
Common and Class C Units [Member]
Limited partners' interest in net income (loss):
Limited partners’ interest in net income (loss)	[7]	51,468	(82,887)	(14,456)		(88,440)
Common Units [Member]
Limited partners' interest in net income (loss):
Limited partners’ interest in net income (loss)	[8]	$ 48,417	$ (73,383)	$ (9,906)		$ (75,097)
Net income (loss) per common unit – basic and diluted	[9],[10]	$ (0.32)	$ 0.49	$ 0.06		$ 0.53
Service Revenues - Fee Based [Member]
Revenues and Other
Revenues and other		$ 359,544		$ 697,963
Service Revenues - Product Based [Member]
Revenues and Other
Revenues and other		22,105		44,698
Product Sales [Member]
Revenues and Other
Revenues and other		54,077		130,014
Affiliates [Member]
Revenues and Other
Revenues and other	[1]	238,029	$ 316,313	479,091		$ 631,468
Operating expenses
Cost of product	[1]	12,609	21,607	32,853		37,595
Operation and maintenance	[11]	23,437	18,462	43,685		35,551
General and administrative	[12]	11,178	9,365	22,792		18,900
Total operating expenses		47,224	49,434	99,330		92,046
Interest expense	[13]	0	0	0		(71)
Affiliates [Member] | Service Revenues - Fee Based [Member]
Revenues and Other
Revenues and other		192,488	154,984	378,489		327,298
Affiliates [Member] | Service Revenues - Product Based [Member]
Revenues and Other
Revenues and other		285	0	527		0
Affiliates [Member] | Product Sales [Member]
Revenues and Other
Revenues and other		45,256	161,329	100,075		304,170
Third Parties [Member]
Revenues and Other
Revenues and other		197,920	209,137	394,026		410,175
Operating expenses
Interest expense		(44,389)	(35,746)	(83,672)		(71,179)
Third Parties [Member] | Service Revenues - Fee Based [Member]
Revenues and Other
Revenues and other		167,056	144,451	319,474		279,951
Third Parties [Member] | Service Revenues - Product Based [Member]
Revenues and Other
Revenues and other		21,820	0	44,171		0
Third Parties [Member] | Product Sales [Member]
Revenues and Other
Revenues and other		8,821	63,495	29,939		127,179
Third Parties [Member] | Other [Member]
Revenues and Other
Revenues and other		$ 223	$ 1,191	$ 442		$ 3,045

[1] Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $12.6 million and $32.9 million for the three and six months ended June 30, 2018, respectively, and $21.6 million and $37.6 million for the three and six months ended June 30, 2017, respectively. Operation and maintenance includes charges from Anadarko of $23.4 million and $43.7 million for the three and six months ended June 30, 2018, respectively, and $18.5 million and $35.6 million for the three and six months ended June 30, 2017, respectively. General and administrative includes charges from Anadarko of $11.2 million and $22.8 million for the three and six months ended June 30, 2018, respectively, and $9.4 million and $18.9 million for the three and six months ended June 30, 2017, respectively. See Note 6.

[3] Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

[4] Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

[5] Represents interest income recognized on the note receivable from Anadarko.

[6] Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and six months ended June 30, 2017, respectively. See Note 10.

[7] Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 5.

[8] Adjusted to reflect amortization of the beneficial conversion features.

[9] See Note 5 for the calculation of net income (loss) per common unit.

[10] The impact of Class C units would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the three and six months ended June 30, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

[11] Represents expenses incurred on and subsequent to the date of the acquisition of 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.

[12] Represents general and administrative expense incurred on and subsequent to the date of the acquisition of 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 Anadarko Incentive Plan within this Note 6).

[13] Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3 and Note 10).

XML

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Cost of product	[1]	$ 68,149	$ 203,277	$ 145,948	$ 392,636
Operation and maintenance	[1]	100,628	76,148	188,907	149,908
General and administrative	[1]	14,035	10,585	28,167	23,244
Interest expense	[2]	(44,389)	(35,746)	(83,672)	(71,250)
Affiliates [Member]
Cost of product	[3]	12,609	21,607	32,853	37,595
Operation and maintenance	[4]	23,437	18,462	43,685	35,551
General and administrative	[5]	11,178	9,365	22,792	18,900
Interest expense	[6]	$ 0	$ 0	$ 0	$ (71)

[1] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $12.6 million and $32.9 million for the three and six months ended June 30, 2018, respectively, and $21.6 million and $37.6 million for the three and six months ended June 30, 2017, respectively. Operation and maintenance includes charges from Anadarko of $23.4 million and $43.7 million for the three and six months ended June 30, 2018, respectively, and $18.5 million and $35.6 million for the three and six months ended June 30, 2017, respectively. General and administrative includes charges from Anadarko of $11.2 million and $22.8 million for the three and six months ended June 30, 2018, respectively, and $9.4 million and $18.9 million for the three and six months ended June 30, 2017, respectively. See Note 6.

[2] Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and six months ended June 30, 2017, respectively. See Note 10.

[3] Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[4] Represents expenses incurred on and subsequent to the date of the acquisition of 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.

[5] Represents general and administrative expense incurred on and subsequent to the date of the acquisition of 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 Anadarko Incentive Plan within this Note 6).

[6] Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3 and Note 10).

XML

Consolidated Balance Sheets - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents		$ 53,235	$ 78,814
Accounts receivable, net	[1]	167,175	160,432
Other current assets	[2]	26,728	14,816
Total current assets		247,138	254,062
Note receivable - Anadarko		260,000	260,000
Property, plant and equipment
Cost		8,618,993	7,864,535
Less accumulated depreciation		2,405,419	2,133,644
Net property, plant and equipment		6,213,574	5,730,891
Goodwill		416,160	416,160
Other intangible assets		761,054	775,269
Equity investments		754,300	566,211
Other assets	[3]	14,384	11,757
Total assets		8,666,610	8,014,350
Current liabilities
Accounts and imbalance payables	[4]	331,447	349,801
Accrued ad valorem taxes		26,318	26,633
Accrued liabilities	[5]	131,352	47,899
Total current liabilities		489,117	424,333
Long-term liabilities
Long-term debt		4,177,353	3,464,712
Deferred income taxes		8,753	7,409
Asset retirement obligations		151,412	143,394
Other liabilities	[6]	138,493	3,491
Total long-term liabilities		4,476,011	3,619,006
Total liabilities		4,965,128	4,043,339
Equity and partners' capital
General partner units (2,583,068 units issued and outstanding at June 30, 2018, and December 31, 2017)		191,564	179,232
Total partners' capital		3,639,420	3,909,282
Noncontrolling interest		62,062	61,729
Total equity and partners' capital		3,701,482	3,971,011
Total liabilities, equity and partners' capital		8,666,610	8,014,350
Common Units [Member]
Equity and partners' capital
Common units and Class C units		2,666,799	2,950,010
Class C Units [Member]
Equity and partners' capital
Common units and Class C units	[7]	$ 781,057	$ 780,040

[1] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $16.1 million and $36.3 million as of June 30, 2018, and December 31, 2017, respectively.

[2] Other current assets includes affiliate amounts of $9.3 million and zero as of June 30, 2018, and December 31, 2017, respectively.

[3] Other assets includes affiliate amounts of $0.2 million and zero as of June 30, 2018, and December 31, 2017, respectively.

[4] Accounts and imbalance payables includes affiliate amounts of zero and $0.3 million as of June 30, 2018, and December 31, 2017, respectively.

[5] Accrued liabilities includes affiliate amounts of $2.3 million and $0.2 million as of June 30, 2018, and December 31, 2017, respectively.

[6] Other liabilities includes affiliate amounts of $48.4 million and $0.7 million as of June 30, 2018, and December 31, 2017, respectively.

[7] The Class C units will convert into common units on a one-for-one basis on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 5.

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
General partner units issued		2,583,068	2,583,068
General partner units outstanding		2,583,068	2,583,068
Accounts receivable, net	[1]	$ 167,175	$ 160,432
Other current assets	[2]	26,728	14,816
Other assets	[3]	14,384	11,757
Accounts and imbalance payables	[4]	331,447	349,801
Accrued liabilities	[5]	131,352	47,899
Other liabilities	[6]	138,493	3,491
Affiliates [Member]
Accounts receivable, net		16,100	36,300
Other current assets		9,300	0
Other assets		200	0
Accounts and imbalance payables		0	300
Accrued liabilities		2,300	200
Other liabilities		$ 48,400	$ 700
Common Units [Member]
Units issued		152,609,285	152,602,105
Units outstanding		152,609,285	152,602,105
Class C Units [Member]
Units issued		13,778,265	13,243,883
Units outstanding		13,778,265	13,243,883
Class C units, common units issued upon conversion		1

[1] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $16.1 million and $36.3 million as of June 30, 2018, and December 31, 2017, respectively.

[2] Other current assets includes affiliate amounts of $9.3 million and zero as of June 30, 2018, and December 31, 2017, respectively.

[3] Other assets includes affiliate amounts of $0.2 million and zero as of June 30, 2018, and December 31, 2017, respectively.

[4] Accounts and imbalance payables includes affiliate amounts of zero and $0.3 million as of June 30, 2018, and December 31, 2017, respectively.

[5] Accrued liabilities includes affiliate amounts of $2.3 million and $0.2 million as of June 30, 2018, and December 31, 2017, respectively.

[6] Other liabilities includes affiliate amounts of $48.4 million and $0.7 million as of June 30, 2018, and December 31, 2017, respectively.

XML

Consolidated Statement of Equity and Partners' Capital - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands		Total	Common Units [Member]	Class C Units [Member]	General Partner Units [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2017		$ 3,971,011	$ 2,950,010	$ 780,040	$ 179,232	$ 61,729
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)		187,867	11,528	2,928	167,615	5,796
Above-market component of swap agreements with Anadarko	[1]	28,121	28,121
Amortization of beneficial conversion feature of Class C units		0	(1,622)	1,622
Distributions to noncontrolling interest owner		(6,421)				(6,421)
Distributions to unitholders		(437,719)	(283,077)		(154,642)
Contributions of equity-based compensation from Anadarko		2,792	2,737		55
Other		210	210
Balance at Jun. 30, 2018		3,701,482	2,666,799	781,057	191,564	62,062
Increase (Decrease) in Partners' Capital [Roll Forward]
Cumulative effect of accounting change	[2]	$ (44,379)	$ (41,108)	$ (3,533)	$ (696)	$ 958

[1] See Note 6.

[2] See Note 1.

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2018		Jun. 30, 2017
Cash flows from operating activities
Net income (loss)		$ 187,867		$ 279,488
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		155,634		143,733
Impairments		127,391		167,920
Non-cash equity-based compensation expense		3,017		2,393
Deferred income taxes		1,523		3,767
Accretion and amortization of long-term obligations, net		2,626		2,139
Equity income, net – affiliates	[1]	(59,642)		(41,189)
Distributions from equity investment earnings – affiliates		48,396		42,202
(Gain) loss on divestiture and other, net	[2],[3]	(286)		(134,945)
Lower of cost or market inventory adjustments		151		140
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		(7,009)		9,363
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net		40,573		(41,975)
Change in other items, net		14,670		116
Net cash provided by operating activities		514,911		433,152
Cash flows from investing activities
Capital expenditures		(650,096)		(260,480)
Investments in equity affiliates		(27,490)		(287)
Distributions from equity investments in excess of cumulative earnings – affiliates		12,505	[4]	9,221
Proceeds from property insurance claims		0		22,977
Net cash used in investing activities		(826,653)		(363,131)
Cash flows from financing activities
Borrowings, net of debt issuance costs		1,337,539		159,989
Repayments of debt		(630,000)		0
Increase (decrease) in outstanding checks		(5,357)		(2,763)
Proceeds from the issuance of common units, net of offering expenses		0		(183)
Distributions to unitholders	[5]	(437,719)		(381,771)
Distributions to noncontrolling interest owner		(6,421)		(6,375)
Net contributions from (distributions to) Anadarko		0		30
Above-market component of swap agreements with Anadarko	[5]	28,121		28,670
Net cash provided by (used in) financing activities		286,163		(239,749)
Net increase (decrease) in cash and cash equivalents		(25,579)		(169,728)
Cash and cash equivalents at beginning of period		78,814		357,925
Cash and cash equivalents at end of period		53,235		188,197
Supplemental disclosures
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko		0		(4,094)
Net distributions to (contributions from) Anadarko of other assets		0		(376)
Interest paid, net of capitalized interest		62,924		68,396
Taxes paid (reimbursements received)		(87)		189
Accrued capital expenditures		182,212		100,038
Fair value of properties and equipment from non-cash third party transactions	[6]	0		551,453
Affiliates [Member]
Cash flows from investing activities
Contributions in aid of construction costs from affiliates		0		1,343
Acquisitions		0		(3,910)
Cash flows from financing activities
Settlement of the Deferred purchase price obligation - Anadarko	[6]	0		(37,346)
Distributions to unitholders	[7]	(251,368)		(213,572)
Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets		0		(376)
Third Parties [Member]
Cash flows from investing activities
Acquisitions		(161,858)		(155,287)
Proceeds from the sale of assets		$ 286		$ 23,292

[1] Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[2] Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

[3] Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

[4] Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual investment basis.

[5] See Note 6.

[6] See Note 3.

[7] Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

XML

Description of Business and Basis of Presentation

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Description of Business and Basis of Presentation

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership (“MLP”) formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop and operate midstream 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”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP 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. WGP has no independent operations or material assets other than owning the partnership interests in the Partnership (see Holdings of Partnership equity in Note 5). 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 subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including 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”), Front Range Pipeline LLC (“FRP”), Whitethorn Pipeline Company LLC (“Whitethorn LLC”) and Cactus II Pipeline LLC (“Cactus II”). See Note 3. The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “MGR assets” refers to the Red Desert complex and the Granger straddle plant.

The Partnership is engaged in the business of gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, natural gas liquids (“NGLs”) and crude oil; and gathering and disposing of produced water. In addition, in its capacity as a processor of natural gas, the Partnership also buys and sells natural gas, NGLs and condensate on behalf of itself and as agent for its customers under certain of its contracts. The Partnership provides these midstream services for Anadarko, as well as for third-party producers and customers. As of June 30, 2018, the Partnership’s assets and investments consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems (1)	12	3	3	2
Treating facilities	19	3	—	3
Natural gas processing plants/trains	20	4	—	2
NGL pipelines	2	—	—	3
Natural gas pipelines	5	—	—	—
Oil pipelines	—	1	—	2

⁽¹⁾  Includes the DBM water systems.

These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. Mentone Train I, a processing train at the DBM complex, is expected to commence operations at the end of the third quarter of 2018.

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

Basis of presentation. The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements for entities not wholly owned:

	Percentage Interest
Equity investments (1)
Fort Union	14.81	%
White Cliffs	10	%
Rendezvous	22	%
Mont Belvieu JV	25	%
TEP	20	%
TEG	20	%
FRP	33.33	%
Whitethorn	20	%
Cactus II	15	%
Proportionate consolidation (2)
Marcellus Interest systems	33.75	%
Newcastle system	50	%
Springfield system	50.1	%
Full consolidation
Chipeta (3)	75	%

⁽¹⁾  Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.

⁽²⁾  The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.

⁽³⁾  The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

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.

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 2017 Form 10-K, as filed with the SEC on February 16, 2018. Management believes that the disclosures made are adequate to make the information not misleading.

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

Presentation of Partnership assets. The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by the Partnership as of June 30, 2018 (see Note 8). Because Anadarko controls the Partnership through its control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko are 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 Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.

Use of estimates.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. 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.

Shutdown of gathering systems. In May 2018, after assessing a number of factors, with safety and protection of the environment as the primary focus, the Partnership decided to take the Kitty Draw gathering system in Wyoming (part of the Hilight system) and the Third Creek gathering system in Colorado (part of the DJ Basin complex) permanently out of service. Results for the three and six months ended June 30, 2018, reflect (i) an accrual of $10.9 million in anticipated costs associated with the shutdown of the systems, recorded as a reduction in affiliate Product sales in the consolidated statements of operations and (ii) impairment expense of $127.2 million associated with reducing the net book value of the gathering systems and additional asset retirement obligation.

Insurance recoveries. In December 2015, there was an initial fire and secondary explosion at the processing facility within the Delaware Basin Midstream, LLC (“DBM”) complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. During the six months ended June 30, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to a change in the Partnership’s estimate of the amount that would be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, the Partnership reached a settlement with insurers and final proceeds were received. During the six months ended June 30, 2017, the Partnership received $52.9 million in cash proceeds from insurers, including $29.9 million in proceeds from business interruption insurance claims and $23.0 million in proceeds from property insurance claims.

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Partnership adopted this ASU using a retrospective approach on January 1, 2018, and the adoption did not impact the consolidated financial statements.

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

Revenue from contracts with customers (Topic 606). The Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Topic 606”) on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The cumulative effect adjustment that was recognized in the opening balance of equity and partners’ capital was a decrease of $44.4 million. The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition (Topic 605) (“Topic 605”).

Effective January 1, 2018, the Partnership changed its accounting policy for revenue recognition as detailed below:

• Fee-based gathering / processing. Under Topic 605, fee revenues were recognized based on the rate in effect for the month of service, even when certain fees were charged on an upfront or limited-term basis. In addition, deficiency fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, revenues continue to be recognized based on the rate in effect when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Under Topic 606, the Partnership recognizes revenue associated with upfront or limited-term fees over the expected period of customer benefit, which is generally the life of the related properties. In addition, deficiency fees are estimated and recognized during the performance period as the services are performed for the customer’s delivered volumes. Under Topic 606, differences between Service revenues – fee based recognized and amounts billed to customers are recognized as contract assets or contract liabilities, as appropriate. This results in a change in the timing of revenue and changes to net income as a result of the revenue contract’s consideration provisions.

• Cost of service rate adjustments. Under Topic 605, revenue was recognized based on the amounts billed to customers each period. Under Topic 606, fixed minimum volume commitment demand fees and variable fees that are also billed on these minimum volumes are recognized as Service revenues – fee based on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and, as a result, a cumulative catch-up revenue adjustment related to the services already provided under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate. Fees received on volumes in excess of the minimum volumes are recognized as Service revenues – fee based as service is provided to the customer based on the billing rate in effect for the performance period. This revenue recognition timing does not affect billings to customers, and differences between amounts billed and revenue recognized are recorded as contract assets or liabilities, as appropriate.

• Aid in construction. Under Topic 605, aid in construction reimbursements were reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Under Topic 606, reimbursement of capital costs received from customers is reflected as a contract liability (deferred revenue) upon receipt. The contract liability is amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

• Percent-of-proceeds gathering / processing. Under Topic 605, the Partnership recognized cost of product expense when the product was purchased from a producer to whom it provides services, and the Partnership recognized revenue when the product was sold to Anadarko or a third party. Under Topic 606, in some instances, where all or a percentage of the proceeds from the sale must be returned to the producer, the net margin from the purchase and sale transactions is presented net within Service revenues – product based because the Partnership is acting as the producer’s agent in the product sale.

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

• Noncash consideration - keep-whole and percent-of-product agreements. Under Topic 605, the Partnership recognized revenues only upon the sale of the related products. Under Topic 606, the Partnership recognizes Service revenues – product based for the products received as noncash consideration in exchange for the services provided, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas cost. Under Topic 606, revenue from product sales is recognized, along with cost of product expense related to the sale, when the product is sold to Anadarko or a third party.

• Wellhead purchase / sale incorporated into gathering / processing. Under Topic 605, the natural gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenues. Under Topic 606, the fees charged to the producer under this contract type are recognized as adjustments to the amount recognized in cost of product expense instead of revenues when such fees relate to services performed after control of the product transfers to the Partnership.

The following tables summarize the impact of adopting Topic 606 on the impacted line items within the consolidated statements of operations and the consolidated balance sheet. The differences between revenue as reported following Topic 606 and revenue as it would have been reported under Topic 605 are due to the changes described above.

	Three Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	359,544	$	358,209	$	1,335
Service revenues – product based	22,105		—		22,105
Product sales	54,077		319,233		(265,156		)
Expenses
Cost of product	68,149		312,329		(244,180		)
Operation and maintenance	100,628		100,632		(4		)
Depreciation and amortization	78,792		78,125		667
Impairments	127,243		127,198		45
Income tax (benefit) expense	282		272		10
Net income attributable to noncontrolling interest	2,811		2,054		757
Net income (loss) attributable to Western Gas Partners, LP	32,708		31,719		989

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

	Six Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	697,963	$	700,547	$	(2,584	)
Service revenues – product based	44,698		—		44,698
Product sales	130,014		611,524		(481,510		)
Expenses
Cost of product	145,948		587,295		(441,347		)
Operation and maintenance	188,907		188,771		136
Depreciation and amortization	155,634		154,278		1,356
Impairments	127,391		127,346		45
Income tax (benefit) expense	1,784		1,781		3
Net income attributable to noncontrolling interest	5,796		4,552		1,244
Net income (loss) attributable to Western Gas Partners, LP	182,071		182,904		(833		)

	June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Assets
Other current assets	$	26,728	$	17,388	$	9,340
Net property, plant and equipment	6,213,574		6,117,733		95,841
Other assets	14,384		14,138		246
Liabilities
Accrued liabilities	131,352		124,913		6,439
Deferred income taxes	8,753		8,930		(177		)
Other liabilities	138,493		2,810		135,683
Equity and partners’ capital
Total equity and partners’ capital	3,701,482		3,738,000		(36,518		)

New accounting standards issued but not yet adopted.ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Partnership plans to make certain elections allowing the Partnership not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements and not to recognize ROU assets or lease liabilities for short-term leases. The Partnership continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU, which is expected to primarily impact other assets and other liabilities. To facilitate compliance with this ASU, the Partnership is implementing new accounting software and continuing to evaluate its systems, processes and internal controls during 2018. The Partnership will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Partnership does not expect to adjust comparative period financial statements.

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

Revenue and cost of product. Upon adoption of the new revenue recognition standard on January 1, 2018 (discussed in Recently adopted accounting standards), the Partnership changed its accounting policy for revenue recognition as described below.

The Partnershipprovides gathering, processing, treating, transportation and disposal services pursuant to a variety of contracts. Under these arrangements, the Partnership receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in Service revenues and Product sales in the consolidated statements of operations. Payment is generally received from the customer in the month following the service or delivery of the product. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Service revenues – fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation and disposal of natural gas, NGLs, condensate, crude oil and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed upon completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties.

The Partnership also receives Service revenues – fee based from contracts that have minimum volume commitment demand fees and fees that require periodic rate redeterminations based upon the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate.

Service revenues – product based includes service revenues from percent-of-proceeds gathering and processing contracts that are recognized net of the cost of product for purchases from the Partnership’s customers since it is acting as the agent in the product sale. Keep-whole and percent-of-product agreements result in Service revenues – product based being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. Noncash consideration for these services is valued at the time the services are provided. Revenue from product sales is also recognized, along with the cost of product expense related to the sale, when the product received as noncash consideration is sold to either Anadarko or a third party.

The Partnership also purchases natural gas volumes from producers at the wellhead or from a production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. When the fees relate to services performed after control of the product has transferred to the Partnership, the fees are treated as a reduction of the purchase cost. Revenue from product sales is recognized, along with cost of product expense related to the sale, when the purchased product is sold to either Anadarko or a third party.

The Partnership receives aid in construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs, etc.) under certain service contracts. Aid in construction reimbursements are reflected as a contract liability upon receipt and amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

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Revenue from Contracts with Customers

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers

2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes the Partnership’s revenue from contracts with customers:

thousands	Three Months Ended   June 30, 2018			Six Months Ended   June 30, 2018
Revenue from customers
Service revenues – fee based	$	359,544		$	697,963
Service revenues – product based	22,105			44,698
Product sales	55,449			132,629
Total revenue from customers	437,098			875,290
Revenue from other than customers
Net gains (losses) on commodity price swap agreements	(1,372		)	(2,615		)
Other	223			442
Total revenues and other	$	435,949		$	873,117

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $267.1 million and $244.4 million as of June 30, 2018, and December 31, 2017, respectively.

Contract assets primarily relate to accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed. The following table summarizes the current period activity related to contract assets from contracts with customers:

thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	5,129
Amounts transferred to Accounts receivable, net from contract assets recognized in the adoption effect (1)	(2,677		)
Additional estimated revenues recognized (2)	7,134
Balance at June 30, 2018	$	9,586
Contract assets at June 30, 2018
Other current assets	$	9,340
Other assets	246
Total contract assets from contracts with customers	$	9,586

⁽¹⁾  Includes $(0.2) million for the three months ended June 30, 2018.

⁽²⁾  Includes $3.7 million for the three months ended June 30, 2018.

2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)

Contract liabilities primarily relate to (i) fees that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of customer benefit, (ii) fixed and variable fees under cost of service contracts that are received from customers for which revenue recognition is deferred and (iii) aid in construction payments received from customers that must be recognized over the expected period of customer benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:

thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	120,717
Cash received or receivable, excluding revenues recognized during the period (1)	41,076
Revenues recognized during the period that were included in the adoption effect (2)	(2,009		)
Balance at June 30, 2018	$	159,784
Contract liabilities at June 30, 2018
Accrued liabilities	$	24,101
Other liabilities	135,683
Total contract liabilities from contracts with customers	$	159,784

⁽¹⁾  Includes $12.5 million for the three months ended June 30, 2018.

⁽²⁾  Includes $(1.0) million for the three months ended June 30, 2018.

Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that are unsatisfied (or partially unsatisfied) as of June 30, 2018, are reflected in the following table. The Partnership applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a small portion of expected future consolidated revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and in some cases variable commodity prices for those volumes.

thousands
Remainder of 2018	$	220,037
2019	492,806
2020	542,214
2021	527,151
2022	527,103
Thereafter	2,168,028
Total	$	4,477,339

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Acquisitions and Divestitures

3. ACQUISITIONS AND DIVESTITURES

Whitethorn LLC acquisition. In June 2018, the Partnership acquired a 20% interest in Whitethorn LLC, which owns the crude oil and condensate pipeline that originates in Midland, Texas and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with its investment in Whitethorn, the Partnership will share proportionally in the commercial activities. The Partnership acquired its 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 8.

Cactus II acquisition. In June 2018, the Partnership acquired a 15% interest in Cactus II, which will own a crude oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline is under construction and expected to become operational in the fourth quarter of 2019. The Partnership acquired its 15% interest from a third party via an $11.3 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 8.

Property exchange. On March 17, 2017, the Partnership acquired an additional 50% interest in the Delaware Basin JV Gathering LLC (“DBJV”) system (the “Additional DBJV System Interest”) from a third party in exchange for (a) the Partnership’s 33.75% non-operated interest in two natural gas gathering systems located in northern Pennsylvania (the “Non-Operated Marcellus Interest”), commonly referred to as the Liberty and Rome systems, and (b) $155.0 million of cash consideration (collectively, the “Property Exchange”). The Partnership previously held a 50% interest in, and operated, the DBJV system.

The Property Exchange was reflected as a nonmonetary transaction whereby the acquired Additional DBJV System Interest was recorded at the fair value of the divested Non-Operated Marcellus Interest plus the $155.0 million of cash consideration. The Property Exchange resulted in a net gain of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributable to the Property Exchange were included in the consolidated statements of operations beginning on the acquisition date in the first quarter of 2017.

DBJV acquisition - Deferred purchase price obligation - Anadarko.Prior to the Partnership’s agreement with Anadarko to settle its deferred purchase price obligation early, the consideration that would have been paid by the Partnership for the March 2015 acquisition of DBJV from Anadarko consisted of a cash payment to Anadarko due on March 31, 2020. In May 2017, the Partnership reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.

Helper and Clawson systems divestiture. During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of $16.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

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Partnership Distributions

6 Months Ended

Jun. 30, 2018

Distributions Made to Members or Limited Partners [Abstract]

Partnership Distributions

4. PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors of the Partnership’s general partner (the “Board of Directors”) declared the following cash distributions to the Partnership’s common and general partner unitholders for the periods presented:

thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
2017
March 31	$	0.875	$	188,753	May 2017
June 30	0.890		207,491		August 2017
September 30	0.905		212,038		November 2017
December 31	0.920		216,586		February 2018
2018
March 31	$	0.935	$	221,133	May 2018
June 30 (1)	0.950		225,691		August 2018

⁽¹⁾  The Board of Directors declared a cash distribution to the Partnership’s unitholders for the second quarter of 2018 of $0.950 per unit, or $225.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution is payable on August 13, 2018, to unitholders of record at the close of business on August 1, 2018.

Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments or other agreements; or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. Working capital borrowings may only be those that, at the time of such borrowings, were intended to be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.

Class C unit distributions. The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on March 1, 2020 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted into common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a 6% discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value. See Note 5 for further discussion of the Class C units.

4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)

Series A Preferred unit distributions. As further described in Note 5, the Partnership issued Series A Preferred units representing limited partner interests in the Partnership to private investors in 2016. The Series A Preferred unitholders received quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis. Such converted common units were entitled to distributions made to common unitholders with respect to the quarter during which the applicable conversion occurred and did not include a prorated Series A Preferred unit distribution. For the quarter ended March 31, 2017, the Series A Preferred unitholders received an aggregate cash distribution of $7.5 million (paid in May 2017).

General partner interest and incentive distribution rights. As of June 30, 2018, the general partner was entitled to 1.5% of all quarterly distributions that the Partnership makes prior to its liquidation and, as the holder of the incentive distribution rights (“IDRs”), was entitled to incentive distributions at the maximum distribution sharing percentage of 48.0% for all periods presented, after the minimum quarterly distribution and the target distribution levels had been achieved. The maximum distribution sharing percentage of 49.5% does not include any distributions that the general partner may receive on common units that it may acquire.

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Equity and Partners' Capital

6 Months Ended

Jun. 30, 2018

Partners' Capital Notes [Abstract]

Equity and Partners' Capital

5. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. In July 2017, the Partnership filed a registration statement with the SEC for the issuance of up to an aggregate of $500.0 million of common units pursuant to a new continuous offering program that has not yet been initiated.

Class C units. In November 2014, the Partnership issued 10,913,853 Class C units to APC Midstream Holdings, LLC (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund the acquisition of DBM.

When issued, the Class C units were scheduled to convert into common units on a one-for-one basis on December 31, 2017. In February 2017, Anadarko elected to extend the conversion date of the Class C units to March 1, 2020. The Partnership can elect to convert the Class C units earlier or Anadarko can extend the conversion date again.

The Class C units were issued at a discount to the then-current market price of the common units into which they are convertible. This discount, totaling $34.8 million, represents a beneficial conversion feature, and at issuance, was reflected as an increase in common unitholders’ capital and a decrease in Class C unitholder capital to reflect the fair value of the Class C units at issuance. The beneficial conversion feature is considered a non-cash distribution that is recognized from the date of issuance through the date of conversion, resulting in an increase in Class C unitholder capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature is amortized assuming the extended conversion date of March 1, 2020, using the effective yield method. The impact of the beneficial conversion feature amortization is included in the calculation of earnings per unit.

Series A Preferred units. In 2016, the Partnership issued 21,922,831 Series A Preferred units to private investors. The Series A Preferred units were issued at a discount to the then-current market price of the common units into which they were convertible, representing a beneficial conversion feature at issuance. The impact of the beneficial conversion feature amortization was included in the calculation of earnings per unit. For the six months ended June 30, 2017, the amortization for the beneficial conversion feature of the Series A Preferred units was $62.3 million.

Pursuant to an agreement between the Partnership and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units converted into common units on a one-for-one basis on May 2, 2017.

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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

The following table summarizes the Partnership’s units issued during the six months ended June 30, 2018:

	Common Units	Class C Units	General Partner Units	Total
Balance at December 31, 2017	152,602,105	13,243,883	2,583,068	168,429,056
PIK Class C units	—	534,382	—	534,382
Long-Term Incentive Plan award vestings	7,180	—	—	7,180
Balance at June 30, 2018	152,609,285	13,778,265	2,583,068	168,970,618

Holdings of Partnership equity. As of June 30, 2018, WGP held50,132,046common units, representing a29.7%limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held2,583,068general partner units, representing a1.5%general partner interest in the Partnership, and100%of the IDRs. As ofJune 30, 2018, other subsidiaries of Anadarko collectively held2,011,380common units and13,778,265Class C units, representing an aggregate9.3%limited partner interest in the Partnership. As ofJune 30, 2018, the public held100,465,859common units, representing the remaining59.5%limited partner interest in the Partnership.

Net income (loss) per common unit. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the unitholders for purposes of calculating net income (loss) per common unit. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of acquisition of the Partnership assets is allocated as follows:

General partner. The general partner’s allocation is equal to cash distributions plus its portion of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner consistent with actual cash distributions and capital account allocations, including incentive distributions. 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 in accordance with its weighted-average ownership percentage during each period.

Series A Preferred unitholders. The Series A Preferred units were not considered a participating security as they only had distribution rights up to the specified per-unit quarterly distribution and had no rights to the Partnership’s undistributed earnings and losses. As such, the Series A Preferred unitholders’ allocation was equal to their cash distribution plus the amortization of the Series A Preferred units beneficial conversion feature (see Series A Preferred units above).

Common and Class C unitholders. The Class C units are considered a participating security because they participate in distributions with common units according to a predetermined formula (see Note 4). The common and Class C unitholders’ allocation is equal to their cash distributions plus their respective portions of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the common and Class C unitholders consistent with actual cash distributions and capital account allocations. Undistributed earnings or undistributed losses are then allocated to the common and Class C unitholders in accordance with their respective weighted-average ownership percentages during each period. The common unitholder allocation also includes the impact of the amortization of the Series A Preferred units and Class C units beneficial conversion features. The Class C unitholder allocation is similarly impacted by the amortization of the Class C units beneficial conversion feature (see Class C units above).

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Calculation of net income (loss) per unit. Basic net income (loss) per common unit is calculated by dividing the net income (loss) attributable to common unitholders 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. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest in net income (loss) assuming, prior to the actual conversion, conversion of the Series A Preferred units into common units, and (ii) the net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming, prior to the actual conversion, conversion of the Series A Preferred units.

The following table illustrates the Partnership’s calculation of net income (loss) per common unit:

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except per-unit amounts	2018			2017			2018			2017
Net income (loss) attributable to Western Gas Partners, LP	$	32,708		$	173,451		$	182,071		$	275,340
Series A Preferred units interest in net (income) loss (1)	—			(14,199		)	—			(42,373		)
General partner interest in net (income) loss	(84,176		)	(76,365		)	(167,615		)	(144,527		)
Common and Class C limited partners’ interest in net income (loss)	$	(51,468	)	$	82,887		$	14,456		$	88,440
Net income (loss) allocable to common units (1)	$	(48,417	)	$	73,383		$	9,906		$	75,097
Net income (loss) allocable to Class C units (1)	(3,051		)	9,504			4,550			13,343
Common and Class C limited partners’ interest in net income (loss)	$	(51,468	)	$	82,887		$	14,456		$	88,440
Net income (loss) per unit
Common units – basic and diluted (2)	$	(0.32	)	$	0.49		$	0.06		$	0.53
Weighted-average units outstanding
Common units – basic and diluted	152,604			148,864			152,603			141,696
Excluded due to anti-dilutive effect:
Class C units (2)	13,649			12,650			13,516			12,552
Series A Preferred units assuming conversion to common units (2)	—			3,734			—			10,901

⁽¹⁾  Adjusted to reflect amortization of the beneficial conversion features.

⁽²⁾  The impact of Class C units would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the three and six months ended June 30, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

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Transactions with Affiliates

6 Months Ended

Jun. 30, 2018

Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract]

Transactions with Affiliates

6. 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 and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operation 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.

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. 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. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

Note receivable - 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 $304.7 million and $325.2 million at June 30, 2018, and December 31, 2017, 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 a majority of the commodity price risk inherent in its percent-of-proceeds, percent-of-product and keep-whole contracts. 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. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. The Partnership’s net gains (losses) on commodity price swap agreements were $(1.4) million and $(2.6) million for the three and six months ended June 30, 2018, respectively, and $1.0 million and $0.5 million for the three and six months ended June 30, 2017, respectively, and are reported in the consolidated statements of operations as affiliate Product sales in 2018 and as affiliate Product sales and Cost of product expense in 2017 (see Note 1).

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Revenues or costs attributable to volumes sold and purchased during 2017 and 2018 for the DJ Basin complex and MGR assets are recognized in the consolidated statements of operations at the applicable market price in the tables below. The Partnership also records a capital contribution from Anadarko in the Partnership’s consolidated statement of equity and partners’ capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price in the tables below, minus (ii) the amount by which the swap price for product purchases exceeds the market price in the tables below. For the six months ended June 30, 2018, the capital contribution from Anadarko was $28.1 million. The tables below summarize the swap prices compared to the forward market prices:

	DJ Basin Complex
per barrel except natural gas	2017 - 2018 Swap Prices		2017 Market Prices (1)		2018 Market Prices (1)
Ethane	$	18.41	$	5.09	$	5.41
Propane	47.08		18.85		28.72
Isobutane	62.09		26.83		32.92
Normal butane	54.62		26.20		32.71
Natural gasoline	72.88		41.84		48.04
Condensate	76.47		45.40		49.36
Natural gas (per MMBtu)	5.96		3.05		2.21

	MGR Assets
per barrel except natural gas	2017 - 2018 Swap Prices		2017 Market Prices (1)		2018 Market Prices (1)
Ethane	$	23.11	$	4.08	$	2.52
Propane	52.90		19.24		25.83
Isobutane	73.89		25.79		30.03
Normal butane	64.93		25.16		29.82
Natural gasoline	81.68		45.01		47.25
Condensate	81.68		53.55		56.76
Natural gas (per MMBtu)	4.87		3.05		2.21

⁽¹⁾  Represents the New York Mercantile Exchange forward strip price as of December 1, 2016, and December 20, 2017, for the 2017 Market Prices and 2018 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

Gathering and processing agreements. The Partnership has significant gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The Partnership’s natural gas gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 35% for both the three and six months ended June 30, 2018, and 38% and 34% for the three and six months ended June 30, 2017, respectively. The Partnership’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 35% for both the three and six months ended June 30, 2018, and 39% and 44% for the three and six months ended June 30, 2017, respectively. The Partnership’s crude oil, NGL and produced water gathering, treating, transportation and disposal throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 72% and 68% for the three and six months ended June 30, 2018, respectively, and 41% and 47% for the three and six months ended June 30, 2017, respectively.

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Commodity purchase and sale agreements. The Partnership sells a significant amount of its natural gas, condensate and NGLs to Anadarko Energy Services Company (“AESC”), Anadarko’s marketing affiliate. In addition, the Partnership purchases natural gas, condensate and NGLs from AESC pursuant to purchase agreements. The Partnership’s purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal.

WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2017 Long-Term Incentive Plan, effective October 17, 2017. Awards granted prior to October 17, 2017, were awarded under the Western Gas Partners, LP 2008 Long-Term Incentive Plan. These awards are primarily granted to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. 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 June 30, 2018 and 2017, and $0.2 million for each of the six months ended June 30, 2018 and 2017.

Anadarko Incentive Plan. General and administrative expenses included $1.7 million and $3.8 million for the three and six months ended June 30, 2018, respectively, and $0.9 million and $2.1 million for the three and six months ended June 30, 2017, respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (“Anadarko Incentive Plan”). Of this amount, $2.8 million is reflected as contributions to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the six months ended June 30, 2018.

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

	Six Months Ended June 30,
thousands	2018			2017
Cash consideration	$	—		$	3,910
Payable to affiliate	254			—
Net carrying value	(254		)	(4,286		)
Partners’ capital adjustment	$	—		$	(376	)

Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. For periods prior to January 1, 2018, the cash receipts resulting from such reimbursements were presented as “Contributions in aid of construction costs from affiliates” within the investing section of the consolidated statements of cash flows. As discussed in Recently adopted accounting standards in Note 1,upon adoption of Topic 606, affiliate reimbursements of capital costs are reflected as contract liabilities upon receipt, amortized to Service revenues – fee based over the expected period of customer benefit, and presented within the operating section of the consolidated statements of cash flows.

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes material affiliate transactions:

	Three Months Ended   June 30,					Six Months Ended   June 30,
thousands	2018		2017			2018		2017
Revenues and other (1)	$	238,029	$	316,313		$	479,091	$	631,468
Equity income, net– affiliates (1)	39,218		21,728			59,642		41,189
Cost of product (1)	12,609		21,607			32,853		37,595
Operation and maintenance (2)	23,437		18,462			43,685		35,551
General and administrative (3)	11,178		9,365			22,792		18,900
Operating expenses	47,224		49,434			99,330		92,046
Interest income (4)	4,225		4,225			8,450		8,450
Interest expense (5)	—		—			—		71
Settlement of the Deferred purchase price obligation – Anadarko (6)	—		(37,346		)	—		(37,346		)
Distributions to unitholders (7)	127,204		110,449			251,368		213,572
Above-market component of swap agreements with Anadarko	13,839		16,373			28,121		28,670

⁽¹⁾  Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, 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 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.

⁽³⁾  Represents general and administrative expense incurred on and subsequent to the date of the acquisition of 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 Anadarko Incentive Plan within this Note 6).

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

⁽⁵⁾  Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3andNote 10).

⁽⁶⁾  Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).

⁽⁷⁾  Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

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 operations.

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Property, Plant and Equipment

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

7. PROPERTY, PLANT AND EQUIPMENT

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

thousands	Estimated Useful Life	June 30,   2018		December 31,   2017
Land	n/a	$	4,653	$	4,450
Gathering systems and processing complexes	3 to 47 years	7,565,998		7,113,114
Pipelines and equipment	15 to 45 years	137,769		137,644
Assets under construction	n/a	879,095		579,501
Other	3 to 40 years	31,478		29,826
Total property, plant and equipment		8,618,993		7,864,535
Less accumulated depreciation		2,405,419		2,133,644
Net property, plant and equipment		$	6,213,574	$	5,730,891

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.

Impairments.During the six months ended June 30, 2018, the Partnership recognized impairments of $127.4 million, including impairments of $120.8 million at the Third Creek gathering system and $6.4 million at the Kitty Draw gathering system. These assets were impaired to their estimated salvage values of $1.0 million and zero, respectively, using the market approach and Level 3 fair value inputs, due to the shutdown of the systems. See Note 1 for further information.

During the year ended December 31, 2017, the Partnership recognized impairments of $178.4 million, including an impairment of $158.8 million at the Granger complex, which was impaired to its estimated fair value of $48.5 million using the income approach and Level 3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. The remaining $19.6 million of impairments was primarily related to (i) an $8.2 million impairment due to the cancellation of a plant project at the Hilight system, (ii) a $3.7 million impairment at the Granger straddle plant, which was impaired to its estimated salvage value of $0.6 million using the income approach and Level 3 fair value inputs, (iii) a $3.1 million impairment of the Fort Union equity investment, (iv) a $2.0 million impairment of an idle facility in northeast Wyoming, which was impaired to its estimated salvage value of $0.4 million using the market approach and Level 3 fair value inputs, and (v) the cancellation of a pipeline project in West Texas.

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Equity Investments

6 Months Ended

Jun. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Investments

8. EQUITY INVESTMENTS

The following table presents the activity in the Partnership’s equity investments for the six months ended June 30, 2018:

thousands	Fort Union			White Cliffs			Rendezvous			Mont Belvieu JV			TEFR Interests			Whitethorn		Cactus II		Total
Balance at December 31, 2017	$	7,030		$	44,945		$	42,528		$	110,299		$	361,409		$	—	$	—	$	566,211
Acquisitions	—			—			—			—			—			150,563		11,295		161,858
Investment earnings (loss), net of amortization	(444		)	5,898			439			15,200			33,037			5,512		—		59,642
Contributions	—			1,278			—			—			—			7,069		19,127		27,474
Capitalized interest	—			—			—			—			—			—		16		16
Distributions	(194		)	(5,607		)	(1,410		)	(15,219		)	(25,966		)	—		—		(48,396		)
Distributions in excess of cumulative earnings (1)	(2,658		)	(1,958		)	(1,784		)	(2,131		)	(3,974		)	—		—		(12,505		)
Balance at June 30, 2018	$	3,734		$	44,556		$	39,773		$	108,149		$	364,506		$	163,144	$	30,438	$	754,300

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

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Components of Working Capital

6 Months Ended

Jun. 30, 2018

Components Of Working Capital [Abstract]

Components of Working Capital

9. COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:

thousands	June 30, 2018		December 31, 2017
Trade receivables, net	$	167,116	$	160,387
Other receivables, net	59		45
Total accounts receivable, net	$	167,175	$	160,432

A summary of other current assets is as follows:

thousands	June 30, 2018		December 31, 2017
Natural gas liquids inventory	$	9,421	$	10,788
Imbalance receivables	7,703		1,640
Prepaid insurance	264		2,388
Contract assets	9,340		—
Total other current assets	$	26,728	$	14,816

A summary of accrued liabilities is as follows:

thousands	June 30, 2018		December 31, 2017
Accrued interest expense	$	58,753	$	40,632
Short-term asset retirement obligations (1)	42,312		2,304
Short-term remediation and reclamation obligations	833		833
Income taxes payable	2,756		2,495
Contract liabilities	24,101		—
Other	2,597		1,635
Total accrued liabilities	$	131,352	$	47,899

⁽¹⁾  As of June 30, 2018, includes $40.2 million of short-term liabilities incurred related to the shutdowns at the Third Creek and Kitty Draw gathering systems. See Note 1 for further information.

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Debt and Interest Expense

6 Months Ended

Jun. 30, 2018

Debt Instruments [Abstract]

Debt and Interest Expense

10. DEBT AND INTEREST EXPENSE

At June 30, 2018, the Partnership’s debt consisted of 2.600% Senior Notes due 2018 (the “2018 Notes”), 5.375% Senior Notes due 2021 (the “2021 Notes”), 4.000% Senior Notes due 2022 (the “2022 Notes”), 3.950% Senior Notes due 2025 (the “2025 Notes”), 4.650% Senior Notes due 2026 (the “2026 Notes”), 4.500% Senior Notes due 2028 (the “2028 Notes”), 5.450% Senior Notes due 2044 (the “2044 Notes”) and 5.300% Senior Notes due 2048 (the “2048 Notes”).

The following table presents the Partnership’s outstanding debt:

	June 30, 2018						December 31, 2017
thousands	Principal		Carrying Value		Fair Value(1)		Principal		Carrying Value		Fair Value (1)
2018 Notes	$	350,000	$	349,937	$	349,832	$	350,000	$	349,684	$	350,631
2021 Notes	500,000		496,380		520,037		500,000		495,815		530,647
2022 Notes	670,000		668,962		665,356		670,000		668,849		684,043
2025 Notes	500,000		492,356		475,739		500,000		491,885		500,885
2026 Notes	500,000		495,475		492,415		500,000		495,245		520,144
2028 Notes	400,000		394,399		386,234		—		—		—
2044 Notes	600,000		593,290		569,855		600,000		593,234		637,827
2048 Notes	700,000		686,554		651,984		—		—		—
RCF	—		—		—		370,000		370,000		370,000
Total long-term debt	$	4,220,000	$	4,177,353	$	4,111,452	$	3,490,000	$	3,464,712	$	3,594,177

⁽¹⁾  Fair value is measured using the market approach and Level 2 inputs.

Debt activity. The following table presents the debt activity of the Partnership for the six months ended June 30, 2018:

thousands	Carrying Value
Balance at December 31, 2017	$	3,464,712
RCF borrowings	260,000
Issuance of 2028 Notes	400,000
Issuance of 2048 Notes	700,000
Repayments of RCF borrowings	(630,000		)
Other	(17,359		)
Balance at June 30, 2018	$	4,177,353

Senior Notes. The 2018 Notes, which are due in August 2018, were classified as long-term debt on the consolidated balance sheet at June 30, 2018, as the Partnership has the ability and intent to refinance these obligations using long-term debt.

The 2028 Notes and 2048 Notes issued in March 2018 were offered at prices to the public of 99.435% and 99.169%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the 2028 Notes and 2048 Notes are 4.682% and 5.431%, respectively. Interest is paid on each such series semi-annually on March 1 and September 1 of each year, beginning September 1, 2018. The proceeds (net of underwriting discounts, original issue discounts and debt issuance costs) were used to repay amounts outstanding under the senior unsecured revolving credit facility (“RCF”) and for general partnership purposes, including to fund capital expenditures.

At June 30, 2018, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.

10. DEBT AND INTEREST EXPENSE (CONTINUED)

Revolving credit facility. In February 2018, the Partnership entered into the five-year $1.5 billion RCF by amending and restating the $1.2 billion credit facility that was originally entered into in February 2014. The RCF is expandable to a maximum of $2.0 billion, matures in February 2023, with options to extend maturity by up to two additional one year increments, and bears interest at the London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based upon the Partnership’s senior unsecured debt rating. The Partnership is required to pay a quarterly facility fee ranging from 0.125% to 0.250% of the commitment amount (whether used or unused), also based upon its senior unsecured debt rating.

As of June 30, 2018, the Partnership had no outstanding borrowings and $4.6 million in outstanding letters of credit, resulting in $1,495.4 million available borrowing capacity under the RCF. As of June 30, 2018 and 2017, the interest rate on any outstanding RCF borrowings was 3.39% and 2.53%, respectively. The facility fee rate was 0.20% at June 30, 2018 and 2017. At June 30, 2018, the Partnership was in compliance with all covenants under the RCF.

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

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands	2018			2017			2018			2017
Third parties
Long-term debt	$	(48,394	)	$	(35,161	)	$	(89,677	)	$	(69,780	)
Amortization of debt issuance costs and commitment fees	(2,006		)	(1,645		)	(4,060		)	(3,275		)
Capitalized interest	6,011			1,060			10,065			1,876
Total interest expense – third parties	(44,389		)	(35,746		)	(83,672		)	(71,179		)
Affiliates
Deferred purchase price obligation – Anadarko (1)	—			—			—			(71		)
Total interest expense – affiliates	—			—			—			(71		)
Interest expense	$	(44,389	)	$	(35,746	)	$	(83,672	)	$	(71,250	)

⁽¹⁾  See Note 3 for a discussion of the Deferred purchase price obligation - Anadarko.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

11. COMMITMENTS AND CONTINGENCIES

Litigation and legal proceedings. In February 2017, DBJV, at the time a 50/50 joint venture between a third party and the Partnership, initiated an arbitration against SWEPI LP (“SWEPI”) for breach of a 2007 gas gathering agreement between it and DBJV (the “GGA”). Specifically, DBJV seeks to collect approximately $194.2 million in gathering fees under the GGA for the period January 1, 2016 to July 1, 2017. SWEPI disputes DBJV’s calculation of the cost of service based rate and filed a counterclaim for $14.9 million alleging overpayment of fees under the GGA for the years 2013 through 2015. The final arbitration hearing concluded on June 27, 2018, and the Partnership expects to receive a decision by the end of the third quarter of 2018. Under the terms of the Property Exchange, the Partnership’s former joint venture partner in DBJV will owe 50% of any amounts to be paid, and have a right to 50% of any amounts received, by the Partnership as a result of this arbitration proceeding. Pursuant to an agreement between the parties, if the arbitrators determine that DBJV is owed an amount of money by SWEPI for underpaid gathering fees for the period from January 1, 2016 to July 1, 2017, that amount will be paid to DBJV over five years as a supplemental gathering fee under the currently effective gas gathering agreement between the parties. Any other amounts owed by either party will be paid in cash within ninety days of the conclusion of the arbitration. As part of the adoption of Topic 606 (see Note 1), during the first quarter of 2018, the Partnership recorded a $7.5 million contract liability and reduced total equity and partners’ capital related to the counterclaim for the years 2013 through 2015 under the GGA revenue contract. Any amounts awarded to DBJV under the arbitration would be recognized in the period the arbitration decision is received. Management does not believe the outcome of this proceeding will have a materially unfavorable effect on the Partnership’s financial condition, results of operations or cash flows.

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 the 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, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to construction and expansion projects at the DBJV system and the DJ Basin and DBM complexes.

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease arrangements for corporate offices, shared field offices and equipment supporting the Partnership’s operations, for which Anadarko charges the Partnership lease expense. The leases for the corporate offices and shared field offices extend through 2028 and 2033, respectively. Lease expense charged to the Partnership associated with these lease arrangements was $12.2 million and $25.9 million for the three and six months ended June 30, 2018, respectively, and $12.2 million and $20.7 million for the three and six months ended June 30, 2017, respectively.

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Description of Business and Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Consolidation policy

Basis of presentation. The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements for entities not wholly owned:

	Percentage Interest
Equity investments (1)
Fort Union	14.81	%
White Cliffs	10	%
Rendezvous	22	%
Mont Belvieu JV	25	%
TEP	20	%
TEG	20	%
FRP	33.33	%
Whitethorn	20	%
Cactus II	15	%
Proportionate consolidation (2)
Marcellus Interest systems	33.75	%
Newcastle system	50	%
Springfield system	50.1	%
Full consolidation
Chipeta (3)	75	%

⁽¹⁾  Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.

⁽²⁾  The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.

⁽³⁾  The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

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.

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 2017 Form 10-K, as filed with the SEC on February 16, 2018. Management believes that the disclosures made are adequate to make the information not misleading.

Business combinations policy

Presentation of Partnership assets. The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by the Partnership as of June 30, 2018 (see Note 8). Because Anadarko controls the Partnership through its control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko are 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 Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.

Use of estimates policy

Use of estimates.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. 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.

New accounting standards policy

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Partnership adopted this ASU using a retrospective approach on January 1, 2018, and the adoption did not impact the consolidated financial statements.

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

Revenue from contracts with customers (Topic 606). The Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Topic 606”) on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The cumulative effect adjustment that was recognized in the opening balance of equity and partners’ capital was a decrease of $44.4 million. The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition (Topic 605) (“Topic 605”).

Effective January 1, 2018, the Partnership changed its accounting policy for revenue recognition as detailed below:

• Fee-based gathering / processing. Under Topic 605, fee revenues were recognized based on the rate in effect for the month of service, even when certain fees were charged on an upfront or limited-term basis. In addition, deficiency fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, revenues continue to be recognized based on the rate in effect when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Under Topic 606, the Partnership recognizes revenue associated with upfront or limited-term fees over the expected period of customer benefit, which is generally the life of the related properties. In addition, deficiency fees are estimated and recognized during the performance period as the services are performed for the customer’s delivered volumes. Under Topic 606, differences between Service revenues – fee based recognized and amounts billed to customers are recognized as contract assets or contract liabilities, as appropriate. This results in a change in the timing of revenue and changes to net income as a result of the revenue contract’s consideration provisions.

• Cost of service rate adjustments. Under Topic 605, revenue was recognized based on the amounts billed to customers each period. Under Topic 606, fixed minimum volume commitment demand fees and variable fees that are also billed on these minimum volumes are recognized as Service revenues – fee based on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and, as a result, a cumulative catch-up revenue adjustment related to the services already provided under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate. Fees received on volumes in excess of the minimum volumes are recognized as Service revenues – fee based as service is provided to the customer based on the billing rate in effect for the performance period. This revenue recognition timing does not affect billings to customers, and differences between amounts billed and revenue recognized are recorded as contract assets or liabilities, as appropriate.

• Aid in construction. Under Topic 605, aid in construction reimbursements were reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Under Topic 606, reimbursement of capital costs received from customers is reflected as a contract liability (deferred revenue) upon receipt. The contract liability is amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

• Percent-of-proceeds gathering / processing. Under Topic 605, the Partnership recognized cost of product expense when the product was purchased from a producer to whom it provides services, and the Partnership recognized revenue when the product was sold to Anadarko or a third party. Under Topic 606, in some instances, where all or a percentage of the proceeds from the sale must be returned to the producer, the net margin from the purchase and sale transactions is presented net within Service revenues – product based because the Partnership is acting as the producer’s agent in the product sale.

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

• Noncash consideration - keep-whole and percent-of-product agreements. Under Topic 605, the Partnership recognized revenues only upon the sale of the related products. Under Topic 606, the Partnership recognizes Service revenues – product based for the products received as noncash consideration in exchange for the services provided, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas cost. Under Topic 606, revenue from product sales is recognized, along with cost of product expense related to the sale, when the product is sold to Anadarko or a third party.

• Wellhead purchase / sale incorporated into gathering / processing. Under Topic 605, the natural gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenues. Under Topic 606, the fees charged to the producer under this contract type are recognized as adjustments to the amount recognized in cost of product expense instead of revenues when such fees relate to services performed after control of the product transfers to the Partnership.

The following tables summarize the impact of adopting Topic 606 on the impacted line items within the consolidated statements of operations and the consolidated balance sheet. The differences between revenue as reported following Topic 606 and revenue as it would have been reported under Topic 605 are due to the changes described above.

	Three Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	359,544	$	358,209	$	1,335
Service revenues – product based	22,105		—		22,105
Product sales	54,077		319,233		(265,156		)
Expenses
Cost of product	68,149		312,329		(244,180		)
Operation and maintenance	100,628		100,632		(4		)
Depreciation and amortization	78,792		78,125		667
Impairments	127,243		127,198		45
Income tax (benefit) expense	282		272		10
Net income attributable to noncontrolling interest	2,811		2,054		757
Net income (loss) attributable to Western Gas Partners, LP	32,708		31,719		989

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

	Six Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	697,963	$	700,547	$	(2,584	)
Service revenues – product based	44,698		—		44,698
Product sales	130,014		611,524		(481,510		)
Expenses
Cost of product	145,948		587,295		(441,347		)
Operation and maintenance	188,907		188,771		136
Depreciation and amortization	155,634		154,278		1,356
Impairments	127,391		127,346		45
Income tax (benefit) expense	1,784		1,781		3
Net income attributable to noncontrolling interest	5,796		4,552		1,244
Net income (loss) attributable to Western Gas Partners, LP	182,071		182,904		(833		)

	June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Assets
Other current assets	$	26,728	$	17,388	$	9,340
Net property, plant and equipment	6,213,574		6,117,733		95,841
Other assets	14,384		14,138		246
Liabilities
Accrued liabilities	131,352		124,913		6,439
Deferred income taxes	8,753		8,930		(177		)
Other liabilities	138,493		2,810		135,683
Equity and partners’ capital
Total equity and partners’ capital	3,701,482		3,738,000		(36,518		)

New accounting standards issued but not yet adopted.ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Partnership plans to make certain elections allowing the Partnership not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements and not to recognize ROU assets or lease liabilities for short-term leases. The Partnership continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU, which is expected to primarily impact other assets and other liabilities. To facilitate compliance with this ASU, the Partnership is implementing new accounting software and continuing to evaluate its systems, processes and internal controls during 2018. The Partnership will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Partnership does not expect to adjust comparative period financial statements.

Revenue and cost of product policy

Revenue and cost of product. Upon adoption of the new revenue recognition standard on January 1, 2018 (discussed in Recently adopted accounting standards), the Partnership changed its accounting policy for revenue recognition as described below.

The Partnershipprovides gathering, processing, treating, transportation and disposal services pursuant to a variety of contracts. Under these arrangements, the Partnership receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in Service revenues and Product sales in the consolidated statements of operations. Payment is generally received from the customer in the month following the service or delivery of the product. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Service revenues – fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation and disposal of natural gas, NGLs, condensate, crude oil and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed upon completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties.

The Partnership also receives Service revenues – fee based from contracts that have minimum volume commitment demand fees and fees that require periodic rate redeterminations based upon the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate.

Service revenues – product based includes service revenues from percent-of-proceeds gathering and processing contracts that are recognized net of the cost of product for purchases from the Partnership’s customers since it is acting as the agent in the product sale. Keep-whole and percent-of-product agreements result in Service revenues – product based being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. Noncash consideration for these services is valued at the time the services are provided. Revenue from product sales is also recognized, along with the cost of product expense related to the sale, when the product received as noncash consideration is sold to either Anadarko or a third party.

The Partnership also purchases natural gas volumes from producers at the wellhead or from a production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. When the fees relate to services performed after control of the product has transferred to the Partnership, the fees are treated as a reduction of the purchase cost. Revenue from product sales is recognized, along with cost of product expense related to the sale, when the purchased product is sold to either Anadarko or a third party.

The Partnership receives aid in construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs, etc.) under certain service contracts. Aid in construction reimbursements are reflected as a contract liability upon receipt and amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

Net income (loss) per common unit policy

Net income (loss) per common unit. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the unitholders for purposes of calculating net income (loss) per common unit. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of acquisition of the Partnership assets is allocated as follows:

General partner. The general partner’s allocation is equal to cash distributions plus its portion of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner consistent with actual cash distributions and capital account allocations, including incentive distributions. 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 in accordance with its weighted-average ownership percentage during each period.

Series A Preferred unitholders. The Series A Preferred units were not considered a participating security as they only had distribution rights up to the specified per-unit quarterly distribution and had no rights to the Partnership’s undistributed earnings and losses. As such, the Series A Preferred unitholders’ allocation was equal to their cash distribution plus the amortization of the Series A Preferred units beneficial conversion feature (see Series A Preferred units above).

Common and Class C unitholders. The Class C units are considered a participating security because they participate in distributions with common units according to a predetermined formula (see Note 4). The common and Class C unitholders’ allocation is equal to their cash distributions plus their respective portions of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the common and Class C unitholders consistent with actual cash distributions and capital account allocations. Undistributed earnings or undistributed losses are then allocated to the common and Class C unitholders in accordance with their respective weighted-average ownership percentages during each period. The common unitholder allocation also includes the impact of the amortization of the Series A Preferred units and Class C units beneficial conversion features. The Class C unitholder allocation is similarly impacted by the amortization of the Class C units beneficial conversion feature (see Class C units above).

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Calculation of net income (loss) per unit. Basic net income (loss) per common unit is calculated by dividing the net income (loss) attributable to common unitholders 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. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest in net income (loss) assuming, prior to the actual conversion, conversion of the Series A Preferred units into common units, and (ii) the net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming, prior to the actual conversion, conversion of the Series A Preferred units.

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Description of Business and Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Assets and Investments Table

As of June 30, 2018, the Partnership’s assets and investments consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems (1)	12	3	3	2
Treating facilities	19	3	—	3
Natural gas processing plants/trains	20	4	—	2
NGL pipelines	2	—	—	3
Natural gas pipelines	5	—	—	—
Oil pipelines	—	1	—	2

⁽¹⁾  Includes the DBM water systems.

Ownership Interests and Method of Consolidation Table

The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements for entities not wholly owned:

	Percentage Interest
Equity investments (1)
Fort Union	14.81	%
White Cliffs	10	%
Rendezvous	22	%
Mont Belvieu JV	25	%
TEP	20	%
TEG	20	%
FRP	33.33	%
Whitethorn	20	%
Cactus II	15	%
Proportionate consolidation (2)
Marcellus Interest systems	33.75	%
Newcastle system	50	%
Springfield system	50.1	%
Full consolidation
Chipeta (3)	75	%

⁽¹⁾  Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.

⁽²⁾  The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.

⁽³⁾  The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

Impact of New Accounting Pronouncement Tables

The following tables summarize the impact of adopting Topic 606 on the impacted line items within the consolidated statements of operations and the consolidated balance sheet. The differences between revenue as reported following Topic 606 and revenue as it would have been reported under Topic 605 are due to the changes described above.

	Three Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	359,544	$	358,209	$	1,335
Service revenues – product based	22,105		—		22,105
Product sales	54,077		319,233		(265,156		)
Expenses
Cost of product	68,149		312,329		(244,180		)
Operation and maintenance	100,628		100,632		(4		)
Depreciation and amortization	78,792		78,125		667
Impairments	127,243		127,198		45
Income tax (benefit) expense	282		272		10
Net income attributable to noncontrolling interest	2,811		2,054		757
Net income (loss) attributable to Western Gas Partners, LP	32,708		31,719		989

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

	Six Months Ended   June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	697,963	$	700,547	$	(2,584	)
Service revenues – product based	44,698		—		44,698
Product sales	130,014		611,524		(481,510		)
Expenses
Cost of product	145,948		587,295		(441,347		)
Operation and maintenance	188,907		188,771		136
Depreciation and amortization	155,634		154,278		1,356
Impairments	127,391		127,346		45
Income tax (benefit) expense	1,784		1,781		3
Net income attributable to noncontrolling interest	5,796		4,552		1,244
Net income (loss) attributable to Western Gas Partners, LP	182,071		182,904		(833		)

	June 30, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Assets
Other current assets	$	26,728	$	17,388	$	9,340
Net property, plant and equipment	6,213,574		6,117,733		95,841
Other assets	14,384		14,138		246
Liabilities
Accrued liabilities	131,352		124,913		6,439
Deferred income taxes	8,753		8,930		(177		)
Other liabilities	138,493		2,810		135,683
Equity and partners’ capital
Total equity and partners’ capital	3,701,482		3,738,000		(36,518		)

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Revenue from Contracts with Customers (Tables)

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Summary of Revenue from Contracts with Customers Table

The following table summarizes the Partnership’s revenue from contracts with customers:

thousands	Three Months Ended   June 30, 2018			Six Months Ended   June 30, 2018
Revenue from customers
Service revenues – fee based	$	359,544		$	697,963
Service revenues – product based	22,105			44,698
Product sales	55,449			132,629
Total revenue from customers	437,098			875,290
Revenue from other than customers
Net gains (losses) on commodity price swap agreements	(1,372		)	(2,615		)
Other	223			442
Total revenues and other	$	435,949		$	873,117

Contract Assets and Liabilities Activity Tables

The following table summarizes the current period activity related to contract assets from contracts with customers:

thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	5,129
Amounts transferred to Accounts receivable, net from contract assets recognized in the adoption effect (1)	(2,677		)
Additional estimated revenues recognized (2)	7,134
Balance at June 30, 2018	$	9,586
Contract assets at June 30, 2018
Other current assets	$	9,340
Other assets	246
Total contract assets from contracts with customers	$	9,586

⁽¹⁾  Includes $(0.2) million for the three months ended June 30, 2018.

⁽²⁾  Includes $3.7 million for the three months ended June 30, 2018.

The following table summarizes the current period activity related to contract liabilities from contracts with customers:

thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	120,717
Cash received or receivable, excluding revenues recognized during the period (1)	41,076
Revenues recognized during the period that were included in the adoption effect (2)	(2,009		)
Balance at June 30, 2018	$	159,784
Contract liabilities at June 30, 2018
Accrued liabilities	$	24,101
Other liabilities	135,683
Total contract liabilities from contracts with customers	$	159,784

⁽¹⁾  Includes $12.5 million for the three months ended June 30, 2018.

⁽²⁾  Includes $(1.0) million for the three months ended June 30, 2018.

Expected Revenue Recognition from Satisfaction of Performance Obligations Table

Therefore, the following table represents only a small portion of expected future consolidated revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and in some cases variable commodity prices for those volumes.

thousands
Remainder of 2018	$	220,037
2019	492,806
2020	542,214
2021	527,151
2022	527,103
Thereafter	2,168,028
Total	$	4,477,339

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Partnership Distributions (Tables)

6 Months Ended

Jun. 30, 2018

Distributions Made to Members or Limited Partners [Abstract]

Cash Distributions Table

The Board of Directors of the Partnership’s general partner (the “Board of Directors”) declared the following cash distributions to the Partnership’s common and general partner unitholders for the periods presented:

thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
2017
March 31	$	0.875	$	188,753	May 2017
June 30	0.890		207,491		August 2017
September 30	0.905		212,038		November 2017
December 31	0.920		216,586		February 2018
2018
March 31	$	0.935	$	221,133	May 2018
June 30 (1)	0.950		225,691		August 2018

⁽¹⁾  The Board of Directors declared a cash distribution to the Partnership’s unitholders for the second quarter of 2018 of $0.950 per unit, or $225.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution is payable on August 13, 2018, to unitholders of record at the close of business on August 1, 2018.

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Equity and Partners' Capital (Tables)

6 Months Ended

Jun. 30, 2018

Partners' Capital Notes [Abstract]

Partnership Interests Table

The following table summarizes the Partnership’s units issued during the six months ended June 30, 2018:

	Common Units	Class C Units	General Partner Units	Total
Balance at December 31, 2017	152,602,105	13,243,883	2,583,068	168,429,056
PIK Class C units	—	534,382	—	534,382
Long-Term Incentive Plan award vestings	7,180	—	—	7,180
Balance at June 30, 2018	152,609,285	13,778,265	2,583,068	168,970,618

Calculation of Net Income (Loss) Per Unit Table

The following table illustrates the Partnership’s calculation of net income (loss) per common unit:

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands except per-unit amounts	2018			2017			2018			2017
Net income (loss) attributable to Western Gas Partners, LP	$	32,708		$	173,451		$	182,071		$	275,340
Series A Preferred units interest in net (income) loss (1)	—			(14,199		)	—			(42,373		)
General partner interest in net (income) loss	(84,176		)	(76,365		)	(167,615		)	(144,527		)
Common and Class C limited partners’ interest in net income (loss)	$	(51,468	)	$	82,887		$	14,456		$	88,440
Net income (loss) allocable to common units (1)	$	(48,417	)	$	73,383		$	9,906		$	75,097
Net income (loss) allocable to Class C units (1)	(3,051		)	9,504			4,550			13,343
Common and Class C limited partners’ interest in net income (loss)	$	(51,468	)	$	82,887		$	14,456		$	88,440
Net income (loss) per unit
Common units – basic and diluted (2)	$	(0.32	)	$	0.49		$	0.06		$	0.53
Weighted-average units outstanding
Common units – basic and diluted	152,604			148,864			152,603			141,696
Excluded due to anti-dilutive effect:
Class C units (2)	13,649			12,650			13,516			12,552
Series A Preferred units assuming conversion to common units (2)	—			3,734			—			10,901

⁽¹⁾  Adjusted to reflect amortization of the beneficial conversion features.

⁽²⁾  The impact of Class C units would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the three and six months ended June 30, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

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Transactions with Affiliates (Tables)

6 Months Ended

Jun. 30, 2018

Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract]

Commodity Price Swap Agreements Tables

The tables below summarize the swap prices compared to the forward market prices:

	DJ Basin Complex
per barrel except natural gas	2017 - 2018 Swap Prices		2017 Market Prices (1)		2018 Market Prices (1)
Ethane	$	18.41	$	5.09	$	5.41
Propane	47.08		18.85		28.72
Isobutane	62.09		26.83		32.92
Normal butane	54.62		26.20		32.71
Natural gasoline	72.88		41.84		48.04
Condensate	76.47		45.40		49.36
Natural gas (per MMBtu)	5.96		3.05		2.21

	MGR Assets
per barrel except natural gas	2017 - 2018 Swap Prices		2017 Market Prices (1)		2018 Market Prices (1)
Ethane	$	23.11	$	4.08	$	2.52
Propane	52.90		19.24		25.83
Isobutane	73.89		25.79		30.03
Normal butane	64.93		25.16		29.82
Natural gasoline	81.68		45.01		47.25
Condensate	81.68		53.55		56.76
Natural gas (per MMBtu)	4.87		3.05		2.21

⁽¹⁾  Represents the New York Mercantile Exchange forward strip price as of December 1, 2016, and December 20, 2017, for the 2017 Market Prices and 2018 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

Related Party Transactions Table

The following table summarizes material affiliate transactions:

	Three Months Ended   June 30,					Six Months Ended   June 30,
thousands	2018		2017			2018		2017
Revenues and other (1)	$	238,029	$	316,313		$	479,091	$	631,468
Equity income, net– affiliates (1)	39,218		21,728			59,642		41,189
Cost of product (1)	12,609		21,607			32,853		37,595
Operation and maintenance (2)	23,437		18,462			43,685		35,551
General and administrative (3)	11,178		9,365			22,792		18,900
Operating expenses	47,224		49,434			99,330		92,046
Interest income (4)	4,225		4,225			8,450		8,450
Interest expense (5)	—		—			—		71
Settlement of the Deferred purchase price obligation – Anadarko (6)	—		(37,346		)	—		(37,346		)
Distributions to unitholders (7)	127,204		110,449			251,368		213,572
Above-market component of swap agreements with Anadarko	13,839		16,373			28,121		28,670

⁽¹⁾  Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, 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 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.

⁽³⁾  Represents general and administrative expense incurred on and subsequent to the date of the acquisition of 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 Anadarko Incentive Plan within this Note 6).

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

⁽⁵⁾  Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3andNote 10).

⁽⁶⁾  Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).

⁽⁷⁾  Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

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

	Six Months Ended June 30,
thousands	2018			2017
Cash consideration	$	—		$	3,910
Payable to affiliate	254			—
Net carrying value	(254		)	(4,286		)
Partners’ capital adjustment	$	—		$	(376	)

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Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Table

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

thousands	Estimated Useful Life	June 30,   2018		December 31,   2017
Land	n/a	$	4,653	$	4,450
Gathering systems and processing complexes	3 to 47 years	7,565,998		7,113,114
Pipelines and equipment	15 to 45 years	137,769		137,644
Assets under construction	n/a	879,095		579,501
Other	3 to 40 years	31,478		29,826
Total property, plant and equipment		8,618,993		7,864,535
Less accumulated depreciation		2,405,419		2,133,644
Net property, plant and equipment		$	6,213,574	$	5,730,891

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Equity Investments (Tables)

6 Months Ended

Jun. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Investments Table

The following table presents the activity in the Partnership’s equity investments for the six months ended June 30, 2018:

thousands	Fort Union			White Cliffs			Rendezvous			Mont Belvieu JV			TEFR Interests			Whitethorn		Cactus II		Total
Balance at December 31, 2017	$	7,030		$	44,945		$	42,528		$	110,299		$	361,409		$	—	$	—	$	566,211
Acquisitions	—			—			—			—			—			150,563		11,295		161,858
Investment earnings (loss), net of amortization	(444		)	5,898			439			15,200			33,037			5,512		—		59,642
Contributions	—			1,278			—			—			—			7,069		19,127		27,474
Capitalized interest	—			—			—			—			—			—		16		16
Distributions	(194		)	(5,607		)	(1,410		)	(15,219		)	(25,966		)	—		—		(48,396		)
Distributions in excess of cumulative earnings (1)	(2,658		)	(1,958		)	(1,784		)	(2,131		)	(3,974		)	—		—		(12,505		)
Balance at June 30, 2018	$	3,734		$	44,556		$	39,773		$	108,149		$	364,506		$	163,144	$	30,438	$	754,300

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

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Components of Working Capital (Tables)

6 Months Ended

Jun. 30, 2018

Components Of Working Capital [Abstract]

Accounts Receivable, Net Table

A summary of accounts receivable, net is as follows:

thousands	June 30, 2018		December 31, 2017
Trade receivables, net	$	167,116	$	160,387
Other receivables, net	59		45
Total accounts receivable, net	$	167,175	$	160,432

Other Current Assets Table

A summary of other current assets is as follows:

thousands	June 30, 2018		December 31, 2017
Natural gas liquids inventory	$	9,421	$	10,788
Imbalance receivables	7,703		1,640
Prepaid insurance	264		2,388
Contract assets	9,340		—
Total other current assets	$	26,728	$	14,816

Accrued Liabilities Table

A summary of accrued liabilities is as follows:

thousands	June 30, 2018		December 31, 2017
Accrued interest expense	$	58,753	$	40,632
Short-term asset retirement obligations (1)	42,312		2,304
Short-term remediation and reclamation obligations	833		833
Income taxes payable	2,756		2,495
Contract liabilities	24,101		—
Other	2,597		1,635
Total accrued liabilities	$	131,352	$	47,899

⁽¹⁾  As of June 30, 2018, includes $40.2 million of short-term liabilities incurred related to the shutdowns at the Third Creek and Kitty Draw gathering systems. See Note 1 for further information.

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Debt and Interest Expense (Tables)

6 Months Ended

Jun. 30, 2018

Debt Instruments [Abstract]

Debt Outstanding and Debt Activity Tables

The following table presents the Partnership’s outstanding debt:

	June 30, 2018						December 31, 2017
thousands	Principal		Carrying Value		Fair Value(1)		Principal		Carrying Value		Fair Value (1)
2018 Notes	$	350,000	$	349,937	$	349,832	$	350,000	$	349,684	$	350,631
2021 Notes	500,000		496,380		520,037		500,000		495,815		530,647
2022 Notes	670,000		668,962		665,356		670,000		668,849		684,043
2025 Notes	500,000		492,356		475,739		500,000		491,885		500,885
2026 Notes	500,000		495,475		492,415		500,000		495,245		520,144
2028 Notes	400,000		394,399		386,234		—		—		—
2044 Notes	600,000		593,290		569,855		600,000		593,234		637,827
2048 Notes	700,000		686,554		651,984		—		—		—
RCF	—		—		—		370,000		370,000		370,000
Total long-term debt	$	4,220,000	$	4,177,353	$	4,111,452	$	3,490,000	$	3,464,712	$	3,594,177

⁽¹⁾  Fair value is measured using the market approach and Level 2 inputs.

Debt activity. The following table presents the debt activity of the Partnership for the six months ended June 30, 2018:

thousands	Carrying Value
Balance at December 31, 2017	$	3,464,712
RCF borrowings	260,000
Issuance of 2028 Notes	400,000
Issuance of 2048 Notes	700,000
Repayments of RCF borrowings	(630,000		)
Other	(17,359		)
Balance at June 30, 2018	$	4,177,353

Interest Expense Table

The following table summarizes the amounts included in interest expense:

	Three Months Ended   June 30,						Six Months Ended   June 30,
thousands	2018			2017			2018			2017
Third parties
Long-term debt	$	(48,394	)	$	(35,161	)	$	(89,677	)	$	(69,780	)
Amortization of debt issuance costs and commitment fees	(2,006		)	(1,645		)	(4,060		)	(3,275		)
Capitalized interest	6,011			1,060			10,065			1,876
Total interest expense – third parties	(44,389		)	(35,746		)	(83,672		)	(71,179		)
Affiliates
Deferred purchase price obligation – Anadarko (1)	—			—			—			(71		)
Total interest expense – affiliates	—			—			—			(71		)
Interest expense	$	(44,389	)	$	(35,746	)	$	(83,672	)	$	(71,250	)

⁽¹⁾  See Note 3 for a discussion of the Deferred purchase price obligation - Anadarko.

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Description of Business and Basis of Presentation - Assets and Investments Table (Details)	Jun. 30, 2018 unit
Owned and Operated [Member] | Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	12	[1]
Owned and Operated [Member] | Treating Facilities [Member]
Assets [Line Items]
Assets, number of units	19
Owned and Operated [Member] | Natural Gas Processing Plants/Trains [Member]
Assets [Line Items]
Assets, number of units	20
Owned and Operated [Member] | Natural Gas Liquids Pipelines [Member]
Assets [Line Items]
Assets, number of units	2
Owned and Operated [Member] | Natural Gas Pipelines [Member]
Assets [Line Items]
Assets, number of units	5
Operated Interests [Member] | Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	3	[1]
Operated Interests [Member] | Treating Facilities [Member]
Assets [Line Items]
Assets, number of units	3
Operated Interests [Member] | Natural Gas Processing Plants/Trains [Member]
Assets [Line Items]
Assets, number of units	4
Operated Interests [Member] | Oil Pipelines [Member]
Assets [Line Items]
Assets, number of units	1
Non-Operated Interests [Member] | Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	3	[1]
Equity Interests [Member] | Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	2	[1]
Equity Interests [Member] | Treating Facilities [Member]
Assets [Line Items]
Assets, number of units	3
Equity Interests [Member] | Natural Gas Processing Plants/Trains [Member]
Assets [Line Items]
Assets, number of units	2
Equity Interests [Member] | Natural Gas Liquids Pipelines [Member]
Assets [Line Items]
Assets, number of units	3
Equity Interests [Member] | Oil Pipelines [Member]
Assets [Line Items]
Assets, number of units	2

[1] Includes the DBM water systems.

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Description of Business and Basis of Presentation - Ownership Interests and Method of Consolidation Table (Details)	6 Months Ended
	Jun. 30, 2018
Chipeta [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership interest by noncontrolling interest owner	25.00%
Equity Investments [Member] | Fort Union [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	14.81%	[1]
Equity Investments [Member] | White Cliffs [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	10.00%	[1]
Equity Investments [Member] | Rendezvous [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	22.00%	[1]
Equity Investments [Member] | Mont Belvieu JV [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	25.00%	[1]
Equity Investments [Member] | Texas Express Pipeline [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	20.00%	[1]
Equity Investments [Member] | Texas Express Gathering [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	20.00%	[1]
Equity Investments [Member] | Front Range Pipeline [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	33.33%	[1]
Equity Investments [Member] | Whitethorn [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	20.00%	[1]
Equity Investments [Member] | Cactus II [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	15.00%	[1]
Proportionate Consolidation [Member] | Marcellus Interest Systems [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	33.75%	[2]
Proportionate Consolidation [Member] | Newcastle System [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	50.00%	[2]
Proportionate Consolidation [Member] | Springfield System [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	50.10%	[2]
Full Consolidation [Member] | Chipeta [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Percentage ownership interest	75.00%	[3]

[1] Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.

[2] The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.

[3] The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

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Description of Business and Basis of Presentation - Impact of New Accounting Pronouncement - Statements of Operations Table (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Revenues
Revenues and other		$ 435,949	$ 525,450	$ 873,117	$ 1,041,643
Expenses
Cost of product	[1]	68,149	203,277	145,948	392,636
Operation and maintenance	[1]	100,628	76,148	188,907	149,908
Depreciation and amortization		78,792	74,031	155,634	143,733
Impairments		127,243	3,178	127,391	167,920	$ 178,400
Income tax (benefit) expense		282	843	1,784	4,395
Net income attributable to noncontrolling interest		2,811	2,046	5,796	4,148
Net income (loss) attributable to Western Gas Partners, LP		32,708	$ 173,451	182,071	$ 275,340
Service Revenues - Fee Based [Member]
Revenues
Revenues and other		359,544		697,963
Service Revenues - Product Based [Member]
Revenues
Revenues and other		22,105		44,698
Product Sales [Member]
Revenues
Revenues and other		54,077		130,014
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member]
Expenses
Cost of product		312,329		587,295
Operation and maintenance		100,632		188,771
Depreciation and amortization		78,125		154,278
Impairments		127,198		127,346
Income tax (benefit) expense		272		1,781
Net income attributable to noncontrolling interest		2,054		4,552
Net income (loss) attributable to Western Gas Partners, LP		31,719		182,904
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member] | Service Revenues - Fee Based [Member]
Revenues
Revenues and other		358,209		700,547
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member] | Service Revenues - Product Based [Member]
Revenues
Revenues and other		0		0
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member] | Product Sales [Member]
Revenues
Revenues and other		319,233		611,524
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase / (Decrease) [Member]
Expenses
Cost of product		(244,180)		(441,347)
Operation and maintenance		(4)		136
Depreciation and amortization		667		1,356
Impairments		45		45
Income tax (benefit) expense		10		3
Net income attributable to noncontrolling interest		757		1,244
Net income (loss) attributable to Western Gas Partners, LP		989		(833)
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase / (Decrease) [Member] | Service Revenues - Fee Based [Member]
Revenues
Revenues and other		1,335		(2,584)
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase / (Decrease) [Member] | Service Revenues - Product Based [Member]
Revenues
Revenues and other		22,105		44,698
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase / (Decrease) [Member] | Product Sales [Member]
Revenues
Revenues and other		$ (265,156)		$ (481,510)

[1] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $12.6 million and $32.9 million for the three and six months ended June 30, 2018, respectively, and $21.6 million and $37.6 million for the three and six months ended June 30, 2017, respectively. Operation and maintenance includes charges from Anadarko of $23.4 million and $43.7 million for the three and six months ended June 30, 2018, respectively, and $18.5 million and $35.6 million for the three and six months ended June 30, 2017, respectively. General and administrative includes charges from Anadarko of $11.2 million and $22.8 million for the three and six months ended June 30, 2018, respectively, and $9.4 million and $18.9 million for the three and six months ended June 30, 2017, respectively. See Note 6.

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Description of Business and Basis of Presentation - Impact of New Accounting Pronouncement - Balance Sheet Table (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Assets
Other current assets	[1]	$ 26,728	$ 14,816
Net property, plant and equipment		6,213,574	5,730,891
Other assets	[2]	14,384	11,757
Liabilities
Accrued liabilities	[3]	131,352	47,899
Deferred income taxes		8,753	7,409
Other liabilities	[4]	138,493	3,491
Equity and partners' capital
Total equity and partners' capital		3,701,482	$ 3,971,011
Accounting Standards Update 2014-09 [Member] | Without Adoption of Topic 606 [Member]
Assets
Other current assets		17,388
Net property, plant and equipment		6,117,733
Other assets		14,138
Liabilities
Accrued liabilities		124,913
Deferred income taxes		8,930
Other liabilities		2,810
Equity and partners' capital
Total equity and partners' capital		3,738,000
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase / (Decrease) [Member]
Assets
Other current assets		9,340
Net property, plant and equipment		95,841
Other assets		246
Liabilities
Accrued liabilities		6,439
Deferred income taxes		(177)
Other liabilities		135,683
Equity and partners' capital
Total equity and partners' capital		$ (36,518)

[1] Other current assets includes affiliate amounts of $9.3 million and zero as of June 30, 2018, and December 31, 2017, respectively.

[2] Other assets includes affiliate amounts of $0.2 million and zero as of June 30, 2018, and December 31, 2017, respectively.

[3] Accrued liabilities includes affiliate amounts of $2.3 million and $0.2 million as of June 30, 2018, and December 31, 2017, respectively.

[4] Other liabilities includes affiliate amounts of $48.4 million and $0.7 million as of June 30, 2018, and December 31, 2017, respectively.

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Description of Business and Basis of Presentation - Additional Information (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended				12 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017		Dec. 31, 2017	Jan. 01, 2018
Revenues and other		$ 435,949	$ 525,450	$ 873,117		$ 1,041,643
Impairments		127,243	3,178	127,391		167,920		$ 178,400
Loss on divestiture and other, net	[1]	(170)	(15,458)	(286)	[2]	(134,945)	[2]
Proceeds from property insurance claims				0		22,977
Cumulative effect of accounting change	[3]	$ (44,379)		$ (44,379)
Minimum [Member]
Contract term		5 years		5 years
Maximum [Member]
Contract term		10 years		10 years
Accounting Standards Update 2014-09 [Member]
Cumulative effect of accounting change									$ (44,379)
Kitty Draw and Third Creek Gathering Systems [Member]
Impairments				$ 127,200
Delaware Basin Midstream Complex [Member]
Loss on divestiture and other, net						5,700
Proceeds from insurance claims, total						52,900
Proceeds from business interruption insurance claims						29,882
Proceeds from property insurance claims						22,977
Affiliates [Member]
Revenues and other	[4]	$ 238,029	316,313	479,091		631,468
Product Sales [Member]
Revenues and other		54,077		130,014
Product Sales [Member] | Affiliates [Member]
Revenues and other		$ 45,256	$ 161,329	100,075		$ 304,170
Product Sales [Member] | Affiliates [Member] | Kitty Draw and Third Creek Gathering Systems [Member]
Revenues and other				$ (10,900)

[1] Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

[2] Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.

[3] See Note 1.

[4] Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

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Revenue from Contracts with Customers - Revenue From Contracts With Customers Table (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue from customers	$ 437,098		$ 875,290
Total revenues and other	435,949	$ 525,450	873,117	$ 1,041,643
Service Revenues - Fee Based [Member]
Disaggregation of Revenue [Line Items]
Revenue from customers	359,544		697,963
Total revenues and other	359,544		697,963
Service Revenues - Product Based [Member]
Disaggregation of Revenue [Line Items]
Revenue from customers	22,105		44,698
Total revenues and other	22,105		44,698
Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from customers	55,449		132,629
Total revenues and other	54,077		130,014
Commodity Price Swap Agreement [Member]
Disaggregation of Revenue [Line Items]
Revenue from other than customers	(1,372)		(2,615)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from other than customers	$ 223		$ 442

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Revenue from Contracts with Customers - Contract Assets Table (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018		Jun. 30, 2018	Dec. 31, 2017
Change in Contracts with Customer, Asset [Roll Forward]
Balance at December 31, 2017		$ 0
Cumulative effect of adopting Topic 606		5,129
Amounts transferred to Accounts receivable, net from contract assets recognized in the adoption effect	$ (200)	(2,677)	[1]
Additional estimated revenues recognized	3,700	7,134	[2]
Balance at June 30, 2018	9,586	9,586
Contract assets at June 30, 2018
Other current assets				$ 9,340	$ 0
Other assets				246
Total contract assets from contracts with customers	$ 9,586	$ 0		$ 9,586	$ 0

[1] Includes $(0.2) million for the three months ended June 30, 2018.

[2] Includes $3.7 million for the three months ended June 30, 2018.

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Revenue from Contracts with Customers - Contract Liabilities Table (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018		Jun. 30, 2018	Dec. 31, 2017
Change in Contracts with Customer, Liability [Roll Forward]
Balance at December 31, 2017		$ 0
Cumulative effect of adopting Topic 606		120,717
Cash received or receivable, excluding revenues recognized during the period	$ 12,500	41,076	[1]
Revenues recognized during the period that were included in the adoption effect	(1,000)	(2,009)	[2]
Balance at June 30, 2018	159,784	159,784
Contract liabilities at June 30, 2018
Accrued liabilities				$ 24,101	$ 0
Other liabilities				135,683
Total contract liabilities from contracts with customers	$ 159,784	$ 0		$ 159,784	$ 0

[1] Includes $12.5 million for the three months ended June 30, 2018.

[2] Includes $(1.0) million for the three months ended June 30, 2018.

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Revenue from Contracts with Customers - Expected Revenues Table (Details) $ in Thousands	Jun. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 220,037
Performance obligation expected to be satisfied, expected timing	6 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 492,806
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 542,214
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 527,151
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 527,103
Performance obligation expected to be satisfied, expected timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation expected to be satisfied	$ 4,477,339
Performance obligation expected to be satisfied, expected timing

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Revenue from Contracts with Customers - Additional Information (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Revenue from Contracts with Customer [Line Items]
Accounts receivable, net	[1]	$ 167,175	$ 160,432
Customers [Member]
Revenue from Contracts with Customer [Line Items]
Accounts receivable, net		$ 267,100	$ 244,400

[1] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $16.1 million and $36.3 million as of June 30, 2018, and December 31, 2017, respectively.

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Acquisitions and Divestitures - Additional Information (Details) - USD ($) $ in Thousands					3 Months Ended		6 Months Ended
		Jun. 27, 2018	Jun. 01, 2018	Mar. 17, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Property, Plant and Equipment [Line Items]
Acquisition, net investment							$ 161,858
Affiliates [Member]
Property, Plant and Equipment [Line Items]
Cash payment							0	$ 3,910
Settlement of the Deferred purchase price obligation - Anadarko	[1]						0	37,346
Helper and Clawson Systems [Member]
Property, Plant and Equipment [Line Items]
Gain (loss) on sale of assets								16,300
Deferred Purchase Price Obligation - Anadarko [Member] | Affiliates [Member]
Property, Plant and Equipment [Line Items]
Settlement of the Deferred purchase price obligation - Anadarko	[2]				$ 0	$ 37,346	$ 0	37,346
Non-Operated Marcellus Interest [Member]
Property, Plant and Equipment [Line Items]
Percentage ownership interest				33.75%
Whitethorn [Member]
Property, Plant and Equipment [Line Items]
Ownership percentage acquired			20.00%
Acquisition, net investment			$ 150,600
Cactus II [Member]
Property, Plant and Equipment [Line Items]
Ownership percentage acquired		15.00%
Acquisition, net investment		$ 11,300
Delaware Basin JV Gathering LLC [Member]
Property, Plant and Equipment [Line Items]
Ownership percentage acquired				50.00%
Percentage ownership interest				50.00%
Cash payment				$ 155,000
Net gain from property exchange								125,700
Delaware Basin JV Gathering LLC [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | Affiliates [Member]
Property, Plant and Equipment [Line Items]
Settlement of the Deferred purchase price obligation - Anadarko								$ 37,346

[1] See Note 3.

[2] Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).

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Partnership Distributions - Cash Distributions Table (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Jun. 30, 2018	[1]	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017
Distributions Made to Members or Limited Partners [Abstract]
Total quarterly distribution per unit	$ 0.950		$ 0.935	$ 0.920	$ 0.905	$ 0.890	$ 0.875
Total quarterly cash distribution	$ 225,691		$ 221,133	$ 216,586	$ 212,038	$ 207,491	$ 188,753

[1] The Board of Directors declared a cash distribution to the Partnership’s unitholders for the second quarter of 2018 of $0.950 per unit, or $225.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution is payable on August 13, 2018, to unitholders of record at the close of business on August 1, 2018.

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Partnership Distributions - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended	6 Months Ended
	May 02, 2017	Mar. 01, 2017	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Distribution Made to Limited Partner [Line Items]
Partnership agreement day requirement of distribution of available cash				45 days
Incentive distributions percentage				48.00%
Minimum [Member]
Distribution Made to Limited Partner [Line Items]
Distribution sharing percentage				1.50%
Maximum [Member]
Distribution Made to Limited Partner [Line Items]
Distribution sharing percentage				49.50%
Class C Units [Member]
Distribution Made to Limited Partner [Line Items]
Class C units, discount rate percentage on distribution				6.00%
Series A Preferred Units [Member]
Distribution Made to Limited Partner [Line Items]
Series A Preferred units, quarterly distribution per unit					$ 0.68
Series A Preferred units, quarterly cash distribution			$ 7.5
Series A Preferred Units [Member] | Series A Preferred Units March 2017 Conversion [Member]
Distribution Made to Limited Partner [Line Items]
Series A Preferred units, percentage converted		50.00%
Series A Preferred units, common units issued upon conversion		1
Series A Preferred Units [Member] | Series A Preferred Units May 2017 Conversion [Member]
Distribution Made to Limited Partner [Line Items]
Series A Preferred units, percentage converted	50.00%
Series A Preferred units, common units issued upon conversion	1

XML

Equity and Partners' Capital - Partnership Interests Table (Details)	6 Months Ended
	Jun. 30, 2018 shares
Change In Units [Roll Forward]
Balance	168,429,056
Units issued	534,382
Long-Term Incentive Plan award vestings	7,180
Balance	168,970,618
Common Units [Member]
Change In Units [Roll Forward]
Balance	152,602,105
Long-Term Incentive Plan award vestings	7,180
Balance	152,609,285
Class C Units [Member]
Change In Units [Roll Forward]
Balance	13,243,883
Units issued	534,382
Balance	13,778,265
General Partner [Member]
Change In Units [Roll Forward]
Balance	2,583,068
Balance	2,583,068

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Equity and Partners' Capital - Calculation of Net Income (Loss) Per Unit Table (Details) - USD ($) $ / shares in Units, $ in Thousands				3 Months Ended		6 Months Ended
		May 02, 2017	Mar. 01, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings Per Unit [Line Items]
Net income (loss) attributable to Western Gas Partners, LP				$ 32,708	$ 173,451	$ 182,071	$ 275,340
General partner interest in net (income) loss	[1]			(84,176)	(76,365)	(167,615)	(144,527)
Series A Preferred Units [Member]
Earnings Per Unit [Line Items]
Limited partners’ interest in net income (loss)	[2]			$ 0	$ 14,199	$ 0	$ 42,373
Anti-dilutive units excluded from computation of earnings per unit	[3]			0	3,734,000	0	10,901,000
Series A Preferred Units [Member] | Series A Preferred Units March 2017 Conversion [Member]
Earnings Per Unit [Line Items]
Series A Preferred units, percentage converted			50.00%
Series A Preferred units, common units issued upon conversion			1
Series A Preferred Units [Member] | Series A Preferred Units May 2017 Conversion [Member]
Earnings Per Unit [Line Items]
Series A Preferred units, percentage converted		50.00%
Series A Preferred units, common units issued upon conversion		1
Common and Class C Units [Member]
Earnings Per Unit [Line Items]
Limited partners’ interest in net income (loss)	[1]			$ (51,468)	$ 82,887	$ 14,456	$ 88,440
Common Units [Member]
Earnings Per Unit [Line Items]
Limited partners’ interest in net income (loss)	[2]			$ (48,417)	$ 73,383	$ 9,906	$ 75,097
Net income (loss) per common unit – basic and diluted	[3],[4]			$ (0.32)	$ 0.49	$ 0.06	$ 0.53
Weighted-average units outstanding - basic and diluted				152,604,000	148,864,000	152,603,000	141,696,000
Class C Units [Member]
Earnings Per Unit [Line Items]
Limited partners’ interest in net income (loss)	[2]			$ (3,051)	$ 9,504	$ 4,550	$ 13,343
Anti-dilutive units excluded from computation of earnings per unit	[3]			13,649,000	12,650,000	13,516,000	12,552,000

[1] Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 5.

[2] Adjusted to reflect amortization of the beneficial conversion features.

[3] The impact of Class C units would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the three and six months ended June 30, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

[4] See Note 5 for the calculation of net income (loss) per common unit.

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Equity and Partners' Capital - Additional Information (Details) - USD ($) $ in Thousands			1 Months Ended	6 Months Ended		12 Months Ended
	May 02, 2017	Mar. 01, 2017	Nov. 30, 2014	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2017	Jul. 31, 2017
Schedule Of Investments [Line Items]
Units issued				534,382
Series A Preferred units, amortization of beneficial conversion feature				$ 0
General partner units owned				2,583,068				2,583,068
Western Gas Partners, LP [Member] | Western Gas Equity Partners, LP [Member]
Schedule Of Investments [Line Items]
General partner units owned				2,583,068
General partner's interest				1.50%
Class C Units [Member]
Schedule Of Investments [Line Items]
Units issued				534,382
Class C units, common units issued upon conversion				1
Beneficial conversion feature							$ 34,800
Limited partner units owned				13,778,265				13,243,883
Class C Units [Member] | Western Gas Partners, LP [Member] | Other Subsidiaries of Anadarko [Member]
Schedule Of Investments [Line Items]
Limited partner units owned				13,778,265
Class C Units [Member] | Other Subsidiaries of Anadarko [Member]
Schedule Of Investments [Line Items]
Units issued			10,913,853
Series A Preferred Units [Member]
Schedule Of Investments [Line Items]
Series A Preferred units, amortization of beneficial conversion feature					$ 62,300
Series A Preferred Units [Member] | Series A Preferred Units March 2017 Conversion [Member]
Schedule Of Investments [Line Items]
Series A Preferred units, percentage converted		50.00%
Series A Preferred units, common units issued upon conversion		1
Series A Preferred Units [Member] | Series A Preferred Units May 2017 Conversion [Member]
Schedule Of Investments [Line Items]
Series A Preferred units, percentage converted	50.00%
Series A Preferred units, common units issued upon conversion	1
Series A Preferred Units [Member] | Private Investor [Member]
Schedule Of Investments [Line Items]
Units issued						21,922,831
Common Units [Member]
Schedule Of Investments [Line Items]
Limited partner units owned				152,609,285				152,602,105
Common Units [Member] | Western Gas Partners, LP [Member] | Public [Member]
Schedule Of Investments [Line Items]
Limited partner units owned				100,465,859
Limited partner ownership interest				59.50%
Common Units [Member] | Western Gas Partners, LP [Member] | Western Gas Equity Partners, LP [Member]
Schedule Of Investments [Line Items]
Limited partner units owned				50,132,046
Limited partner ownership interest				29.70%
Common Units [Member] | Western Gas Partners, LP [Member] | Other Subsidiaries of Anadarko [Member]
Schedule Of Investments [Line Items]
Limited partner units owned				2,011,380
Incentive Distribution Rights [Member] | Western Gas Partners, LP [Member] | Western Gas Equity Partners, LP [Member]
Schedule Of Investments [Line Items]
General partner's interest				100.00%
Common and Class C Units [Member] | Western Gas Partners, LP [Member] | Other Subsidiaries of Anadarko [Member]
Schedule Of Investments [Line Items]
Limited partner ownership interest				9.30%
July 2017 COP [Member]
Schedule Of Investments [Line Items]
Maximum aggregate principal of common units									$ 500,000

XML

Transactions with Affiliates - Commodity Price Swap Agreements Tables (Details)		Jun. 30, 2018 $ / bbl $ / MMBTU	Dec. 20, 2017 $ / bbl $ / MMBTU	Dec. 01, 2016 $ / bbl $ / MMBTU
DJ Basin Complex [Member] | Years 2017 - 2018 [Member] | Ethane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		18.41
DJ Basin Complex [Member] | Years 2017 - 2018 [Member] | Propane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		47.08
DJ Basin Complex [Member] | Years 2017 - 2018 [Member] | Isobutane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		62.09
DJ Basin Complex [Member] | Years 2017 - 2018 [Member] | Normal Butane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		54.62
DJ Basin Complex [Member] | Years 2017 - 2018 [Member] | Natural Gasoline [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		72.88
DJ Basin Complex [Member] | Years 2017 - 2018 [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		76.47
DJ Basin Complex [Member] | Years 2017 - 2018 [Member] | Natural Gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU		5.96
DJ Basin Complex [Member] | Year 2017 [Member] | Ethane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			5.09
DJ Basin Complex [Member] | Year 2017 [Member] | Propane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			18.85
DJ Basin Complex [Member] | Year 2017 [Member] | Isobutane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			26.83
DJ Basin Complex [Member] | Year 2017 [Member] | Normal Butane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			26.20
DJ Basin Complex [Member] | Year 2017 [Member] | Natural Gasoline [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			41.84
DJ Basin Complex [Member] | Year 2017 [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			45.40
DJ Basin Complex [Member] | Year 2017 [Member] | Natural Gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price | $ / MMBTU	[1]			3.05
DJ Basin Complex [Member] | Year 2018 [Member] | Ethane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		5.41
DJ Basin Complex [Member] | Year 2018 [Member] | Propane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		28.72
DJ Basin Complex [Member] | Year 2018 [Member] | Isobutane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		32.92
DJ Basin Complex [Member] | Year 2018 [Member] | Normal Butane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		32.71
DJ Basin Complex [Member] | Year 2018 [Member] | Natural Gasoline [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		48.04
DJ Basin Complex [Member] | Year 2018 [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		49.36
DJ Basin Complex [Member] | Year 2018 [Member] | Natural Gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price | $ / MMBTU	[1]		2.21
MGR Assets [Member] | Years 2017 - 2018 [Member] | Ethane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		23.11
MGR Assets [Member] | Years 2017 - 2018 [Member] | Propane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		52.90
MGR Assets [Member] | Years 2017 - 2018 [Member] | Isobutane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		73.89
MGR Assets [Member] | Years 2017 - 2018 [Member] | Normal Butane [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		64.93
MGR Assets [Member] | Years 2017 - 2018 [Member] | Natural Gasoline [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		81.68
MGR Assets [Member] | Years 2017 - 2018 [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price		81.68
MGR Assets [Member] | Years 2017 - 2018 [Member] | Natural Gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU		4.87
MGR Assets [Member] | Year 2017 [Member] | Ethane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			4.08
MGR Assets [Member] | Year 2017 [Member] | Propane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			19.24
MGR Assets [Member] | Year 2017 [Member] | Isobutane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			25.79
MGR Assets [Member] | Year 2017 [Member] | Normal Butane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			25.16
MGR Assets [Member] | Year 2017 [Member] | Natural Gasoline [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			45.01
MGR Assets [Member] | Year 2017 [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]			53.55
MGR Assets [Member] | Year 2017 [Member] | Natural Gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price | $ / MMBTU	[1]			3.05
MGR Assets [Member] | Year 2018 [Member] | Ethane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		2.52
MGR Assets [Member] | Year 2018 [Member] | Propane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		25.83
MGR Assets [Member] | Year 2018 [Member] | Isobutane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		30.03
MGR Assets [Member] | Year 2018 [Member] | Normal Butane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		29.82
MGR Assets [Member] | Year 2018 [Member] | Natural Gasoline [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		47.25
MGR Assets [Member] | Year 2018 [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	[1]		56.76
MGR Assets [Member] | Year 2018 [Member] | Natural Gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price | $ / MMBTU	[1]		2.21

[1] Represents the New York Mercantile Exchange forward strip price as of December 1, 2016, and December 20, 2017, for the 2017 Market Prices and 2018 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

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Transactions with Affiliates - Purchases Table (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Related Party Transaction [Line Items]
Partners’ capital adjustment	$ 0	$ (376)
Affiliates [Member]
Related Party Transaction [Line Items]
Cash consideration	0	3,910
Payable to affiliate	254	0
Net carrying value	(254)	(4,286)
Partners’ capital adjustment	$ 0	$ (376)

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Transactions with Affiliates - Summary of Affiliate Transactions Table (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017
Related Party Transaction [Line Items]
Revenues and other		$ 435,949	$ 525,450	$ 873,117		$ 1,041,643
Equity income, net – affiliates	[1]	39,218	21,728	59,642		41,189
Cost of product	[2]	68,149	203,277	145,948		392,636
Operation and maintenance	[2]	100,628	76,148	188,907		149,908
General and administrative	[2]	14,035	10,585	28,167		23,244
Operating expenses		400,601	379,143	670,183		901,659
Interest income	[3]	4,225	4,225	8,450		8,450
Interest expense	[4]	44,389	35,746	83,672		71,250
Distributions to unitholders	[5]			437,719		381,771
Above-market component of swap agreements with Anadarko		13,839	16,373	28,121	[5]	28,670	[5]
Affiliates [Member]
Related Party Transaction [Line Items]
Revenues and other	[1]	238,029	316,313	479,091		631,468
Cost of product	[1]	12,609	21,607	32,853		37,595
Operation and maintenance	[6]	23,437	18,462	43,685		35,551
General and administrative	[7]	11,178	9,365	22,792		18,900
Operating expenses		47,224	49,434	99,330		92,046
Interest expense	[8]	0	0	0		71
Settlement of the Deferred purchase price obligation - Anadarko	[9]			0		(37,346)
Distributions to unitholders	[10]	127,204	110,449	251,368		213,572
Affiliates [Member] | Deferred Purchase Price Obligation - Anadarko [Member]
Related Party Transaction [Line Items]
Settlement of the Deferred purchase price obligation - Anadarko	[11]	$ 0	$ (37,346)	$ 0		$ (37,346)

[1] Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[2] Cost of product includes product purchases from Anadarko (as defined in Note 1) of $12.6 million and $32.9 million for the three and six months ended June 30, 2018, respectively, and $21.6 million and $37.6 million for the three and six months ended June 30, 2017, respectively. Operation and maintenance includes charges from Anadarko of $23.4 million and $43.7 million for the three and six months ended June 30, 2018, respectively, and $18.5 million and $35.6 million for the three and six months ended June 30, 2017, respectively. General and administrative includes charges from Anadarko of $11.2 million and $22.8 million for the three and six months ended June 30, 2018, respectively, and $9.4 million and $18.9 million for the three and six months ended June 30, 2017, respectively. See Note 6.

[3] Represents interest income recognized on the note receivable from Anadarko.

[4] Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and six months ended June 30, 2017, respectively. See Note 10.

[5] See Note 6.

[6] Represents expenses incurred on and subsequent to the date of the acquisition of 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.

[7] Represents general and administrative expense incurred on and subsequent to the date of the acquisition of 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 Anadarko Incentive Plan within this Note 6).

[8] Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3 and Note 10).

[9] See Note 3.

[10] Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

[11] Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).

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Transactions with Affiliates - Additional Information (Details) - USD ($)		1 Months Ended	3 Months Ended		6 Months Ended
		May 31, 2008	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Note receivable - Anadarko			$ 260,000,000		$ 260,000,000		$ 260,000,000
Above-market component of swap agreements with Anadarko	[1]				28,121,000
Contributions of equity-based compensation from Anadarko					2,792,000
Anadarko Incentive Plan [Member]
Related Party Transaction [Line Items]
Equity-based compensation expense			1,700,000	$ 900,000	3,800,000	$ 2,100,000
Contributions of equity-based compensation from Anadarko					$ 2,792,000
Western Gas Partners Long Term Incentive Plan [Member]
Related Party Transaction [Line Items]
Units vesting period					3 years
Equity-based compensation expense			$ 100,000	$ 100,000	$ 200,000	$ 200,000
Natural Gas [Member] | Gathering, Treating, Transportation and Disposal [Member]
Related Party Transaction [Line Items]
Affiliate throughput percent			35.00%	38.00%	35.00%	34.00%
Natural Gas [Member] | Processing [Member]
Related Party Transaction [Line Items]
Affiliate throughput percent			35.00%	39.00%	35.00%	44.00%
Crude Oil, NGL and Produced Water [Member] | Gathering, Treating, Transportation and Disposal [Member]
Related Party Transaction [Line Items]
Affiliate throughput percent			72.00%	41.00%	68.00%	47.00%
Commodity Price Swap Agreement [Member]
Related Party Transaction [Line Items]
Net gains (losses) on commodity price swap agreements			$ (1,372,000)		$ (2,615,000)
Affiliates [Member]
Related Party Transaction [Line Items]
Note receivable - Anadarko		$ 260,000,000
Note receivable, due date		May 14, 2038
Fixed annual rate for note receivable bearing interest		6.50%
Affiliates [Member] | Commodity Price Swap Agreement [Member]
Related Party Transaction [Line Items]
Net gains (losses) on commodity price swap agreements			(1,372,000)	$ 1,000,000	(2,615,000)	$ 500,000
Affiliates [Member] | Level 2 Inputs [Member] | Valuation, Market Approach [Member]
Related Party Transaction [Line Items]
Fair value of the note receivable			$ 304,700,000		$ 304,700,000		$ 325,200,000
Independent Director [Member] | Western Gas Partners Long Term Incentive Plan [Member]
Related Party Transaction [Line Items]
Units vesting period					1 year

[1] See Note 6.

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Property, Plant and Equipment - Historical Cost Table (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 8,618,993	$ 7,864,535
Less accumulated depreciation	2,405,419	2,133,644
Net property, plant and equipment	6,213,574	5,730,891
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	4,653	4,450
Gathering Systems and Processing Complexes [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 7,565,998	7,113,114
Gathering Systems and Processing Complexes [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Gathering Systems and Processing Complexes [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	47 years
Pipelines and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 137,769	137,644
Pipelines and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	15 years
Pipelines and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	45 years
Assets Under Construction [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 879,095	579,501
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 31,478	$ 29,826
Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	40 years

XML

Property, Plant and Equipment - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Impairments	$ 127,243,000	$ 3,178,000	$ 127,391,000	$ 167,920,000	$ 178,400,000
Fort Union [Member]
Property, Plant and Equipment [Line Items]
Equity investment impairment loss					3,100,000
Third Creek Gathering System [Member]
Property, Plant and Equipment [Line Items]
Impairments			120,800,000
Third Creek Gathering System [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 Inputs [Member] | Valuation, Market Approach [Member]
Property, Plant and Equipment [Line Items]
Estimated salvage value	1,000,000		1,000,000
Kitty Draw Gathering System [Member]
Property, Plant and Equipment [Line Items]
Impairments			6,400,000
Kitty Draw Gathering System [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 Inputs [Member] | Valuation, Market Approach [Member]
Property, Plant and Equipment [Line Items]
Estimated salvage value	$ 0		$ 0
Granger Complex [Member]
Property, Plant and Equipment [Line Items]
Impairments					158,800,000
Granger Complex [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 Inputs [Member] | Valuation, Income Approach [Member]
Property, Plant and Equipment [Line Items]
Estimated fair value					48,500,000
Equipment [Member]
Property, Plant and Equipment [Line Items]
Impairments					19,600,000
Hilight System [Member]
Property, Plant and Equipment [Line Items]
Impairments					8,200,000
Granger Straddle Plant [Member]
Property, Plant and Equipment [Line Items]
Impairments					3,700,000
Granger Straddle Plant [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 Inputs [Member] | Valuation, Income Approach [Member]
Property, Plant and Equipment [Line Items]
Estimated salvage value					600,000
Northeast Wyoming Facility [Member]
Property, Plant and Equipment [Line Items]
Impairments					2,000,000
Northeast Wyoming Facility [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 Inputs [Member] | Valuation, Market Approach [Member]
Property, Plant and Equipment [Line Items]
Estimated salvage value					$ 400,000

XML

Equity Investments - Equity Investments Table (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017
Schedule of Equity Method Investments [Line Items]
Balance				$ 566,211
Acquisitions				161,858
Investment earnings (loss), net of amortization	[1]	$ 39,218	$ 21,728	59,642		$ 41,189
Contributions				27,474
Capitalized interest				16
Distributions				(48,396)		(42,202)
Distributions in excess of cumulative earnings				(12,505)	[2]	$ (9,221)
Balance		754,300		754,300
Fort Union [Member]
Schedule of Equity Method Investments [Line Items]
Balance				7,030
Acquisitions				0
Investment earnings (loss), net of amortization				(444)
Contributions				0
Capitalized interest				0
Distributions				(194)
Distributions in excess of cumulative earnings	[2]			(2,658)
Balance		3,734		3,734
White Cliffs [Member]
Schedule of Equity Method Investments [Line Items]
Balance				44,945
Acquisitions				0
Investment earnings (loss), net of amortization				5,898
Contributions				1,278
Capitalized interest				0
Distributions				(5,607)
Distributions in excess of cumulative earnings	[2]			(1,958)
Balance		44,556		44,556
Rendezvous [Member]
Schedule of Equity Method Investments [Line Items]
Balance				42,528
Acquisitions				0
Investment earnings (loss), net of amortization				439
Contributions				0
Capitalized interest				0
Distributions				(1,410)
Distributions in excess of cumulative earnings	[2]			(1,784)
Balance		39,773		39,773
Mont Belvieu JV [Member]
Schedule of Equity Method Investments [Line Items]
Balance				110,299
Acquisitions				0
Investment earnings (loss), net of amortization				15,200
Contributions				0
Capitalized interest				0
Distributions				(15,219)
Distributions in excess of cumulative earnings	[2]			(2,131)
Balance		108,149		108,149
TEFR Interests [Member]
Schedule of Equity Method Investments [Line Items]
Balance				361,409
Acquisitions				0
Investment earnings (loss), net of amortization				33,037
Contributions				0
Capitalized interest				0
Distributions				(25,966)
Distributions in excess of cumulative earnings	[2]			(3,974)
Balance		364,506		364,506
Whitethorn [Member]
Schedule of Equity Method Investments [Line Items]
Balance				0
Acquisitions				150,563
Investment earnings (loss), net of amortization				5,512
Contributions				7,069
Capitalized interest				0
Distributions				0
Distributions in excess of cumulative earnings	[2]			0
Balance		163,144		163,144
Cactus II [Member]
Schedule of Equity Method Investments [Line Items]
Balance				0
Acquisitions				11,295
Investment earnings (loss), net of amortization				0
Contributions				19,127
Capitalized interest				16
Distributions				0
Distributions in excess of cumulative earnings	[2]			0
Balance		$ 30,438		$ 30,438

[1] Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.

[2] Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual investment basis.

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Components of Working Capital - Accounts Receivable, Net Table (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Receivables [Abstract]
Trade receivables, net		$ 167,116	$ 160,387
Other receivables, net		59	45
Total accounts receivable, net	[1]	$ 167,175	$ 160,432

[1] Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $16.1 million and $36.3 million as of June 30, 2018, and December 31, 2017, respectively.

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Components of Working Capital - Other Current Assets Table (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Other Current Assets [Line Items]
Natural gas liquids inventory		$ 9,421	$ 10,788
Imbalance receivables		7,703	1,640
Prepaid insurance		264	2,388
Contract assets		9,340	0
Total other current assets	[1]	$ 26,728	$ 14,816

[1] Other current assets includes affiliate amounts of $9.3 million and zero as of June 30, 2018, and December 31, 2017, respectively.

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Components of Working Capital - Accrued Liabilities Table (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2018	Dec. 31, 2017
Components Of Working Capital [Abstract]
Accrued interest expense		$ 58,753	$ 40,632
Short-term asset retirement obligations	[1]	42,312	2,304
Short-term remediation and reclamation obligations		833	833
Income taxes payable		2,756	2,495
Contract liabilities		24,101	0
Other		2,597	1,635
Total accrued liabilities	[2]	131,352	$ 47,899
Liabilities incurred		$ 40,200

[1] As of June 30, 2018, includes $40.2 million of short-term liabilities incurred related to the shutdowns at the Third Creek and Kitty Draw gathering systems. See Note 1 for further information.

[2] Accrued liabilities includes affiliate amounts of $2.3 million and $0.2 million as of June 30, 2018, and December 31, 2017, respectively.

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Debt and Interest Expense - Debt Outstanding Table (Details) - USD ($)		Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total long-term debt, principal		$ 4,220,000,000	$ 3,490,000,000
Carrying value		4,177,353,000	3,464,712,000
Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	4,111,452,000	3,594,177,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Principal		0	370,000,000
Carrying value		0	370,000,000
Revolving Credit Facility [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	0	370,000,000
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Principal		350,000,000	350,000,000
Carrying value		349,937,000	349,684,000
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	349,832,000	350,631,000
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Principal		500,000,000	500,000,000
Carrying value		496,380,000	495,815,000
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	520,037,000	530,647,000
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Principal		670,000,000	670,000,000
Carrying value		668,962,000	668,849,000
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	665,356,000	684,043,000
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Principal		500,000,000	500,000,000
Carrying value		492,356,000	491,885,000
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	475,739,000	500,885,000
Senior Notes [Member] | 4.650% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Principal		500,000,000	500,000,000
Carrying value		495,475,000	495,245,000
Senior Notes [Member] | 4.650% Senior Notes due 2026 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	492,415,000	520,144,000
Senior Notes [Member] | 4.500% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Principal		400,000,000	0
Carrying value		394,399,000	0
Senior Notes [Member] | 4.500% Senior Notes due 2028 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	386,234,000	0
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Principal		600,000,000	600,000,000
Carrying value		593,290,000	593,234,000
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	569,855,000	637,827,000
Senior Notes [Member] | 5.300% Senior Notes due 2048 [Member]
Debt Instrument [Line Items]
Principal		700,000,000	0
Carrying value		686,554,000	0
Senior Notes [Member] | 5.300% Senior Notes due 2048 [Member] | Valuation, Market Approach [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[1]	$ 651,984,000	$ 0

[1] Fair value is measured using the market approach and Level 2 inputs.

XML

Debt and Interest Expense - Debt Activity Table (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018 USD ($)
Changes in Debt Outstanding [Roll Forward]
Beginning balance	$ 3,464,712
Other	(17,359)
Ending balance	4,177,353
Revolving Credit Facility [Member]
Changes in Debt Outstanding [Roll Forward]
Beginning balance	370,000
RCF borrowings	260,000
Repayments of RCF borrowings	(630,000)
Ending balance	0
4.500% Senior Notes due 2028 [Member] | Senior Notes [Member]
Changes in Debt Outstanding [Roll Forward]
Beginning balance	0
Issuance of senior notes	400,000
Ending balance	394,399
5.300% Senior Notes due 2048 [Member] | Senior Notes [Member]
Changes in Debt Outstanding [Roll Forward]
Beginning balance	0
Issuance of senior notes	700,000
Ending balance	$ 686,554

XML

Debt and Interest Expense - Interest Expense Table (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Debt Instrument [Line Items]
Interest expense	[1]	$ (44,389)	$ (35,746)	$ (83,672)	$ (71,250)
Third Parties [Member]
Debt Instrument [Line Items]
Long-term debt		(48,394)	(35,161)	(89,677)	(69,780)
Amortization of debt issuance costs and commitment fees		(2,006)	(1,645)	(4,060)	(3,275)
Capitalized interest		6,011	1,060	10,065	1,876
Interest expense		(44,389)	(35,746)	(83,672)	(71,179)
Affiliates [Member]
Debt Instrument [Line Items]
Interest expense	[2]	0	0	0	(71)
Affiliates [Member] | Deferred Purchase Price Obligation - Anadarko [Member]
Debt Instrument [Line Items]
Deferred purchase price obligation - Anadarko	[3]	$ 0	$ 0	$ 0	$ (71)

[1] Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and six months ended June 30, 2017, respectively. See Note 10.

[2] Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3 and Note 10).

[3] See Note 3 for a discussion of the Deferred purchase price obligation - Anadarko.

XML

Debt and Interest Expense - Additional Information (Details) - USD ($)		6 Months Ended
	Feb. 16, 2018	Jun. 30, 2018	Jun. 30, 2017	Feb. 25, 2014
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Facility, maximum borrowing capacity	$ 1,500,000,000.0			$ 1,200,000,000.0
Facility, expandable maximum borrowing capacity	$ 2,000,000,000
Facility, expiration date	Feb. 15, 2023
Facility, fee rate		0.20%	0.20%
Facility, outstanding borrowings		$ 0
Outstanding letters of credit		4,600,000
Facility, available borrowing capacity		$ 1,495,400,000
Facility, interest rate at period end		3.39%	2.53%
Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Facility, fee rate		0.125%
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Facility, fee rate		0.25%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin added		1.00%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin added		1.50%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added		1.00%
Revolving Credit Facility [Member] | Percentage Above Federal Funds Effective Rate [Member] | Alternate Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added		0.50%
Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin added		0.00%
Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin added		0.50%
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		2.60%
Debt instrument, maturity date		Aug. 15, 2018
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		5.375%
Debt instrument, maturity date		Jun. 01, 2021
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		4.00%
Debt instrument, maturity date		Jul. 01, 2022
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		3.95%
Debt instrument, maturity date		Jun. 01, 2025
Senior Notes [Member] | 4.650% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		4.65%
Debt instrument, maturity date		Jul. 01, 2026
Senior Notes [Member] | 4.500% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		4.50%
Debt instrument, maturity date		Mar. 01, 2028
Offering percent		99.435%
Effective interest rate		4.682%
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		5.45%
Debt instrument, maturity date		Apr. 01, 2044
Senior Notes [Member] | 5.300% Senior Notes due 2048 [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		5.30%
Debt instrument, maturity date		Mar. 01, 2048
Offering percent		99.169%
Effective interest rate		5.431%

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Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
	Mar. 17, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Loss Contingencies [Line Items]
Contract liabilities		$ 24,101		$ 24,101		$ 0
Rent expense associated with office and equipment leases		12,200	$ 12,200	25,900	$ 20,700
DBJV Arbitration [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Gathering fees sought in arbitration				194,200
Fees sought in counterclaim				$ 14,900
Percentage recovery from third party				50.00%
Percentage due to third party				50.00%
Contract liabilities		$ 7,500		$ 7,500
Delaware Basin JV Gathering LLC [Member] | DBJV Arbitration [Member]
Loss Contingencies [Line Items]
Percentage ownership interest	50.00%
Percentage third-party ownership interest	50.00%