Western Midstream Partners 10-K 25 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Trading Symbol	WES
Entity Registrant Name	Western Gas Partners LP
Entity Central Index Key	1,414,475
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 4.9
Entity Common Units Outstanding		128,576,965

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Revenues and Other
Total revenues and other		$ 1,561,372	$ 1,382,868	[1]	$ 1,085,482	[1]
Equity income, net	[2],[3],[4]	71,251	57,836	[1]	22,948	[1]
Operating expenses
Cost of product	[5]	528,435	454,445	[1]	373,171	[1]
Operation and maintenance	[5]	296,774	255,844	[1]	201,759	[1]
General and administrative	[5]	38,108	36,223	[1]	31,353	[1]
Property and other taxes		30,533	26,066	[1]	23,806	[1]
Depreciation and amortization		244,163	186,514	[1]	149,815	[1]
Impairments		514,096	3,084	[1]	1,267	[1]
Total operating expenses		1,652,109	962,176	[1]	781,171	[1]
Gain on divestiture and other, net	[6]	57,020	0	[1]	0	[1]
Operating income (loss)		37,534	478,528	[1]	327,259	[1]
Interest income - affiliates	[7]	16,900	16,900	[1]	16,900	[1]
Interest expense	[8]	(113,872)	(76,766)	[1]	(51,797)	[1]
Other income (expense), net		(619)	864	[1]	1,837	[1]
Income (loss) before income taxes		(60,057)	419,526	[1]	294,199	[1]
Income tax (benefit) expense		3,380	11,659	[1]	4,660	[1]
Net income (loss)		(63,437)	407,867	[1]	289,539	[1]
Net income attributable to noncontrolling interest		10,101	14,025	[1]	10,816	[1]
Net income (loss) attributable to Western Gas Partners, LP		(73,538)	393,842	[1]	278,723	[1]
Limited partners' interest in net income (loss):
Pre-acquisition net (income) loss allocated to Anadarko		(1,742)	(16,353)	[1]	(8,224)	[1]
General partner interest in net (income) loss	[9]	(180,996)	(120,980)	[1]	(69,633)	[1]
Limited partners' interest in net income (loss)	[9]	$ (256,276)	$ 256,509	[1]	$ 200,866	[1]
Net income (loss) per common unit - basic	[10]	$ (1.95)	$ 2.13	[1]	$ 1.83	[1]
Net income (loss) per common unit - diluted	[10],[11]	$ (1.95)	$ 2.12	[1]	$ 1.83	[1]
Affiliates [Member]
Revenues and Other
Gathering, processing and transportation of natural gas and natural gas liquids		$ 581,644	$ 467,540	[1]	$ 340,116	[1]
Natural gas, natural gas liquids and drip condensate sales		447,106	581,317	[1]	502,219	[1]
Other		1,172	5,078	[1]	1,868	[1]
Total revenues and other	[4]	1,029,922	1,053,935	[1]	844,203	[1]
Operating expenses
Cost of product	[4]	167,420	127,906		136,570
Operation and maintenance	[12]	67,119	62,306		59,698
General and administrative	[13]	30,692	28,970		24,956
Total operating expenses		265,231	219,182		221,224
Interest expense	[14]	(14,398)	0		0
Third Parties [Member]
Revenues and Other
Gathering, processing and transportation of natural gas and natural gas liquids		356,477	277,605	[1]	190,877	[1]
Natural gas, natural gas liquids and drip condensate sales		170,843	42,916	[1]	46,289	[1]
Other		4,130	8,412	[1]	4,113	[1]
Total revenues and other		531,450	328,933	[1]	241,279	[1]
Operating expenses
Interest expense		$ (99,474)	$ (76,766)		$ (51,797)
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Income earned from equity investments is classified as affiliate. See Note 1.
[3]	Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.
[4]	Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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.
[5]	Cost of product includes product purchases from Anadarko (as defined in Note 1) of $167.4 million, $127.9 million and $136.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Operation and maintenance includes charges from Anadarko of $67.1 million, $62.3 million and $59.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. General and administrative includes charges from Anadarko of $30.7 million, $29.0 million and $25.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 5.
[6]	Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1.
[7]	Represents interest income recognized on the note receivable from Anadarko.
[8]	Includes affiliate (as defined in Note 1) interest expense of $14.4 million for the year ended December 31, 2015, and zero for each of the years ended December 31, 2014 and 2013. See Note 2 and Note 12.
[9]	Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 4.
[10]	See Note 4 for the calculation of net income (loss) per common unit.
[11]	Inclusion of Class C units in the calculation for the year ended December 31, 2015, would have had an anti-dilutive effect.
[12]	Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
[13]	Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).
[14]	For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 12).

Consolidated Statements of Inc3

Consolidated Statements of Income (Parenthetical) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Cost of product	[1]	$ 528,435	$ 454,445	[2]	$ 373,171	[2]
Operation and maintenance	[1]	296,774	255,844	[2]	201,759	[2]
General and administrative	[1]	38,108	36,223	[2]	31,353	[2]
Interest expense	[3]	113,872	76,766	[2]	51,797	[2]
Affiliates [Member]
Cost of product	[4]	167,420	127,906		136,570
Operation and maintenance	[5]	67,119	62,306		59,698
General and administrative	[6]	30,692	28,970		24,956
Interest expense	[7]	$ 14,398	$ 0		$ 0
[1]	Cost of product includes product purchases from Anadarko (as defined in Note 1) of $167.4 million, $127.9 million and $136.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Operation and maintenance includes charges from Anadarko of $67.1 million, $62.3 million and $59.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. General and administrative includes charges from Anadarko of $30.7 million, $29.0 million and $25.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 5.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[3]	Includes affiliate (as defined in Note 1) interest expense of $14.4 million for the year ended December 31, 2015, and zero for each of the years ended December 31, 2014 and 2013. See Note 2 and Note 12.
[4]	Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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.
[5]	Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
[6]	Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).
[7]	For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 12).

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014	[1]
Current assets
Cash and cash equivalents		$ 98,033	$ 67,054	[2]
Accounts receivable, net	[3]	180,993	109,243
Other current assets	[4]	7,855	10,053
Total current assets		286,881	186,350
Note receivable - Anadarko		260,000	260,000
Property, plant and equipment
Cost		5,904,637	5,626,650
Less accumulated depreciation		1,614,663	1,055,207
Net property, plant and equipment		4,289,974	4,571,443
Goodwill		389,686	389,087
Other intangible assets		832,127	884,857
Equity investments		618,887	634,492
Other assets		29,707	28,289
Total assets		6,707,262	6,954,518
Current liabilities
Accounts and imbalance payables	[5]	64,606	54,232
Accrued ad valorem taxes		17,808	14,812
Accrued liabilities		116,818	170,789
Total current liabilities		199,232	239,833
Long-term debt		2,707,357	2,422,954
Deferred income taxes		5,963	45,642
Asset retirement obligations and other		118,606	111,714
Deferred purchase price obligation - Anadarko	[6]	188,674	0
Total long-term liabilities		3,020,600	2,580,310
Total liabilities		3,219,832	2,820,143
Equity and partners' capital
General partner units (2,583,068 units issued and outstanding at December 31, 2015 and 2014)		120,164	105,725
Net investment by Anadarko		0	122,509
Total partners' capital		3,420,046	4,064,905
Noncontrolling interest		67,384	69,470
Total equity and partners' capital		3,487,430	4,134,375
Total liabilities, equity and partners' capital		6,707,262	6,954,518
Common Units [Member]
Equity and partners' capital
Common units (128,576,965 and 127,695,130 units issued and outstanding at December 31, 2015 and 2014, respectively) and Class C Units (11,411,862 and 10,913,853 units issued and outstanding at December 31, 2015 and 2014, respectively)		2,588,991	3,119,714
Class C Units [Member]
Equity and partners' capital
Common units (128,576,965 and 127,695,130 units issued and outstanding at December 31, 2015 and 2014, respectively) and Class C Units (11,411,862 and 10,913,853 units issued and outstanding at December 31, 2015 and 2014, respectively)		$ 710,891	$ 716,957
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[3]	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $42.7 million and $64.7 million as of December 31, 2015 and 2014, respectively. Accounts receivable, net as of December 31, 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.
[4]	Other current assets includes imbalance receivables from affiliates of zero and $0.2 million as of December 31, 2015 and 2014, respectively.
[5]	Accounts and imbalance payables includes amounts payable to affiliates of zero and $0.1 million as of December 31, 2015 and 2014, respectively.
[6]	See Note 2.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
General partner units issued		2,583,068	2,583,068
General partner units outstanding		2,583,068	2,583,068
Accounts receivable, net	[1]	$ 180,993	$ 109,243	[2]
Other current assets	[3]	7,855	10,053	[2]
Accounts and imbalance payables	[4]	$ 64,606	$ 54,232	[2]
Common Units [Member]
Units issued		128,576,965	127,695,130
Units outstanding		128,576,965	127,695,130
Class C Units [Member]
Units issued		11,411,862	10,913,853
Units outstanding		11,411,862	10,913,853
Affiliates [Member]
Accounts receivable, net		$ 42,700	$ 64,700
Other current assets		0	200
Accounts and imbalance payables		$ 0	$ 100
[1]	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $42.7 million and $64.7 million as of December 31, 2015 and 2014, respectively. Accounts receivable, net as of December 31, 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[3]	Other current assets includes imbalance receivables from affiliates of zero and $0.2 million as of December 31, 2015 and 2014, respectively.
[4]	Accounts and imbalance payables includes amounts payable to affiliates of zero and $0.1 million as of December 31, 2015 and 2014, respectively.

Consolidated Statements of Equi

Consolidated Statements of Equity and Partners' Capital - USD ($) $ in Thousands		Total		Net Investment by Anadarko [Member]	Common Units [Member]	Class C Units [Member]	General Partner Units [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2012	[1]	$ 2,500,020		$ 419,544	$ 1,957,066	$ 0	$ 52,752	$ 70,658
Net income (loss)		289,539	[2]	8,224	200,866		69,633	10,816
Issuance of common and general partner units, net of offering expenses		740,586			724,811		15,775
Contributions from noncontrolling interest owner		2,247						2,247
Distributions to noncontrolling interest owner		(13,127)						(13,127)
Distributions to unitholders		(299,101)			(239,157)		(59,944)
Acquisitions from affiliates		(465,500)		(255,635)	(209,865)
Contributions of equity-based compensation from Anadarko	[3]	2,923			2,865		58
Net pre-acquisition contributions from (distributions to) Anadarko	[4]	194,592		194,592
Net distributions to Anadarko of other assets		(5,855)	[2]		(5,738)		(117)
Elimination of net deferred tax liabilities		46,530		46,530
Other		345			345
Balance at Dec. 31, 2013	[1]	2,993,199		413,255	2,431,193	0	78,157	70,594
Net income (loss)		407,867	[2]	16,353	254,737	1,772	120,980	14,025
Issuance of common and general partner units, net of offering expenses		704,728			691,417		13,311
Issuance of Class C units		750,000				750,000
Beneficial conversion feature of Class C units		0			34,815	(34,815)
Distributions to noncontrolling interest owner		(15,149)						(15,149)
Distributions to unitholders		(408,621)			(302,049)		(106,572)
Acquisitions from affiliates		(356,250)		(372,784)	16,534
Contributions of equity-based compensation from Anadarko	[3]	3,167			3,104		63
Net pre-acquisition contributions from (distributions to) Anadarko	[4]	27,525		27,525
Net distributions to Anadarko of other assets		(10,733)	[2]		(10,519)		(214)
Elimination of net deferred tax liabilities		38,160		38,160
Other		482			482
Balance at Dec. 31, 2014	[1]	4,134,375		122,509	3,119,714	716,957	105,725	69,470
Net income (loss)		(63,437)		1,742	(238,166)	(18,110)	180,996	10,101
Above-market component of swap extensions with Anadarko	[5]	18,449			18,449
Issuance of common and general partner units, net of offering expenses		57,353			57,353
Amortization of beneficial conversion feature of Class C units		0			(12,044)	12,044
Distributions to noncontrolling interest owner		(12,187)						(12,187)
Distributions to unitholders		(545,143)			(378,602)		(166,541)
Acquisitions from affiliates		(174,276)		(197,562)	23,286
Contributions of equity-based compensation from Anadarko	[3]	3,551			3,480		71
Net pre-acquisition contributions from (distributions to) Anadarko		31,467		31,467
Net distributions to Anadarko of other assets		(4,767)			(4,680)		(87)
Elimination of net deferred tax liabilities		41,844		41,844
Other		201			201
Balance at Dec. 31, 2015		$ 3,487,430		$ 0	$ 2,588,991	$ 710,891	$ 120,164	$ 67,384
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[3]	Associated with the Anadarko Incentive Plans as defined and described in Note 1 and Note 5.
[4]	Includes deferred taxes on capitalized interest of $0.3 million and $5.5 million associated with the acquisition of the TEFR Interests (as defined and described in Note 1) for the years ended December 31, 2014 and 2013, respectively.
[5]	See Note 5.

Consolidated Statements of Equ7

Consolidated Statements of Equity and Partners Capital (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Deferred taxes on capitalized interest	$ (38,160)	$ (46,530)
Net Investment by Anadarko [Member]
Deferred taxes on capitalized interest	(38,160)	(46,530)
Net Investment by Anadarko [Member] | Capitalized Interest [Member]
Deferred taxes on capitalized interest	$ 300	$ 5,500

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Cash flows from operating activities
Net income (loss)		$ (63,437)		$ 407,867	[1]	$ 289,539	[1]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		244,163		186,514	[1]	149,815	[1]
Impairments		514,096		3,084	[1]	1,267	[1]
Non-cash equity-based compensation expense		4,188		3,920	[1]	3,521	[1]
Deferred income taxes		1,932		13,325	[1]	40,035	[1]
Accretion and amortization of long-term obligations, net		17,698		2,736	[1]	2,449	[1]
Equity income, net	[2],[3],[4]	(71,251)		(57,836)	[1]	(22,948)	[1]
Distributions from equity investment earnings	[3]	82,054		62,967	[1]	17,698	[1]
Gain on divestiture and other, net	[5]	(57,020)		0	[1]	0	[1]
Lower of cost or market inventory adjustments		443		0	[1]	0	[1]
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net		(5,614)		(6,691)	[1]	(13,936)	[1]
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net		3,154		(39,162)	[1]	28,867	[1]
Change in other items, net		(797)		3,485	[1]	(3,702)	[1]
Net cash provided by operating activities		669,609		580,209	[1]	492,605	[1]
Cash flows from investing activities
Capital expenditures		(602,289)		(722,443)	[1]	(681,999)	[1]
Investments in equity affiliates		(11,442)		(64,278)	[1]	(294,693)	[1]
Distributions from equity investments in excess of cumulative earnings	[3]	16,244	[6]	18,055	[1],[6]	4,438	[1]
Net cash used in investing activities		(466,424)		(2,670,998)	[1]	(1,688,523)	[1]
Cash flows from financing activities
Borrowings, net of debt issuance costs		889,606		1,646,878	[1]	957,503	[1]
Repayments of debt		(610,000)		(650,000)	[1]	(710,000)	[1]
Increase (decrease) in outstanding checks		(1,751)		1,693	[1]	(1,763)	[1]
Proceeds from the issuance of common and general partner units, net of offering expenses		57,353		704,489	[1]	740,825	[1]
Distributions to unitholders	[7]	(545,143)		(408,621)	[1]	(299,101)	[1]
Contributions from noncontrolling interest owner		0		0	[1]	2,247	[1]
Distributions to noncontrolling interest owner		(12,187)		(15,149)	[1]	(13,127)	[1]
Net contributions from Anadarko		31,467		27,825	[1]	200,081	[1]
Above-market component of swap extensions with Anadarko	[7]	18,449		0	[1]	0	[1]
Net cash provided by (used in) financing activities		(172,206)		2,057,115	[1]	876,665	[1]
Net increase (decrease) in cash and cash equivalents		30,979		(33,674)	[1]	(319,253)	[1]
Cash and cash equivalents at beginning of period	[1]	67,054	[8]	100,728		419,981
Cash and cash equivalents at end of period		98,033		67,054	[1],[8]	100,728	[1]
Supplemental disclosures
Net distributions to (contributions from) Anadarko of other assets		4,767		10,733	[1]	5,855	[1]
Interest paid, net of capitalized interest		94,720		67,648	[1]	47,098	[1]
Taxes paid (reimbursements received)		0		(90)	[1]	552	[1]
Capital lease asset transfer		0		4,833	[1],[9]	0	[1]
Delaware Basin JV Gathering LLC [Member]
Cash flows from operating activities
Net income (loss)				17,309		4,096
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity income, net				0		0
Supplemental disclosures
Acquisition of DBJV from Anadarko		174,276		0	[1]	0	[1]
Class C Units [Member]
Cash flows from financing activities
Proceeds from the issuance of Class C units		0		750,000	[1]	0	[1]
Affiliates [Member]
Cash flows from investing activities
Contributions in aid of construction costs from affiliates		461		183	[1]	617	[1]
Acquisitions		(12,664)		(379,193)	[1]	(476,711)	[1]
Proceeds from the sale of assets		925		0	[1]	85	[1]
Cash flows from financing activities
Distributions to unitholders	[10]	(314,200)		(234,024)		(169,150)
Third Parties [Member]
Cash flows from investing activities
Acquisitions		(3,514)		(1,523,327)	[1]	(240,274)	[1]
Proceeds from the sale of assets		$ 145,855		$ 5	[1]	$ 14	[1]
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Income earned from equity investments is classified as affiliate. See Note 1.
[3]	Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.
[4]	Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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.
[5]	Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1.
[6]	Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.
[7]	See Note 5.
[8]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[9]	For the year ended December 31, 2014, represents transfers of $4.6 million from other long-term assets associated with the capital lease component of a processing agreement. See Note 7.
[10]	Represents distributions paid under the partnership agreement (see Note 3 and Note 4).

Consolidated Statements of Cas9

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, plant and equipment	$ 5,904,637	$ 5,626,650	[1]
Natural Gas Processing Plant [Member]
Property, plant and equipment		$ 4,600
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop and operate midstream energy assets. For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership (see Western Gas Equity Partners, LP below). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, and includes equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “Equity investment throughput” refers to the Partnership’s 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of the Partnership’s 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput. The “DJ Basin complex” refers to the Platte Valley system, Wattenberg system and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014. The “MGR assets” include the Red Desert complex, the Granger straddle plant and the 22% interest in Rendezvous. The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. As of December 31, 2015 , the Partnership’s assets and investments accounted for under the equity method consisted of the following: Owned and Operated Operated Interests Non-Operated Interests Equity Interests Natural gas gathering systems 12 2 5 2 Natural gas treating facilities 12 4 — 3 Natural gas processing plants/trains (1) 18 5 — 2 NGL pipelines 2 — — 3 Natural gas pipelines 4 — — — Oil pipeline — — — 1 (1) On December 3, 2015, an incident occurred at the DBM complex. See Note 7 . These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), North-central Pennsylvania and Texas. In June 2015, the Partnership completed the construction and commenced operations of Lancaster Train II, a processing plant located within the DJ Basin complex. In addition, the Partnership is constructing Trains IV and V, both processing plants, at the DBM complex (see Note 2 ), with operations expected to commence during the first half (Train IV) and second half (Train V) of 2016. The Partnership has also made progress payments towards the construction of another cryogenic unit at our DBM complex (Train VI), with an expected in-service date of mid-2017. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Western Gas Equity Partners, LP. WGP owns the following types of interests in the Partnership: (i) the general partner interest and all of the incentive distribution rights (“IDRs”) in the Partnership, both owned through WGP’s 100% ownership of the Partnership’s general partner and (ii) a significant limited partner interest (see Holdings of Partnership equity in Note 4 ). WGP has no independent operations or material assets other than owning such partnership interests. Basis of presentation. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated. 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. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 33.75% share of the assets, liabilities, revenues and expenses attributable to the Non-Operated Marcellus Interest systems and Anadarko-Operated Marcellus Interest systems and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system and the DBJV system (see Note 2 ) in the accompanying consolidated financial statements. The 25% membership interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements for all periods presented. Adjustments to previously issued financial statements. The Partnership’s consolidated statements of income reflect adjustments for the following amounts, which previously reduced Operation and maintenance expense, to revenues related to Gathering, processing and transportation of natural gas and natural gas liquids: (i) $25.0 million for the year ended December 31, 2015 (all of which relates to the six months ended June 30, 2015) and (ii) $39.3 million and $20.5 million for the years ended December 31, 2014 and 2013 , respectively. Management determined that the third-party producer reimbursements received for electricity purchased by the Partnership are more appropriately classified as revenues, instead of a reduction to Operation and maintenance expense. This correction of an error has no impact to Net income (loss), cash flows, or any non-GAAP metric the Partnership uses to evaluate its operations and is not considered material to the Partnership’s results of operations for the years ended December 31, 2015 , 2014 and 2013 . The Partnership has revised its previously reported 2013, 2014 and 2015 consolidated financial statements, and unaudited interim periods therein as applicable, to reflect the reclassification. Presentation of Partnership assets. The term “Partnership assets” refers to the assets owned and interests accounted for under the equity method (see Note 9 ) by the Partnership as of December 31, 2015 . Because Anadarko controls the Partnership through its ownership and 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. See Note 2 . For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s 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 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 under the particular circumstances. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows: Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 – Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement). Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership is required to measure fair value and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the Partnership uses the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 12 . The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items. Cash equivalents. The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. Bad-debt reserve. The Partnership’s revenues are primarily from Anadarko, for which no credit limit is maintained. The Partnership analyzes its exposure to bad debts on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. As of December 31, 2015 and 2014 , the Partnership’s bad-debt reserve was immaterial. Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers’ pipelines. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2015 , imbalance receivables and payables were $2.1 million and $1.6 million , respectively. As of December 31, 2014 , imbalance receivables and payables were $0.4 million and $0.7 million , respectively. Net changes in imbalance payables and receivables are reported in cost of product. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Inventory. The cost of NGLs inventories is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets. See Note 10 . Property, plant and equipment. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the assets acquired from Anadarko are initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to partners’ capital. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred. Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts the Partnership receives from insurance carriers are net of any deductibles related to the covered event. The Partnership records a receivable from insurance to the extent it recognizes a loss from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any of the Partnership’s insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. The Partnership recognizes gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, the Partnership does not recognize a gain related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or the Partnership has a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, in the consolidated balance sheets and presented as capital expenditures in the Partnership’s consolidated statements of cash flows. With respect to business interruption insurance claims, the Partnership recognizes income only when non-refundable cash proceeds are received from insurers, which are presented in the Partnership’s consolidated statements of income as a component of Operating income (loss). In December 2015, there was an initial fire and secondary explosion at the DBM complex. See Note 7 . For the year ended December 31, 2015, the Partnership has recorded $20.3 million of losses in Gain on divestiture and other, net in the consolidated statements of income, related to this involuntary conversion event based on the difference between the net book value of the affected assets and the insurance claim receivable of $48.5 million . Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area. Management evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense. Refer to Note 7 for a description of impairments recorded during the years ended December 31, 2015 , 2014 and 2013. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset. Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. Refer to Note 8 for a discussion of goodwill. The Partnership evaluates goodwill for impairment annually, as of October 1, or more often as facts and circumstances warrant. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. An initial qualitative assessment is performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. If the Partnership concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, based on a hypothetical purchase price allocation, goodwill is written down to its implied fair value through a charge to operating expense. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement. Other intangible assets. The Partnership assesses intangible assets, as described in Note 8 , for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment within this Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Over time, the discounted liability is adjusted to its expected settlement value through accretion expense, which is reported within depreciation and amortization in the consolidated statements of income. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 11 . Environmental expenditures. The Partnership expenses environmental obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 13 . 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Segments. The Partnership’s operations are organized into a single operating segment, the assets of which gather, process, compress, treat and transport Anadarko and third-party natural gas, condensate, NGLs and crude oil in the United States. Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are performed. Producers’ wells are connected to the Partnership’s gathering systems for delivery of natural gas to the Partnership’s processing or treating plants, where the natural gas is processed to extract NGLs and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered and delivered to pipelines for market delivery. Under cost-of-service gathering agreements, the Partnership earns fees for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate is sold. The percentage of the product sale ultimately paid to the producer is recorded as a related cost of product expense. The Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue to either sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price uncertainty that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. See Note 5 . Revenue is recognized from the sale of condensate and NGLs upon transfer of title, and related purchases are recorded as cost of product. The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. Transportation revenues are also generated from interruptible contracts pursuant to which a fee is charged to the customer based on volumes transported through the pipeline. Revenues for transportation of natural gas and NGLs are recognized over the period of firm transportation contracts or, in the case of usage fees and interruptible contracts, when the volumes are received into the pipeline. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission (the “FERC”), and refund reserve liabilities are established where appropriate. Proceeds from the sale of residue, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate sales in the consolidated statements of income. Revenues attributable to the fixed-fee component of gathering and processing contracts as well as demand charges and commodity usage fees on transportation contracts are reported as revenues from gathering, processing and transportation of natural gas and natural gas liquids in the consolidated statements of income. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,128,015 units remained available for future issuance as of December 31, 2015. Upon vesting of each phantom unit awarded under the WES LTIP, the holder will receive common units of the Partnership or, at the discretion of the general partner’s Board of Directors, cash in an amount equal to the market value of common units of the Partnership on the vesting date. Equity-based compensation expense attributable to grants made under the WES LTIP impacts the Partnership’s cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. The Partnership amortizes stock-based compensation expense attributable to awards granted under the WES LTIP over the vesting periods applicable to the awards. Additionally, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) for the years ended December 31, 2015 and 2014 and (ii) the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”) for all periods presented. Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized. Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership’s acquisition of these assets from Anadarko. For periods beginning on and subsequent to the Partnership’s acquisition of the Partnership assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership. The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2015 or 2014. With respect to assets acquired from Anadarko, the Partnership recorded Anadarko’s historic deferred income taxes for the periods prior to the Partnership’s ownership of the assets. For periods subsequent to the Partnership’s acquisition, the Partnership is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the assets acquired from Anadarko. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Net income (loss) per common unit. The Partnership applies the two-class method in determining net income (loss) per unit applicable to master limited partnerships having multiple classes of securities including common units, Class C units, general partner units and IDRs. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Under the two-class method, net income (loss) per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes to its unitholders an amount of cash equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period o

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Acquisitions and Divestitures	2. ACQUISITIONS AND DIVESTITURES In May 2008, concurrently with the closing of the Partnership’s initial public offering (“IPO”), Anadarko contributed to the Partnership the assets and liabilities of Anadarko Gathering Company LLC, Pinnacle Gas Treating LLC, and MIGC LLC. In December 2008, the Partnership completed the acquisition of the Powder River assets from Anadarko, which included (i) the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% membership interest in Fort Union. In July 2009, the Partnership closed on the acquisition of a 51% membership interest in Chipeta from Anadarko. The Partnership closed the acquisitions of Anadarko’s Granger and Wattenberg assets in January 2010 and August 2010, respectively. In September 2010, the Partnership acquired a 10% interest in White Cliffs. The Partnership closed the acquisition of the Platte Valley assets from a third party in February 2011 and the acquisition of the Bison assets from Anadarko in July 2011. In January 2012, the Partnership acquired the MGR assets from Anadarko and in August 2012 Anadarko’s additional Chipeta interest of 24% , bringing the Partnership’s total membership interest in Chipeta to 75% . The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2015 , 2014 and 2013 , and identifies the funding sources for such acquisitions: thousands except unit and percent amounts Acquisition Date Percentage Deferred Purchase Price Obligation - Anadarko Borrowings Cash On Hand Common Units Issued to Anadarko Class C Units Issued to Anadarko Non-Operated Marcellus Interest (1) 03/01/2013 33.75 % $ — $ 250,000 $ 215,500 449,129 — Anadarko-Operated Marcellus Interest (2) 03/08/2013 33.75 % — 133,500 — — — Mont Belvieu JV (3) 06/05/2013 25 % — — 78,129 — — OTTCO (4) 09/03/2013 100 % — 27,500 — — — TEFR Interests (5) 03/03/2014 Various (5) — 350,000 6,250 308,490 — DBM (6) 11/25/2014 100 % — 475,000 298,327 — 10,913,853 DBJV system (7) 03/02/2015 50 % 174,276 — — — — (1) The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million . (2) The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a $1.1 million decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation. (3) The Partnership acquired a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting. (4) The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming. (5) The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million . (6) The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price. (7) The Partnership acquired Anadarko’s interest in Delaware Basin JV Gathering LLC (“DBJV”), which owns a 50% interest in a gathering system and related facilities (the “DBJV system”). The DBJV system is located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. The Partnership currently estimates the future payment will be $282.8 million , the net present value of which was $174.3 million as of the acquisition date. See DBJV acquisition—Deferred purchase price obligation - Anadarko below. 2. ACQUISITIONS AND DIVESTITURES (CONTINUED) DBJV acquisition . Because the acquisition of DBJV was a transfer of net assets between entities under common control, the Partnership’s historical financial statements previously filed with the SEC have been recast in this Form 10-K to include the results attributable to the DBJV system as if the Partnership owned DBJV for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of DBJV have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned DBJV during the periods reported. The following table presents the impact of the DBJV system on revenues and other, equity income, net and net income (loss) as presented in the Partnership’s historical consolidated statements of income: Year Ended December 31, 2014 thousands Partnership Historical (1) DBJV System Combined Revenues and other $ 1,320,756 $ 62,112 $ 1,382,868 Equity income, net 57,836 — 57,836 Net income (loss) 390,558 17,309 407,867 Year Ended December 31, 2013 thousands Partnership Historical (1) DBJV System Combined Revenues and other $ 1,052,937 $ 32,545 $ 1,085,482 Equity income, net 22,948 — 22,948 Net income (loss) 285,443 4,096 289,539 (1) See Adjustments to previously issued financial statements in Note 1 . Deferred purchase price obligation - Anadarko. The consideration to be paid by the Partnership for the acquisition of DBJV consists of a cash payment to Anadarko due on March 31, 2020. The cash payment will be equal to (a) eight multiplied by the average of the Partnership’s share in the Net Earnings (see definition below) of the DBJV system for the calendar years 2018 and 2019, less (b) the Partnership’s share of all capital expenditures incurred for the DBJV system between March 1, 2015, and February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to the DBJV system on an accrual basis. As of the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Net Earnings and capital expenditures for the DBJV system) was $282.8 million , which had a net present value of $174.3 million , using a discount rate of 10% . As of December 31, 2015 , the net present value of this obligation was $188.7 million and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion expense for the year ended December 31, 2015 was $14.4 million and zero for each of the years ended December 31, 2014 and 2013 , and has been recorded as a charge to interest expense. Any subsequent changes to the estimated future payment obligation, if applicable, will be calculated using a discounted cash flow model with a 10% discount rate. Such changes will be recorded as adjustments within Common units on the consolidated balance sheets and consolidated statements of equity and partners’ capital, with accretion adjustments (financing-related) as a result of these changes recorded within interest expense on the consolidated statements of income in the period of the change. DBM acquisition . The DBM acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the DBM acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the DBM acquisition were included in the Partnership’s consolidated statement of income beginning on the acquisition date in the fourth quarter of 2014. 2. ACQUISITIONS AND DIVESTITURES (CONTINUED) The following is the final allocation of the purchase price as of December 31, 2015 , including $3.5 million of post-closing purchase price adjustments, to the assets acquired and liabilities assumed in the DBM acquisition as of the acquisition date: thousands Current assets $ 60,888 Property, plant and equipment 467,171 Goodwill 284,749 Other intangible assets 811,048 Accounts payables (18,621 ) Accrued liabilities (37,360 ) Deferred income taxes (1,342 ) Asset retirement obligations and other (9,060 ) Total purchase price $ 1,557,473 The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the DBM acquisition using inputs that are not observable in the market and thus represent Level 3 inputs. The fair values of the processing plants, gathering system, and related facilities and equipment are based on market and cost approaches. The fair value of the intangible assets was determined using an income approach. Deferred taxes represent the tax effects of differences in the tax basis and acquisition-date fair value of the assets acquired and liabilities assumed. The following table presents pro forma condensed financial information of the Partnership as if the DBM acquisition had occurred on January 1, 2013: Year Ended December 31, thousands except per-unit amounts 2014 2013 Revenues and other $ 1,506,135 $ 1,162,749 Net income (loss) 349,729 243,478 Net income (loss) attributable to Western Gas Partners, LP 335,704 232,622 Net income (loss) per common unit – basic and diluted 1.34 1.12 The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the DBM acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s unaudited pro forma information in the table above includes $12.5 million of revenues and other and $10.4 million of operating expenses, excluding depreciation and amortization and impairments, attributable to the DBM complex that are included in the Partnership’s consolidated statement of income for the year ended December 31, 2014. The pro forma adjustments reflect pre-acquisition results of the DBM acquisition including (a) revenues and expenses; (b) depreciation and amortization based on the purchase price allocated to property, plant and equipment and estimated useful lives; (c) amortization of intangible assets (customer contracts assumed in the acquisition); and (d) interest on borrowings under the Partnership’s senior unsecured revolving credit facility (“RCF”) to finance the DBM acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The unaudited pro forma information does not reflect any cost savings or other synergies anticipated as a result of the DBM acquisition, nor any future acquisition related expenses. Gain on divestiture - Dew and Pinnacle systems. During the third quarter of 2015, the Dew and Pinnacle systems in East Texas were sold to a third party for net proceeds of $145.6 million , after closing adjustments, resulting in a net gain on sale of $77.3 million recorded as Gain on divestiture and other, net in the Partnership’s consolidated statements of income. The Partnership also allocated $5.1 million in goodwill to this divestiture.

Partnership Distributions

Partnership Distributions	12 Months Ended
	Dec. 31, 2015
Distributions Made to Members or Limited Partners [Abstract]
Partnership Distributions	3. PARTNERSHIP DISTRIBUTIONS The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors of the general partner 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 2013 March 31 $ 0.540 $ 70,143 May 2013 June 30 0.560 79,315 August 2013 September 30 0.580 83,986 November 2013 December 31 0.600 92,609 February 2014 2014 March 31 $ 0.625 $ 98,749 May 2014 June 30 0.650 105,655 August 2014 September 30 0.675 111,608 November 2014 December 31 0.700 126,044 February 2015 2015 March 31 $ 0.725 $ 133,203 May 2015 June 30 0.750 139,736 August 2015 September 30 0.775 146,160 November 2015 December 31 (1) 0.800 152,588 February 2016 (1) On January 21, 2016 , the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.800 per unit, or $152.6 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution was paid on February 11, 2016 , to unitholders of record at the close of business on February 1, 2016 . 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. It is intended that working capital borrowings, at the time of such borrowings, be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners. 3. PARTNERSHIP DISTRIBUTIONS (CONTINUED) 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 December 31, 2017 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted to 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. The Partnership issued the following PIK Class C units to APC Midstream Holdings, LLC (“AMH”), the holder of the Class C units, for the periods presented: thousands except unit amounts For the Quarters Ended PIK Class C Units Implied Fair Value Date of 2014 December 31 (1) 45,711 $ 3,072 February 2015 2015 March 31 118,230 $ 8,101 May 2015 June 30 153,020 8,721 August 2015 September 30 181,048 9,724 November 2015 December 31 323,584 10,070 February 2016 (1) Prorated for the 37 -day period the Class C units were outstanding during the fourth quarter of 2014. General partner interest and incentive distribution rights. As of December 31, 2015 , the general partner was entitled to 1.8% of all quarterly distributions that the Partnership makes prior to its liquidation and, as the holder of the 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 49.8% does not include any distributions that the general partner may receive on common units that it may acquire.

Equity and Partners' Capital

Equity and Partners' Capital	12 Months Ended
	Dec. 31, 2015
Partners' Capital Notes [Abstract]
Equity and Partners' Capital	4. EQUITY AND PARTNERS’ CAPITAL Equity offerings. The Partnership completed the following public offerings of its common units during 2015 , 2014 and 2013, including through its Continuous Offering Programs (“COP”): thousands except unit and per-unit amounts Common Units Issued GP Units Issued (1) Price Per Unit Underwriting Discount and Other Offering Expenses Net Proceeds 2013 May 2013 equity offering (2) 7,015,000 143,163 $ 61.18 $ 13,203 $ 424,733 December 2013 equity offering (3) 4,800,000 97,959 61.51 9,447 291,827 $125.0 million COP (4) 685,735 13,996 60.84 965 41,603 2014 $125.0 million COP (5) 1,133,384 23,132 $ 73.48 $ 1,738 $ 83,245 November 2014 equity offering (6) 8,620,153 153,061 70.85 18,615 602,967 2015 $500.0 million COP (7) 873,525 — $ 66.61 $ 805 $ 57,385 (1) Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution. (2) Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option. (3) Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million . (4) Represents common and general partner units issued during the year ended December 31, 2013, pursuant to the Partnership’s registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “$125.0 million COP”). Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2013, were $42.6 million . The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2013. (5) Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million . The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement. (6) Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million . Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. (7) Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million , respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million , respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015. Class C units. In connection with the closing of the DBM acquisition in November 2014, the Partnership issued 10,913,853 Class C units to AMH at a price of $68.72 per unit, generating proceeds of $750.0 million , pursuant to the Unit Purchase Agreement (“UPA”) with Anadarko and AMH. All outstanding Class C units will convert into common units on a one-for-one basis on December 31, 2017, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. The Class C units were issued to partially fund the acquisition of DBM, and the UPA contains an optional redemption feature that provides the Partnership the ability to redeem up to $150.0 million of the Class C units within 10 days of the receipt of cash proceeds from an entity that is not an affiliate of the Partnership or AMH, if these cash proceeds were in relation to (i) the assets of DBM, (ii) the equity interests in DBM or (iii) the equity interests in a subsidiary of the Partnership that owns a majority of the outstanding equity interests in DBM. As of December 31, 2015 , no such proceeds had been received, and no Class C units had been redeemed. 4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED) 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 will be 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 a conversion date of December 31, 2017, using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit. Common, Class C and general partner units . The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.” The following table summarizes the common, Class C and general partner units issued during the years ended December 31, 2015 and 2014: Common Units Class C Units General Partner Units Total Balance at December 31, 2013 117,322,812 — 2,394,345 119,717,157 December 2013 equity offering 300,000 — 6,122 306,122 WES LTIP award vestings 10,291 — 112 10,403 TEFR Interests acquisition 308,490 — 6,296 314,786 $125.0 million COP 1,133,384 — 23,132 1,156,516 November 2014 equity offering 8,620,153 — 153,061 8,773,214 Class C unit issuance — 10,913,853 — 10,913,853 Balance at December 31, 2014 127,695,130 10,913,853 2,583,068 141,192,051 PIK Class C units — 498,009 — 498,009 WES LTIP award vestings 8,310 — — 8,310 $500.0 million COP 873,525 — — 873,525 Balance at December 31, 2015 128,576,965 11,411,862 2,583,068 142,571,895 Holdings of Partnership equity. As of December 31, 2015 , WGP held 49,296,205 common units, representing a 34.6% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,583,068 general partner units, representing a 1.8% general partner interest in the Partnership, and 100% of the IDRs. As of December 31, 2015 , other subsidiaries of Anadarko held 757,619 common units and 11,411,862 Class C units, representing an aggregate 8.5% limited partner interest in the Partnership. As of December 31, 2015 , the public held 78,523,141 common units, representing a 55.1% limited partner interest in the Partnership. 4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED) Net income (loss) per unit for common units. Basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in 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. Because the Class C units participate in distributions with common units according to a predetermined formula (see Note 3 ), they are considered a participating security and are included in the computation of earnings per unit pursuant to the two-class method. The Class C unit participation right results in a non-contingent transfer of value each time the Partnership declares a distribution. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the limited partners’ interest in net income (loss) attributable to common units, and (ii) the limited partners’ interest in net income (loss) allocable 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 outstanding Class C units. The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units: Year Ended December 31, thousands except per-unit amounts 2015 2014 2013 Net income (loss) attributable to Western Gas Partners, LP $ (73,538 ) $ 393,842 $ 278,723 Pre-acquisition net (income) loss allocated to Anadarko (1,742 ) (16,353 ) (8,224 ) General partner interest in net (income) loss (180,996 ) (120,980 ) (69,633 ) Limited partners’ interest in net income (loss) (256,276 ) 256,509 200,866 Net income (loss) allocable to common units (1) (250,210 ) 254,737 200,866 Net income (loss) allocable to Class C units (1) (6,066 ) 1,772 — Limited partners’ interest in net income (loss) $ (256,276 ) $ 256,509 $ 200,866 Net income (loss) per unit Common units - basic $ (1.95 ) $ 2.13 $ 1.83 Common units – diluted (2) (1.95 ) 2.12 1.83 Weighted-average units outstanding Common units – basic 128,345 119,822 109,872 Class C units (2) 11,114 1,106 — Common units – diluted 139,459 120,928 109,872 (1) Adjusted to reflect amortization for the beneficial conversion feature. See Class C units above for a discussion of the Class C units. (2) Inclusion of Class C units in the calculation for the year ended December 31, 2015, would have had an anti-dilutive effect.

Transactions with Affiliates

Transactions with Affiliates	12 Months Ended
	Dec. 31, 2015
Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract]
Transactions with Affiliates	5. TRANSACTIONS WITH AFFILIATES Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue, drip condensate 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. See Note 2 for further information related to contributions of assets to the Partnership by Anadarko. Cash management. Anadarko operates a cash management system whereby excess cash from most of its subsidiaries’ separate bank accounts is generally swept to centralized accounts. Prior to the Partnership’s 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 and Deferred purchase price obligation - Anadarko. Concurrently with the closing of the Partnership’s May 2008 IPO, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50% , payable quarterly. The fair value of the note receivable from Anadarko was $252.3 million and $317.8 million at December 31, 2015 and 2014, 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. The consideration to be paid by the Partnership to Anadarko for the March 2015 acquisition of DBJV consists of a cash payment due on March 31, 2020. See Note 2 and Note 12 . Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the commodity price swap agreements are not specifically defined. Instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold. On December 31, 2014, the Partnership’s commodity price swap agreements for the Hilight and Newcastle systems and the Granger complex (excluding the Granger straddle plant) expired without renewal. The outstanding commodity price swap agreements for the Hugoton system, MGR assets and DJ Basin complex expire in December 2016. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. Below is a summary of the fixed price ranges on all of the Partnership’s outstanding commodity price swap agreements as of December 31, 2015 : per barrel except natural gas 2016 Ethane $ 18.41 − 23.11 Propane 47.08 − 52.90 Isobutane 62.09 − 73.89 Normal butane 54.62 − 64.93 Natural gasoline 72.88 − 81.68 Condensate 76.47 − 81.68 Natural gas (per MMBtu) 4.87 − 5.96 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) The following table summarizes gains and losses upon settlement of commodity price swap agreements recognized in the consolidated statements of income: Year Ended December 31, thousands 2015 2014 2013 Gains (losses) on commodity price swap agreements related to sales: (1) Natural gas sales $ 45,978 $ 9,494 $ 21,382 Natural gas liquids sales 145,258 113,866 102,076 Total 191,236 123,360 123,458 Losses on commodity price swap agreements related to purchases (2) (124,944 ) (68,492 ) (85,294 ) Net gains (losses) on commodity price swap agreements $ 66,292 $ 54,868 $ 38,164 (1) Reported in affiliate natural gas, natural gas liquids and drip condensate sales in the consolidated statements of income in the period in which the related sale is recorded. (2) Reported in cost of product in the consolidated statements of income in the period in which the related purchase is recorded. DJ Basin complex and Hugoton system swap extensions. On June 25, 2015, the Partnership extended its commodity price swap agreements with Anadarko for the DJ Basin complex from July 1, 2015, through December 31, 2015, and for the Hugoton system from October 1, 2015, through December 31, 2015. The table below summarizes the swap prices for the extension period compared to the forward market prices as of the agreement date, June 25, 2015. DJ Basin Complex Hugoton System per barrel except natural gas 2015 Swap Prices Market Prices (1) 2015 Swap Prices Market Prices (1) Ethane $ 18.41 $ 1.96 — — Propane 47.08 13.10 — — Isobutane 62.09 19.75 — — Normal butane 54.62 18.99 — — Natural gasoline 72.88 52.59 — — Condensate 76.47 52.59 $ 78.61 $ 32.56 Natural gas (per MMBtu) 5.96 2.75 5.50 2.74 (1) Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of June 25, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. On December 8, 2015, the commodity price swap agreements with Anadarko for the DJ Basin complex and Hugoton system were further extended from January 1, 2016, through December 31, 2016. The table below summarizes the swap prices for the extension period compared to the forward market prices as of the agreement date, December 8, 2015. DJ Basin Complex Hugoton System per barrel except natural gas 2016 Swap Prices Market Prices (1) 2016 Swap Prices Market Prices (1) Ethane $ 18.41 $ 0.60 — — Propane 47.08 10.98 — — Isobutane 62.09 17.23 — — Normal butane 54.62 16.86 — — Natural gasoline 72.88 26.15 — — Condensate 76.47 34.65 $ 78.61 $ 18.81 Natural gas (per MMBtu) 5.96 2.11 5.50 2.12 (1) Represents the NYMEX forward strip price as of December 8, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) Revenues or costs attributable to volumes settled during the respective extension period, at the applicable market price in the above tables, will be recognized in the consolidated statements of income. The Partnership will also record a capital contribution from Anadarko in the Partnership’s consolidated statement of equity and partners’ capital for the amount by which the swap price exceeds the applicable market price in the above tables. For the year ended December 31, 2015 , the capital contribution from Anadarko was $18.4 million . Gas gathering and processing agreements. The Partnership has significant gas gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The Partnership’s gathering, treating and transportation throughput (excluding equity investment throughput and throughput measured in barrels) attributable to natural gas production owned or controlled by Anadarko was 43% , 49% and 54% for the years ended December 31, 2015 , 2014 and 2013 , respectively. The Partnership’s processing throughput (excluding equity investment throughput and throughput measured in barrels) attributable to natural gas production owned or controlled by Anadarko was 51% , 57% and 59% for the years ended December 31, 2015 , 2014 and 2013 , respectively. 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. Omnibus agreement. Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing; and midstream administration. Anadarko, in accordance with the partnership and omnibus agreements, determines, in its reasonable discretion, amounts to be reimbursed by the Partnership in exchange for services provided under the omnibus agreement. See Summary of affiliate transactions below. The following table summarizes the amounts the Partnership reimbursed to Anadarko: Year Ended December 31, thousands 2015 2014 2013 General and administrative expenses $ 22,896 $ 20,249 $ 16,882 Public company expenses 8,950 8,006 7,152 Total reimbursement $ 31,846 $ 28,255 $ 24,034 Services and secondment agreement. Pursuant to the services and secondment agreement, specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement extends through May 2018 and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination before the applicable twelve-month period expires. The consolidated financial statements include costs allocated by Anadarko for expenses incurred under the services and secondment agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership assets. Tax sharing agreement. Pursuant to a tax sharing agreement, the Partnership reimburses Anadarko for its estimated share of applicable state taxes. These taxes include income taxes attributable to the Partnership’s income which are directly borne by Anadarko through its filing of a combined or consolidated tax return with respect to periods beginning on and subsequent to the acquisition of the Partnership assets from Anadarko. Anadarko may use its own tax attributes to reduce or eliminate the tax liability of its combined or consolidated group, which may include the Partnership as a member. However, under this circumstance, the Partnership nevertheless is required to reimburse Anadarko for its allocable share of taxes that would have been owed had tax attributes not been available to Anadarko. 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) Allocation of costs. For periods prior to the Partnership’s acquisition of the Partnership assets, the consolidated financial statements include costs allocated by Anadarko in the form of a management services fee, which approximated the general and administrative costs incurred by Anadarko attributable to the Partnership assets. This management services fee was allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues or other contractual arrangements. Management believes these allocation methodologies are reasonable. The employees supporting the Partnership’s operations are employees of Anadarko. Anadarko allocates costs to the Partnership for its share of personnel costs, including costs associated with equity-based compensation plans, non-contributory defined pension and postretirement plans, defined contribution savings plan pursuant to the omnibus agreement and services and secondment agreement. In general, the Partnership’s reimbursement to Anadarko under the omnibus agreement or services and secondment agreements is either (i) on an actual basis for direct expenses Anadarko and the general partner incur on behalf of the Partnership, or (ii) based on an allocation of salaries and related employee benefits between the Partnership, the general partner and Anadarko based on estimates of time spent on each entity’s business and affairs. Most general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, and do not include any mark-up or subsidy component. With respect to allocated costs, management believes the allocation method employed by Anadarko is reasonable. Although it is not practicable to determine what the amount of these direct and allocated costs would be if the Partnership were to directly obtain these services, management believes that aggregate costs charged to the Partnership by Anadarko are reasonable. WES LTIP. The general partner awards phantom units under the WES LTIP primarily 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 $0.5 million for the year ended December 31, 2015 , and $0.6 million for each of the years ended December 31, 2014 and 2013 . As of December 31, 2015 , there was $0.1 million of unrecognized compensation expense attributable to the outstanding awards under the WES LTIP, all of which will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 0.4 years . The following table summarizes WES LTIP award activity for the years ended December 31, 2015 , 2014 and 2013 : 2015 2014 2013 Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Phantom units outstanding at beginning of year $ 60.74 9,522 $ 49.47 16,844 $ 41.77 25,619 Vested 60.69 (9,257 ) 49.55 (13,122 ) 41.28 (14,695 ) Granted 69.10 5,212 68.14 5,800 62.49 5,920 Phantom units outstanding at end of year 68.78 5,477 60.74 9,522 49.47 16,844 WGP LTIP and Anadarko Incentive Plans. For the years ended December 31, 2015 , 2014 and 2013 , general and administrative expenses included $3.9 million , $3.5 million and $3.0 million , 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 WGP LTIP and the Anadarko Incentive Plans. Of these amounts, $3.6 million , $3.2 million and $2.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, are reflected as contributions to partners’ capital in the Partnership’s consolidated statements of equity and partners’ capital. As of December 31, 2015 , the Partnership estimated that $7.3 million of estimated unrecognized compensation expense attributable to the WGP LTIP and the Anadarko Incentive Plans will be allocated to the Partnership over a weighted-average period of 2.0 years . 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) Equipment purchases and sales. The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment: Year Ended December 31, 2015 2014 2013 2015 2014 2013 thousands Purchases Sales Cash consideration $ 12,664 $ 22,943 $ 11,211 $ 925 $ — $ 85 Net carrying value 7,944 12,210 5,309 972 — 38 Partners’ capital adjustment $ 4,720 $ 10,733 $ 5,902 $ (47 ) $ — $ 47 Contributions in aid of construction costs from affiliates. In 2013, a subsidiary of Anadarko entered into an aid in construction agreement with the Partnership, whereby the Partnership constructed five receipt-point facilities at the Brasada complex that serve the Anadarko subsidiary. Such subsidiary reimbursed the Partnership for costs associated with construction of the receipt points. These reimbursements are presented within the investing section of the Partnership’s consolidated statements of cash flows as “Contributions in aid of construction costs from affiliates.” Summary of affiliate transactions. The following table summarizes affiliate transactions, which include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas: Year ended December 31, thousands 2015 2014 2013 Revenues and other (1) $ 1,029,922 $ 1,053,935 $ 844,203 Equity income, net (1) 71,251 57,836 22,948 Cost of product (1) 167,420 127,906 136,570 Operation and maintenance (2) 67,119 62,306 59,698 General and administrative (3) 30,692 28,970 24,956 Operating expenses 265,231 219,182 221,224 Interest income (4) 16,900 16,900 16,900 Interest expense (5) 14,398 — — Distributions to unitholders (6) 314,200 234,024 169,150 Above-market component of swap extensions with Anadarko 18,449 — — (1) Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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 the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets. (3) Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5 ). (4) Represents interest income recognized on the note receivable from Anadarko. (5) For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 12 ). (6) Represents distributions paid under the partnership agreement (see Note 3 and Note 4 ). Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented in the consolidated statements of income.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	6. INCOME TAXES The components of the Partnership’s income tax expense (benefit) are as follows: Year Ended December 31, thousands 2015 2014 2013 Current income tax expense (benefit) Federal income tax expense (benefit) $ 590 $ (1,729 ) $ (35,872 ) State income tax expense (benefit) 858 63 497 Total current income tax expense (benefit) 1,448 (1,666 ) (35,375 ) Deferred income tax expense (benefit) Federal income tax expense (benefit) 348 10,612 40,846 State income tax expense (benefit) 1,584 2,713 (811 ) Total deferred income tax expense (benefit) 1,932 13,325 40,035 Total income tax expense (benefit) $ 3,380 $ 11,659 $ 4,660 Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows: Year Ended December 31, thousands except percentages 2015 2014 2013 Income (loss) before income taxes $ (60,057 ) $ 419,526 $ 294,199 Statutory tax rate — % — % — % Tax computed at statutory rate $ — $ — $ — Adjustments resulting from: Federal taxes on income attributable to Partnership assets pre-acquisition 942 8,988 5,390 State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) 27 190 629 Texas margin tax expense (benefit) (1) 2,411 2,481 (1,359 ) Income tax expense (benefit) $ 3,380 $ 11,659 $ 4,660 Effective tax rate (6 )% 3 % 2 % (1) Includes a reduction of $2.2 million in deferred state income taxes. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25% . The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted. The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows: December 31, thousands 2015 2014 Depreciable property $ (4,418 ) $ (44,725 ) Credit carryforwards 512 526 Other intangible assets (2,070 ) (1,450 ) Other 13 7 Net long-term deferred income tax liabilities $ (5,963 ) $ (45,642 ) Credit carryforwards, which are available for use on future income tax returns, consist of $0.5 million of state income tax credits that expire in 2026.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	7. PROPERTY, PLANT AND EQUIPMENT A summary of the historical cost of the Partnership’s property, plant and equipment is as follows: December 31, thousands Estimated Useful Life 2015 2014 Land n/a $ 3,191 $ 2,884 Gathering systems 3 to 47 years 5,420,762 4,972,892 Pipelines and equipment 15 to 45 years 136,290 151,107 Assets under construction n/a 324,720 483,347 Other 3 to 40 years 19,674 16,420 Total property, plant and equipment 5,904,637 5,626,650 Accumulated depreciation 1,614,663 1,055,207 Net property, plant and equipment $ 4,289,974 $ 4,571,443 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. On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the 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. Train II sustained the most damage of the processing trains but is expected to be returned to service by the end of 2016. Train III experienced minimal damage and is expected to be able to accept limited deliveries of gas in April 2016, and return to full service by the end of the second quarter of 2016, along with new liquid handling and amine treating facilities. The Partnership recognized a gross loss resulting from this damage of $68.8 million . See Note 1 . Also during 2015, the Partnership recognized impairments of $514.1 million , primarily due to impairments of $280.2 million at the Red Desert complex and $220.9 million at the Hilight system. Using the income approach and Level 3 fair value inputs, the Red Desert complex was impaired to its estimated salvage value of $6.3 million and the Hilight system was impaired to its estimated fair value of $28.8 million . These impairments were triggered by a reduction in estimated future cash flows caused by the low commodity price environment and resulting reduced producer drilling activity and related throughput. Also during this period, the Partnership recognized impairments of $13.0 million , primarily due to (i) the abandonment of compressors at the MIGC system and (ii) the cancellation of projects at the Non-Operated Marcellus Interest systems, the DBJV system and the Brasada, Red Desert and DJ Basin complexes. Prolonged low or further declines in commodity prices and changes to producers’ drilling plans in response to lower prices could result in additional impairments in future periods. At December 31, 2013, other long-term assets includes $4.6 million of unguaranteed residual value related to the capital lease component of a processing agreement assumed in connection with the acquisition of the Granger straddle plant as a part of the MGR acquisition in January 2012. This agreement, in which the Partnership was the lessor, was replaced effective April 1, 2014, with a gas conditioning agreement that does not satisfy criteria required for lease classification. As such, during the second quarter of 2014, the $4.6 million capital lease asset was reclassified from other long-term assets to property, plant and equipment and commenced depreciation. During 2014, the Partnership recognized impairments of $3.1 million , primarily related to a non-operational plant in the Powder River Basin that was impaired to its estimated salvage value of $2.4 million , using the income approach and Level 3 fair value inputs, the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems and a compressor no longer in service at the Hilight system. During 2013, the Partnership recognized a $1.3 million impairment primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems.

Goodwill and Intangibles

Goodwill and Intangibles	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangibles	8. GOODWILL AND INTANGIBLES Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the Partnership assets acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price paid to a third-party entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s allocated goodwill balance does not represent, and in some cases is significantly different from, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of such net assets on their respective acquisition dates. The Partnership evaluates goodwill for impairment annually (see Note 1 ). Estimating the fair value of the Partnership’s reporting units was not necessary based on the qualitative evaluation as of October 1, 2015 , and no goodwill impairment has been recognized in these consolidated financial statements. Procedures were also performed in the fourth quarter of 2015 to review any changes in circumstances subsequent to the annual test, including changes in commodity prices. These procedures also indicated no impairment. Other intangible assets. The intangible asset balance in the consolidated balance sheets includes the fair value, net of amortization, of (i) contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which are being amortized on a straight-line basis over 50 years , (ii) interconnect agreements at Chipeta entered into in November 2012, which are being amortized on a straight-line basis over 10 years , and (iii) contracts assumed by the Partnership in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years . The Partnership assesses intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment in Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. No intangible asset impairment has been recognized in these consolidated financial statements. The following table presents the gross carrying amount and accumulated amortization of other intangible assets: December 31, thousands 2015 2014 Gross carrying amount $ 868,035 $ 892,555 Accumulated amortization (35,908 ) (7,698 ) Other intangible assets $ 832,127 $ 884,857 Amortization expense for intangible assets was $28.2 million , $4.3 million and $1.4 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The Partnership estimates that it will record $28.4 million of intangible asset amortization for each of the next five years.

Equity Investments

Equity Investments	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Equity Investments	9. EQUITY INVESTMENTS The following table presents the activity in the Partnership’s equity investments for the years ended December 31, 2015 and 2014 : Equity Investments thousands Fort (1) White (2) Rendezvous (3) Mont (4) TEG (5) TEP (6) FRP (7) Total Balance at December 31, 2013 $ 25,172 $ 35,039 $ 60,928 $ 122,480 $ 16,649 $ 197,731 $ 135,401 $ 593,400 Investment earnings (loss), net of amortization 6,344 11,912 1,729 29,029 650 6,108 2,064 57,836 Contributions — 10,456 — 3,957 352 6,623 42,033 63,421 Capitalized interest — — — — — — 857 857 Distributions (5,583 ) (11,330 ) (3,669 ) (34,129 ) (523 ) (5,622 ) (2,111 ) (62,967 ) Distributions in excess of cumulative earnings (8) — (1,762 ) (2,652 ) — (338 ) (6,047 ) (7,256 ) (18,055 ) Balance at December 31, 2014 $ 25,933 $ 44,315 $ 56,336 $ 121,337 $ 16,790 $ 198,793 $ 170,988 $ 634,492 Investment earnings (loss), net of amortization (3,200 ) 14,770 2,292 23,570 586 16,088 17,145 71,251 Contributions — 8,512 — (432 ) — 1,880 1,482 11,442 Distributions (5,611 ) (14,188 ) (4,233 ) (24,248 ) (803 ) (16,340 ) (16,631 ) (82,054 ) Distributions in excess of cumulative earnings (8) — (2,970 ) (3,482 ) (3,138 ) (290 ) (5,618 ) (746 ) (16,244 ) Balance at December 31, 2015 $ 17,122 $ 50,439 $ 50,913 $ 117,089 $ 16,283 $ 194,803 $ 172,238 $ 618,887 (1) The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners. (2) The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members. (3) The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members. (4) The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners. (5) The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members. (6) The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (7) The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (8) Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis. 9. EQUITY INVESTMENTS (CONTINUED) During the year ended December 31, 2015, an impairment loss was recognized by the managing partner of Fort Union. The Partnership’s 14.81% share of the impairment loss was $9.5 million recorded in Equity income, net in the consolidated statements of income. The investment balance at December 31, 2015 , includes $40.1 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of Western Gas Resources, Inc. (“WGRI”), the entity that previously owned the interest in Rendezvous, which Anadarko acquired in August 2006. This excess balance is attributable to the difference between the fair value and book value of such gathering and treating facilities (at the time WGRI was acquired by Anadarko) and is being amortized over the remaining estimated useful life of those facilities. The investment balance in White Cliffs at December 31, 2015 , is $8.1 million less than the Partnership’s underlying equity in White Cliffs’ net assets, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference is being amortized to equity income, net over the remaining estimated useful life of the White Cliffs pipeline. Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss. The following tables present the summarized combined financial information for the Partnership’s equity investments (amounts represent 100% of investee financial information): Year Ended December 31, thousands 2015 2014 2013 Consolidated Statements of Income Revenues $ 668,797 $ 548,629 $ 261,705 Operating income 381,616 336,188 171,496 Net income 381,161 333,705 170,175 December 31, thousands 2015 2014 Consolidated Balance Sheets Current assets $ 156,180 $ 141,781 Property, plant and equipment, net 2,736,553 2,814,336 Other assets 43,713 48,799 Total assets $ 2,936,446 $ 3,004,916 Current liabilities 78,116 95,102 Non-current liabilities 9,072 22,615 Equity 2,849,258 2,887,199 Total liabilities and equity $ 2,936,446 $ 3,004,916

Components of Working Capital

Components of Working Capital	12 Months Ended
	Dec. 31, 2015
Components Of Working Capital [Abstract]
Components of Working Capital	10. COMPONENTS OF WORKING CAPITAL A summary of accounts receivable, net is as follows: December 31, thousands 2015 2014 Trade receivables, net $ 131,221 $ 105,646 Other receivables, net 49,772 3,597 Total accounts receivable, net $ 180,993 $ 109,243 A summary of other current assets is as follows: December 31, thousands 2015 2014 Natural gas liquids inventory $ 2,403 $ 5,316 Imbalance receivables 2,122 415 Prepaid insurance 2,296 2,443 Other 1,034 1,879 Total other current assets $ 7,855 $ 10,053 A summary of accrued liabilities is as follows: December 31, thousands 2015 2014 Accrued capital expenditures $ 60,702 $ 128,856 Accrued plant purchases 16,425 14,023 Accrued interest expense 26,194 24,741 Short-term asset retirement obligations 3,555 1,224 Short-term remediation and reclamation obligations 1,136 475 Income taxes payable 770 207 Other 8,036 1,263 Total accrued liabilities $ 116,818 $ 170,789

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	11. ASSET RETIREMENT OBLIGATIONS The following table provides a summary of changes in asset retirement obligations: Year Ended December 31, thousands 2015 2014 Carrying amount of asset retirement obligations at beginning of year $ 110,735 $ 78,535 Liabilities incurred 9,121 13,982 Liabilities settled (7,377 ) (4,195 ) Accretion expense 5,943 4,879 Revisions in estimated liabilities 2,105 17,534 Carrying amount of asset retirement obligations at end of year $ 120,527 $ 110,735 The liabilities incurred for the year ended December 31, 2015 , represented additions in asset retirement obligations primarily due to capital expansions at the DJ Basin, Granger and Brasada complexes and the Hilight and Non-Operated Marcellus Interest systems. Revisions in estimated liabilities for the year ended December 31, 2015 , are related to (i) changes in expected timing of settlement primarily at the DBM and DJ Basin complexes and Hugoton and DBJV systems, and (ii) changes in property lives primarily at the Granger, Brasada and Red Desert complexes and the Hilight and Non-Operated Marcellus Interest systems. The liabilities incurred for the year ended December 31, 2014 , increased primarily due to the acquisition of DBM in the fourth quarter of 2014 and continued capital expansion at the DJ Basin complex. Revisions in estimated liabilities for the year ended December 31, 2014 , are related to changes in property lives and changes in the expected timing of settlement, primarily at the DJ Basin complex, Granger complex, Hugoton and Hilight systems, MIGC, OTTCO, Brasada complex and Non-Operated Marcellus Interest systems.

Debt and Interest Expense

Debt and Interest Expense	12 Months Ended
	Dec. 31, 2015
Debt Instruments [Abstract]
Debt and Interest Expense	12. DEBT AND INTEREST EXPENSE At December 31, 2015 , the Partnership’s debt consisted of 5.375% Senior Notes due 2021 (the “2021 Notes”), 4.000% Senior Notes due 2022 (the “2022 Notes”), 2.600% Senior Notes due 2018 (the “2018 Notes”), 5.450% Senior Notes due 2044 (the “2044 Notes”), 3.950% Senior Notes due 2025 (the “2025 Notes”), and borrowings on the RCF. The following table presents the Partnership’s outstanding debt as of December 31, 2015 and 2014: December 31, 2015 December 31, 2014 thousands Principal Carrying Value Fair Value (1) Principal Carrying Value Fair Value (1) 2021 Notes $ 500,000 $ 496,285 $ 513,645 $ 500,000 $ 495,714 $ 549,530 2022 Notes 670,000 672,572 595,744 670,000 672,930 681,942 2018 Notes 350,000 350,348 339,293 350,000 350,474 352,162 2044 Notes 400,000 393,923 321,499 400,000 393,836 417,619 2025 Notes 500,000 494,229 422,285 — — — RCF 300,000 300,000 300,000 510,000 510,000 510,000 Total long-term debt $ 2,720,000 $ 2,707,357 $ 2,492,466 $ 2,430,000 $ 2,422,954 $ 2,511,253 (1) Fair value is measured using the market approach and Level 2 inputs. 12. DEBT AND INTEREST EXPENSE (CONTINUED) Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2015 and 2014: thousands Carrying Value Balance at December 31, 2013 $ 1,418,169 RCF borrowings 1,160,000 Issuance of 2044 Notes 400,000 Issuance of 2018 Notes 100,000 Repayments of RCF borrowings (650,000 ) Other (5,215 ) Balance at December 31, 2014 $ 2,422,954 RCF borrowings 400,000 Issuance of 2025 Notes 500,000 Repayments of RCF borrowings (610,000 ) Other (5,597 ) Balance at December 31, 2015 $ 2,707,357 Senior Notes. The 2025 Notes issued in June 2015 were offered at a price to the public of 98.789% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2025 Notes is 4.205% . Interest is paid semi-annually on June 1 and December 1 of each year. Proceeds (net of underwriting discount of $3.3 million , original issue discount and debt issuance costs) were used to repay a portion of the amount outstanding under the RCF. The 2044 Notes issued in March 2014 were offered at a price to the public of 98.443% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2044 Notes is 5.633% . Interest is paid semi-annually on April 1 and October 1 of each year. Proceeds (net of underwriting discount of $3.5 million , original issue discount and debt issuance costs) were used to repay amounts then outstanding under the RCF and for general partnership purposes. The 2018 Notes issued in March 2014 were offered at a price to the public of 100.857% of the face amount. Including the effects of the issuance premium for the March 2014 offering, the issuance discount for the August 2013 offering of 2018 Notes and underwriting discounts, the effective interest rate of the 2018 Notes is 2.743% . Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $0.6 million , original issue premium and debt issuance costs) were used to repay amounts then outstanding under the RCF and for general partnership purposes. At December 31, 2015 , the Partnership was in compliance with all covenants under the indentures governing its outstanding notes. 12. DEBT AND INTEREST EXPENSE (CONTINUED) Revolving credit facility. The $1.2 billion RCF, which is expandable to a maximum of $1.5 billion , matures in February 2019 and bears interest at London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 0.975% to 1.45% , or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% , or (c) LIBOR plus 1% , in each case plus applicable margins currently ranging from zero to 0.45% , based upon the Partnership’s senior unsecured debt rating. The interest rate on the RCF was 1.73% and 1.47% at December 31, 2015 and 2014, respectively. The Partnership is required to pay a quarterly facility fee currently ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), based upon the Partnership’s senior unsecured debt rating. The facility fee rate was 0.20% at December 31, 2015 and 2014. As of December 31, 2015 , the Partnership had $300.0 million of outstanding borrowings, $6.4 million in outstanding letters of credit and $893.6 million available for borrowing under the RCF. At December 31, 2015 , the Partnership was in compliance with all covenants under the RCF. The 2021 Notes, 2022 Notes, 2018 Notes, 2044 Notes, 2025 Notes and obligations under the RCF are recourse to the Partnership’s general partner. The Partnership’s general partner is indemnified by a wholly owned subsidiary of Anadarko, WGRI, against any claims made against the general partner under the 2022 Notes, 2021 Notes, and/or the RCF. In connection with the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests, the Partnership’s general partner and other wholly owned subsidiaries of Anadarko entered into indemnification agreements, whereby such subsidiaries agreed to indemnify the Partnership’s general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests. These indemnification agreements apply to the 2044 Notes, 2018 Notes and/or RCF borrowings outstanding related to the aforementioned acquisitions. The Partnership’s general partner, the other indemnifying subsidiaries of Anadarko and WGRI also amended and restated the indemnity agreements between them to (i) conform language among all the indemnification agreements and (ii) reduce the amount for which WGRI would indemnify the Partnership’s general partner by an amount equal to any amounts payable to the Partnership’s general partner under the indemnification agreements related to the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests. Interest expense. The following table summarizes the amounts included in interest expense: Year Ended December 31, thousands 2015 2014 2013 Third parties Long-term debt $ 102,058 $ 81,495 $ 59,293 Amortization of debt issuance costs and commitment fees 5,734 5,103 4,449 Capitalized interest (8,318 ) (9,832 ) (11,945 ) Total interest expense – third parties 99,474 76,766 51,797 Affiliates Deferred purchase price obligation – Anadarko (1) 14,398 — — Total interest expense – affiliates 14,398 — — Interest expense $ 113,872 $ 76,766 $ 51,797 (1) See Note 2 for a discussion of the accretion and net present value of the Deferred purchase price obligation - Anadarko.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	13. COMMITMENTS AND CONTINGENCIES Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As of December 31, 2015 and 2014 , the consolidated balance sheets included $2.6 million and $2.0 million , respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities and the long-term portion of these amounts is included in Asset retirement obligations and other. The recorded obligations do not include any anticipated insurance recoveries. The majority of payments related to these obligations are expected to be made over the next five years . Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes that the amounts reflected in the Partnership’s recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership’s overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered. See Note 10 and Note 11 . Litigation and legal proceedings. In March 2011, DCP Midstream, LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering, LLC, in Weld County District Court (the “Court”) in Colorado, alleging that Anadarko diverted gas from DCP’s gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering, LLC, the entity that holds the Wattenberg assets (located within the DJ Basin complex). Anadarko countersued DCP asserting that DCP has not properly allocated values and charges to Anadarko for the gas that DCP gathers and/or processes, and seeks a judgment that DCP has no valid gathering or processing rights to much of the gas production it is claiming, in addition to other claims. In January 2016, the parties entered into a settlement of these matters and the lawsuit was dismissed in February 2016 with no cash impact to the Partnership. 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 the final disposition of which could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. Other commitments. The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates. As of December 31, 2015 , the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of $45.0 million , the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to the construction of Trains IV and V at the DBM complex, progress payments made towards the construction of Train VI, also at the DBM complex, and expansion projects at the DBJV system and the DJ Basin complex. Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations, for which Anadarko charges the Partnership rent. The leases for the corporate offices and shared field offices extend through 2017 and 2018, respectively, and the lease for the warehouse extends through February 2017. Rent expense associated with the office, warehouse and equipment leases was $18.9 million , $9.4 million and $7.6 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. 13. COMMITMENTS AND CONTINGENCIES (CONTINUED) The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2015 , that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement: thousands Operating Leases 2016 $ 2,614 2017 1,705 2018 109 2019 — 2020 — Thereafter — Total $ 4,428

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	14. SUBSEQUENT EVENTS On February 24, 2016 , the Partnership announced that it agreed to acquire Anadarko’s 100% interest in Springfield Pipeline LLC (“Springfield”) for $750.0 million . Springfield’s sole asset is a 50.1% interest in the Springfield oil and gas gathering system (the “Springfield system”), which consists of oil and gas gathering lines located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership intends to finance the acquisition, which is expected to close by March 15, 2016, subject to obtaining necessary regulatory approvals, through the issuance of $449.0 million in aggregate amount of 8.5% perpetual convertible preferred units to private investors at a price of $32.00 per unit, the issuance of 1,253,761 and 835,841 of the Partnership’s common units at a price of $29.91 per common unit to Anadarko and WGP, respectively, and the borrowing of $247.5 million on the RCF. The convertible preferred units issuance includes an over-allotment feature that may result in the issuance of up to an additional $252.6 million in aggregate amount of such convertible preferred units within 30 days following the closing of the initial issuance, the net proceeds of which would be used to pay down RCF borrowings. Net proceeds from the issuance of the convertible preferred units will be $440.0 million . Additionally, the convertible preferred units are expected to pay a distribution of $2.72 per year and, subject to certain limitations and adjustments, become convertible into the Partnership’s common units on a one -for-one basis on the second anniversary of the issuance of such convertible preferred units. WGP will fund its WES unit purchase by drawing on a secured revolving credit facility that will close on or before the closing date of the Springfield acquisition.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Business combinations policy	Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 33.75% share of the assets, liabilities, revenues and expenses attributable to the Non-Operated Marcellus Interest systems and Anadarko-Operated Marcellus Interest systems and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system and the DBJV system (see Note 2 ) in the accompanying consolidated financial statements. The 25% membership interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements for all periods presented. Presentation of Partnership assets. The term “Partnership assets” refers to the assets owned and interests accounted for under the equity method (see Note 9 ) by the Partnership as of December 31, 2015 . Because Anadarko controls the Partnership through its ownership and 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. See Note 2 . For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s 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 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. DBJV acquisition . Because the acquisition of DBJV was a transfer of net assets between entities under common control, the Partnership’s historical financial statements previously filed with the SEC have been recast in this Form 10-K to include the results attributable to the DBJV system as if the Partnership owned DBJV for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of DBJV have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned DBJV during the periods reported. DBM acquisition . The DBM acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the DBM acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the DBM acquisition were included in the Partnership’s consolidated statement of income beginning on the acquisition date in the fourth quarter of 2014.
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 under the particular circumstances. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known.
Fair value policy	Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows: Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 – Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement). Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership is required to measure fair value and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the Partnership uses the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 12 . The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items. Deferred purchase price obligation - Anadarko. The consideration to be paid by the Partnership for the acquisition of DBJV consists of a cash payment to Anadarko due on March 31, 2020. The cash payment will be equal to (a) eight multiplied by the average of the Partnership’s share in the Net Earnings (see definition below) of the DBJV system for the calendar years 2018 and 2019, less (b) the Partnership’s share of all capital expenditures incurred for the DBJV system between March 1, 2015, and February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to the DBJV system on an accrual basis. As of the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Net Earnings and capital expenditures for the DBJV system) was $282.8 million , which had a net present value of $174.3 million , using a discount rate of 10% . As of December 31, 2015 , the net present value of this obligation was $188.7 million and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion expense for the year ended December 31, 2015 was $14.4 million and zero for each of the years ended December 31, 2014 and 2013 , and has been recorded as a charge to interest expense. Any subsequent changes to the estimated future payment obligation, if applicable, will be calculated using a discounted cash flow model with a 10% discount rate. Such changes will be recorded as adjustments within Common units on the consolidated balance sheets and consolidated statements of equity and partners’ capital, with accretion adjustments (financing-related) as a result of these changes recorded within interest expense on the consolidated statements of income in the period of the change. DBM acquisition . The DBM acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the DBM acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the DBM acquisition were included in the Partnership’s consolidated statement of income beginning on the acquisition date in the fourth quarter of 2014. The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the DBM acquisition using inputs that are not observable in the market and thus represent Level 3 inputs. The fair values of the processing plants, gathering system, and related facilities and equipment are based on market and cost approaches. The fair value of the intangible assets was determined using an income approach. Deferred taxes represent the tax effects of differences in the tax basis and acquisition-date fair value of the assets acquired and liabilities assumed. 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 December 31, 2017 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted to 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. Note receivable - Anadarko and Deferred purchase price obligation - Anadarko. Concurrently with the closing of the Partnership’s May 2008 IPO, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50% , payable quarterly. The fair value of the note receivable from Anadarko was $252.3 million and $317.8 million at December 31, 2015 and 2014, 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. Also during 2015, the Partnership recognized impairments of $514.1 million , primarily due to impairments of $280.2 million at the Red Desert complex and $220.9 million at the Hilight system. Using the income approach and Level 3 fair value inputs, the Red Desert complex was impaired to its estimated salvage value of $6.3 million and the Hilight system was impaired to its estimated fair value of $28.8 million . These impairments were triggered by a reduction in estimated future cash flows caused by the low commodity price environment and resulting reduced producer drilling activity and related throughput. Also during this period, the Partnership recognized impairments of $13.0 million , primarily due to (i) the abandonment of compressors at the MIGC system and (ii) the cancellation of projects at the Non-Operated Marcellus Interest systems, the DBJV system and the Brasada, Red Desert and DJ Basin complexes. Prolonged low or further declines in commodity prices and changes to producers’ drilling plans in response to lower prices could result in additional impairments in future periods. During 2014, the Partnership recognized impairments of $3.1 million , primarily related to a non-operational plant in the Powder River Basin that was impaired to its estimated salvage value of $2.4 million , using the income approach and Level 3 fair value inputs, the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems and a compressor no longer in service at the Hilight system.
Cash equivalents policy	Cash equivalents. The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Bad-debt reserve policy	Bad-debt reserve. The Partnership’s revenues are primarily from Anadarko, for which no credit limit is maintained. The Partnership analyzes its exposure to bad debts on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. As of December 31, 2015 and 2014 , the Partnership’s bad-debt reserve was immaterial.
Imbalances policy	Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers’ pipelines. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2015 , imbalance receivables and payables were $2.1 million and $1.6 million , respectively. As of December 31, 2014 , imbalance receivables and payables were $0.4 million and $0.7 million , respectively. Net changes in imbalance payables and receivables are reported in cost of product.
Inventory policy	Inventory. The cost of NGLs inventories is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets. See Note 10 .
Property, plant and equipment policy	Property, plant and equipment. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the assets acquired from Anadarko are initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to partners’ capital. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred. Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts the Partnership receives from insurance carriers are net of any deductibles related to the covered event. The Partnership records a receivable from insurance to the extent it recognizes a loss from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any of the Partnership’s insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. The Partnership recognizes gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, the Partnership does not recognize a gain related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or the Partnership has a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, in the consolidated balance sheets and presented as capital expenditures in the Partnership’s consolidated statements of cash flows. With respect to business interruption insurance claims, the Partnership recognizes income only when non-refundable cash proceeds are received from insurers, which are presented in the Partnership’s consolidated statements of income as a component of Operating income (loss). In December 2015, there was an initial fire and secondary explosion at the DBM complex. See Note 7 . For the year ended December 31, 2015, the Partnership has recorded $20.3 million of losses in Gain on divestiture and other, net in the consolidated statements of income, related to this involuntary conversion event based on the difference between the net book value of the affected assets and the insurance claim receivable of $48.5 million . Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area. Management evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense. Refer to Note 7 for a description of impairments recorded during the years ended December 31, 2015 , 2014 and 2013. 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. These cash receipts are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. See Note 5 .
Capitalized interest policy	Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset.
Goodwill policy	Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. Refer to Note 8 for a discussion of goodwill. The Partnership evaluates goodwill for impairment annually, as of October 1, or more often as facts and circumstances warrant. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. An initial qualitative assessment is performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. If the Partnership concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, based on a hypothetical purchase price allocation, goodwill is written down to its implied fair value through a charge to operating expense. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement.
Other intangible assets policy	Other intangible assets. The Partnership assesses intangible assets, as described in Note 8 , for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment within this Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets.
Asset retirement obligations and environmental expenditures policy	Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Over time, the discounted liability is adjusted to its expected settlement value through accretion expense, which is reported within depreciation and amortization in the consolidated statements of income. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 11 . Environmental expenditures. The Partnership expenses environmental obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 13 .
Segments policy	Segments. The Partnership’s operations are organized into a single operating segment, the assets of which gather, process, compress, treat and transport Anadarko and third-party natural gas, condensate, NGLs and crude oil in the United States.
Revenues and cost of product policy	Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are performed. Producers’ wells are connected to the Partnership’s gathering systems for delivery of natural gas to the Partnership’s processing or treating plants, where the natural gas is processed to extract NGLs and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered and delivered to pipelines for market delivery. Under cost-of-service gathering agreements, the Partnership earns fees for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate is sold. The percentage of the product sale ultimately paid to the producer is recorded as a related cost of product expense. The Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue to either sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price uncertainty that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. See Note 5 . Revenue is recognized from the sale of condensate and NGLs upon transfer of title, and related purchases are recorded as cost of product. The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. Transportation revenues are also generated from interruptible contracts pursuant to which a fee is charged to the customer based on volumes transported through the pipeline. Revenues for transportation of natural gas and NGLs are recognized over the period of firm transportation contracts or, in the case of usage fees and interruptible contracts, when the volumes are received into the pipeline. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission (the “FERC”), and refund reserve liabilities are established where appropriate. Proceeds from the sale of residue, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate sales in the consolidated statements of income. Revenues attributable to the fixed-fee component of gathering and processing contracts as well as demand charges and commodity usage fees on transportation contracts are reported as revenues from gathering, processing and transportation of natural gas and natural gas liquids in the consolidated statements of income.
Equity-based compensation policy	Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,128,015 units remained available for future issuance as of December 31, 2015. Upon vesting of each phantom unit awarded under the WES LTIP, the holder will receive common units of the Partnership or, at the discretion of the general partner’s Board of Directors, cash in an amount equal to the market value of common units of the Partnership on the vesting date. Equity-based compensation expense attributable to grants made under the WES LTIP impacts the Partnership’s cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. The Partnership amortizes stock-based compensation expense attributable to awards granted under the WES LTIP over the vesting periods applicable to the awards. Additionally, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) for the years ended December 31, 2015 and 2014 and (ii) the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”) for all periods presented. Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized.
Income taxes policy	Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership’s acquisition of these assets from Anadarko. For periods beginning on and subsequent to the Partnership’s acquisition of the Partnership assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership. The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2015 or 2014. With respect to assets acquired from Anadarko, the Partnership recorded Anadarko’s historic deferred income taxes for the periods prior to the Partnership’s ownership of the assets. For periods subsequent to the Partnership’s acquisition, the Partnership is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the assets acquired from Anadarko.
Net income per common unit policy	Net income (loss) per common unit. The Partnership applies the two-class method in determining net income (loss) per unit applicable to master limited partnerships having multiple classes of securities including common units, Class C units, general partner units and IDRs. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Under the two-class method, net income (loss) per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes to its unitholders an amount of cash equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period or any other economic or practical limitation on the ability to make a full distribution of all of the net income for the period. The Partnership’s net income (loss) earned on and subsequent to the date of the acquisition of the Partnership assets is allocated to the general partner and the limited partners, including the Class C unitholder, in accordance with their respective weighted-average ownership percentages and, when applicable, giving effect to incentive distributions allocable to the general partner. Specifically, net income equal to the amount of available cash (as defined by the Amended and Restated Agreement of Limited Partnership of the Partnership (the “partnership agreement”)) is allocated to the general partner, common and Class C unitholders consistent with actual cash distributions and capital account allocations, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and the Class C unitholder in accordance with their respective weighted-average ownership percentages during each period. Additionally, the Partnership’s net income (loss) allocable to the common unitholders is net of amortization of the beneficial conversion feature related to the Class C units (see Class C units in Note 4 ). 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 for purposes of calculating net income (loss) per common unit. See Note 4 .
Recently issued accounting standards policy	Recently issued accounting standards . The Financial Accounting Standards Board recently issued the following Accounting Standards Updates (“ASUs”): ASU 2015-17 , Income Taxes (Topic - 740)—Balance Sheet Classification of Deferred Taxes . This ASU requires all deferred tax assets and liabilities, including any related valuation allowance, to be presented in the balance sheet as noncurrent. The early adoption of this ASU using a retrospective approach had no material impact on the Partnership’s consolidated financial statements. See Note 6 . 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) ASU 2015-06, Earnings Per Share (Topic - 260)—Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions . This ASU contains guidance that addresses the historical earnings per unit presentation for master limited partnerships that apply the two-class method of calculating earnings per unit. When a general partner transfers or “drops down” net assets to a master limited partnership, the transaction is accounted for as a transaction between entities under common control, and the statements of operations are adjusted retrospectively to reflect the transaction. This ASU specifies that the historical earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner, and the previously reported earnings per unit of the limited partners should not change as a result of the dropdown transaction. The ASU also requires additional disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective approach, with early adoption permitted. While the Partnership believes it is currently in compliance with this ASU, it continues to evaluate the impact of the adoption of this ASU on its consolidated financial statements. ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30)—Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Partnership adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption will result in a reclassification that will reduce Other assets and Long-term debt by $16.7 million on the Partnership’s consolidated balance sheet at December 31, 2015, when included in future filings. ASU 2015-02, Consolidation—Amendments to the Consolidation Analysis . This ASU amends existing requirements applicable to reporting entities that are required to evaluate consolidation of a legal entity under the variable interest entity (“VIE”) or voting interest entity models. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including an additional requirement that a limited partnership will be a VIE unless the limited partners have either substantive kick-out or participating rights over the general partner. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. The Partnership has evaluated the impact of the adoption of this ASU on its consolidated financial statements and determined it does not have any entities for which it is the primary beneficiary for accounting purposes. The adoption of this ASU will not have a material impact on the Partnership’s consolidated financial statements. ASU 2014-09, Revenue from Contracts with Customers . This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition , and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Partnership is required to adopt the new standard in the first quarter of 2018 using one of two retrospective application methods. The Partnership is continuing to evaluate the provisions of this ASU, and has not determined the impact this standard may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.
Equity method investments policy	Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Assets and Investments Table	As of December 31, 2015 , the Partnership’s assets and investments accounted for under the equity method consisted of the following: Owned and Operated Operated Interests Non-Operated Interests Equity Interests Natural gas gathering systems 12 2 5 2 Natural gas treating facilities 12 4 — 3 Natural gas processing plants/trains (1) 18 5 — 2 NGL pipelines 2 — — 3 Natural gas pipelines 4 — — — Oil pipeline — — — 1 (1) On December 3, 2015, an incident occurred at the DBM complex. See Note 7 .

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Acquisitions Table	The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2015 , 2014 and 2013 , and identifies the funding sources for such acquisitions: thousands except unit and percent amounts Acquisition Date Percentage Deferred Purchase Price Obligation - Anadarko Borrowings Cash On Hand Common Units Issued to Anadarko Class C Units Issued to Anadarko Non-Operated Marcellus Interest (1) 03/01/2013 33.75 % $ — $ 250,000 $ 215,500 449,129 — Anadarko-Operated Marcellus Interest (2) 03/08/2013 33.75 % — 133,500 — — — Mont Belvieu JV (3) 06/05/2013 25 % — — 78,129 — — OTTCO (4) 09/03/2013 100 % — 27,500 — — — TEFR Interests (5) 03/03/2014 Various (5) — 350,000 6,250 308,490 — DBM (6) 11/25/2014 100 % — 475,000 298,327 — 10,913,853 DBJV system (7) 03/02/2015 50 % 174,276 — — — — (1) The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million . (2) The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a $1.1 million decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation. (3) The Partnership acquired a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting. (4) The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming. (5) The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million . (6) The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price. (7) The Partnership acquired Anadarko’s interest in Delaware Basin JV Gathering LLC (“DBJV”), which owns a 50% interest in a gathering system and related facilities (the “DBJV system”). The DBJV system is located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. The Partnership currently estimates the future payment will be $282.8 million , the net present value of which was $174.3 million as of the acquisition date. See DBJV acquisition—Deferred purchase price obligation - Anadarko below.
Impact to Historical Consolidated Statements of Income Table	The following table presents the impact of the DBJV system on revenues and other, equity income, net and net income (loss) as presented in the Partnership’s historical consolidated statements of income: Year Ended December 31, 2014 thousands Partnership Historical (1) DBJV System Combined Revenues and other $ 1,320,756 $ 62,112 $ 1,382,868 Equity income, net 57,836 — 57,836 Net income (loss) 390,558 17,309 407,867 Year Ended December 31, 2013 thousands Partnership Historical (1) DBJV System Combined Revenues and other $ 1,052,937 $ 32,545 $ 1,085,482 Equity income, net 22,948 — 22,948 Net income (loss) 285,443 4,096 289,539 (1) See Adjustments to previously issued financial statements in Note 1 .
Purchase Price Allocation Table	The following is the final allocation of the purchase price as of December 31, 2015 , including $3.5 million of post-closing purchase price adjustments, to the assets acquired and liabilities assumed in the DBM acquisition as of the acquisition date: thousands Current assets $ 60,888 Property, plant and equipment 467,171 Goodwill 284,749 Other intangible assets 811,048 Accounts payables (18,621 ) Accrued liabilities (37,360 ) Deferred income taxes (1,342 ) Asset retirement obligations and other (9,060 ) Total purchase price $ 1,557,473
Pro Forma Condensed Financial Information Table	The following table presents pro forma condensed financial information of the Partnership as if the DBM acquisition had occurred on January 1, 2013: Year Ended December 31, thousands except per-unit amounts 2014 2013 Revenues and other $ 1,506,135 $ 1,162,749 Net income (loss) 349,729 243,478 Net income (loss) attributable to Western Gas Partners, LP 335,704 232,622 Net income (loss) per common unit – basic and diluted 1.34 1.12

Partnership Distributions (Tabl

Partnership Distributions (Tables)	12 Months Ended
	Dec. 31, 2015
Distributions Made to Members or Limited Partners [Abstract]
Cash Distributions Table	The Board of Directors of the general partner 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 2013 March 31 $ 0.540 $ 70,143 May 2013 June 30 0.560 79,315 August 2013 September 30 0.580 83,986 November 2013 December 31 0.600 92,609 February 2014 2014 March 31 $ 0.625 $ 98,749 May 2014 June 30 0.650 105,655 August 2014 September 30 0.675 111,608 November 2014 December 31 0.700 126,044 February 2015 2015 March 31 $ 0.725 $ 133,203 May 2015 June 30 0.750 139,736 August 2015 September 30 0.775 146,160 November 2015 December 31 (1) 0.800 152,588 February 2016 (1) On January 21, 2016 , the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.800 per unit, or $152.6 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution was paid on February 11, 2016 , to unitholders of record at the close of business on February 1, 2016 .
PIK Class C Units Distributions Table	The Partnership issued the following PIK Class C units to APC Midstream Holdings, LLC (“AMH”), the holder of the Class C units, for the periods presented: thousands except unit amounts For the Quarters Ended PIK Class C Units Implied Fair Value Date of 2014 December 31 (1) 45,711 $ 3,072 February 2015 2015 March 31 118,230 $ 8,101 May 2015 June 30 153,020 8,721 August 2015 September 30 181,048 9,724 November 2015 December 31 323,584 10,070 February 2016 (1) Prorated for the 37 -day period the Class C units were outstanding during the fourth quarter of 2014.

Equity and Partners' Capital (T

Equity and Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2015
Partners' Capital Notes [Abstract]
Equity Offerings Table	The Partnership completed the following public offerings of its common units during 2015 , 2014 and 2013, including through its Continuous Offering Programs (“COP”): thousands except unit and per-unit amounts Common Units Issued GP Units Issued (1) Price Per Unit Underwriting Discount and Other Offering Expenses Net Proceeds 2013 May 2013 equity offering (2) 7,015,000 143,163 $ 61.18 $ 13,203 $ 424,733 December 2013 equity offering (3) 4,800,000 97,959 61.51 9,447 291,827 $125.0 million COP (4) 685,735 13,996 60.84 965 41,603 2014 $125.0 million COP (5) 1,133,384 23,132 $ 73.48 $ 1,738 $ 83,245 November 2014 equity offering (6) 8,620,153 153,061 70.85 18,615 602,967 2015 $500.0 million COP (7) 873,525 — $ 66.61 $ 805 $ 57,385 (1) Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution. (2) Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option. (3) Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million . (4) Represents common and general partner units issued during the year ended December 31, 2013, pursuant to the Partnership’s registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “$125.0 million COP”). Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2013, were $42.6 million . The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2013. (5) Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million . The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement. (6) Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million . Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. (7) Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million , respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million , respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015.
Limited Partner and General Partner Units Table	The following table summarizes the common, Class C and general partner units issued during the years ended December 31, 2015 and 2014: Common Units Class C Units General Partner Units Total Balance at December 31, 2013 117,322,812 — 2,394,345 119,717,157 December 2013 equity offering 300,000 — 6,122 306,122 WES LTIP award vestings 10,291 — 112 10,403 TEFR Interests acquisition 308,490 — 6,296 314,786 $125.0 million COP 1,133,384 — 23,132 1,156,516 November 2014 equity offering 8,620,153 — 153,061 8,773,214 Class C unit issuance — 10,913,853 — 10,913,853 Balance at December 31, 2014 127,695,130 10,913,853 2,583,068 141,192,051 PIK Class C units — 498,009 — 498,009 WES LTIP award vestings 8,310 — — 8,310 $500.0 million COP 873,525 — — 873,525 Balance at December 31, 2015 128,576,965 11,411,862 2,583,068 142,571,895
Calculation of Net Income (Loss) Per Unit Table	The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units: Year Ended December 31, thousands except per-unit amounts 2015 2014 2013 Net income (loss) attributable to Western Gas Partners, LP $ (73,538 ) $ 393,842 $ 278,723 Pre-acquisition net (income) loss allocated to Anadarko (1,742 ) (16,353 ) (8,224 ) General partner interest in net (income) loss (180,996 ) (120,980 ) (69,633 ) Limited partners’ interest in net income (loss) (256,276 ) 256,509 200,866 Net income (loss) allocable to common units (1) (250,210 ) 254,737 200,866 Net income (loss) allocable to Class C units (1) (6,066 ) 1,772 — Limited partners’ interest in net income (loss) $ (256,276 ) $ 256,509 $ 200,866 Net income (loss) per unit Common units - basic $ (1.95 ) $ 2.13 $ 1.83 Common units – diluted (2) (1.95 ) 2.12 1.83 Weighted-average units outstanding Common units – basic 128,345 119,822 109,872 Class C units (2) 11,114 1,106 — Common units – diluted 139,459 120,928 109,872 (1) Adjusted to reflect amortization for the beneficial conversion feature. See Class C units above for a discussion of the Class C units. (2) Inclusion of Class C units in the calculation for the year ended December 31, 2015, would have had an anti-dilutive effect.

Transactions with Affiliates (T

Transactions with Affiliates (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract]
Commodity Price Swap Agreements Table	Below is a summary of the fixed price ranges on all of the Partnership’s outstanding commodity price swap agreements as of December 31, 2015 : per barrel except natural gas 2016 Ethane $ 18.41 − 23.11 Propane 47.08 − 52.90 Isobutane 62.09 − 73.89 Normal butane 54.62 − 64.93 Natural gasoline 72.88 − 81.68 Condensate 76.47 − 81.68 Natural gas (per MMBtu) 4.87 − 5.96
Gains (Losses) on Commodity Price Swap Agreements Table	The following table summarizes gains and losses upon settlement of commodity price swap agreements recognized in the consolidated statements of income: Year Ended December 31, thousands 2015 2014 2013 Gains (losses) on commodity price swap agreements related to sales: (1) Natural gas sales $ 45,978 $ 9,494 $ 21,382 Natural gas liquids sales 145,258 113,866 102,076 Total 191,236 123,360 123,458 Losses on commodity price swap agreements related to purchases (2) (124,944 ) (68,492 ) (85,294 ) Net gains (losses) on commodity price swap agreements $ 66,292 $ 54,868 $ 38,164 (1) Reported in affiliate natural gas, natural gas liquids and drip condensate sales in the consolidated statements of income in the period in which the related sale is recorded. (2) Reported in cost of product in the consolidated statements of income in the period in which the related purchase is recorded.
Commodity Price Swap Agreements Extensions Tables	The table below summarizes the swap prices for the extension period compared to the forward market prices as of the agreement date, June 25, 2015. DJ Basin Complex Hugoton System per barrel except natural gas 2015 Swap Prices Market Prices (1) 2015 Swap Prices Market Prices (1) Ethane $ 18.41 $ 1.96 — — Propane 47.08 13.10 — — Isobutane 62.09 19.75 — — Normal butane 54.62 18.99 — — Natural gasoline 72.88 52.59 — — Condensate 76.47 52.59 $ 78.61 $ 32.56 Natural gas (per MMBtu) 5.96 2.75 5.50 2.74 (1) Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of June 25, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. On December 8, 2015, the commodity price swap agreements with Anadarko for the DJ Basin complex and Hugoton system were further extended from January 1, 2016, through December 31, 2016. The table below summarizes the swap prices for the extension period compared to the forward market prices as of the agreement date, December 8, 2015. DJ Basin Complex Hugoton System per barrel except natural gas 2016 Swap Prices Market Prices (1) 2016 Swap Prices Market Prices (1) Ethane $ 18.41 $ 0.60 — — Propane 47.08 10.98 — — Isobutane 62.09 17.23 — — Normal butane 54.62 16.86 — — Natural gasoline 72.88 26.15 — — Condensate 76.47 34.65 $ 78.61 $ 18.81 Natural gas (per MMBtu) 5.96 2.11 5.50 2.12 (1) Represents the NYMEX forward strip price as of December 8, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.
Related Party Transactions Tables	The following table summarizes the amounts the Partnership reimbursed to Anadarko: Year Ended December 31, thousands 2015 2014 2013 General and administrative expenses $ 22,896 $ 20,249 $ 16,882 Public company expenses 8,950 8,006 7,152 Total reimbursement $ 31,846 $ 28,255 $ 24,034 The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment: Year Ended December 31, 2015 2014 2013 2015 2014 2013 thousands Purchases Sales Cash consideration $ 12,664 $ 22,943 $ 11,211 $ 925 $ — $ 85 Net carrying value 7,944 12,210 5,309 972 — 38 Partners’ capital adjustment $ 4,720 $ 10,733 $ 5,902 $ (47 ) $ — $ 47 The following table summarizes affiliate transactions, which include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas: Year ended December 31, thousands 2015 2014 2013 Revenues and other (1) $ 1,029,922 $ 1,053,935 $ 844,203 Equity income, net (1) 71,251 57,836 22,948 Cost of product (1) 167,420 127,906 136,570 Operation and maintenance (2) 67,119 62,306 59,698 General and administrative (3) 30,692 28,970 24,956 Operating expenses 265,231 219,182 221,224 Interest income (4) 16,900 16,900 16,900 Interest expense (5) 14,398 — — Distributions to unitholders (6) 314,200 234,024 169,150 Above-market component of swap extensions with Anadarko 18,449 — — (1) Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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 the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets. (3) Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5 ). (4) Represents interest income recognized on the note receivable from Anadarko. (5) For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 12 ). (6) Represents distributions paid under the partnership agreement (see Note 3 and Note 4 ).
LTIP Award Activity Table	The following table summarizes WES LTIP award activity for the years ended December 31, 2015 , 2014 and 2013 : 2015 2014 2013 Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Phantom units outstanding at beginning of year $ 60.74 9,522 $ 49.47 16,844 $ 41.77 25,619 Vested 60.69 (9,257 ) 49.55 (13,122 ) 41.28 (14,695 ) Granted 69.10 5,212 68.14 5,800 62.49 5,920 Phantom units outstanding at end of year 68.78 5,477 60.74 9,522 49.47 16,844

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit) Table	The components of the Partnership’s income tax expense (benefit) are as follows: Year Ended December 31, thousands 2015 2014 2013 Current income tax expense (benefit) Federal income tax expense (benefit) $ 590 $ (1,729 ) $ (35,872 ) State income tax expense (benefit) 858 63 497 Total current income tax expense (benefit) 1,448 (1,666 ) (35,375 ) Deferred income tax expense (benefit) Federal income tax expense (benefit) 348 10,612 40,846 State income tax expense (benefit) 1,584 2,713 (811 ) Total deferred income tax expense (benefit) 1,932 13,325 40,035 Total income tax expense (benefit) $ 3,380 $ 11,659 $ 4,660
Tax Rate Reconciliation Table	Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows: Year Ended December 31, thousands except percentages 2015 2014 2013 Income (loss) before income taxes $ (60,057 ) $ 419,526 $ 294,199 Statutory tax rate — % — % — % Tax computed at statutory rate $ — $ — $ — Adjustments resulting from: Federal taxes on income attributable to Partnership assets pre-acquisition 942 8,988 5,390 State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) 27 190 629 Texas margin tax expense (benefit) (1) 2,411 2,481 (1,359 ) Income tax expense (benefit) $ 3,380 $ 11,659 $ 4,660 Effective tax rate (6 )% 3 % 2 % (1) Includes a reduction of $2.2 million in deferred state income taxes. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25% . The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted.
Income Tax Temporary Differences Table	The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows: December 31, thousands 2015 2014 Depreciable property $ (4,418 ) $ (44,725 ) Credit carryforwards 512 526 Other intangible assets (2,070 ) (1,450 ) Other 13 7 Net long-term deferred income tax liabilities $ (5,963 ) $ (45,642 )

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Table	A summary of the historical cost of the Partnership’s property, plant and equipment is as follows: December 31, thousands Estimated Useful Life 2015 2014 Land n/a $ 3,191 $ 2,884 Gathering systems 3 to 47 years 5,420,762 4,972,892 Pipelines and equipment 15 to 45 years 136,290 151,107 Assets under construction n/a 324,720 483,347 Other 3 to 40 years 19,674 16,420 Total property, plant and equipment 5,904,637 5,626,650 Accumulated depreciation 1,614,663 1,055,207 Net property, plant and equipment $ 4,289,974 $ 4,571,443

Goodwill and Intangibles (Table

Goodwill and Intangibles (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Other Intangible Assets Table	The following table presents the gross carrying amount and accumulated amortization of other intangible assets: December 31, thousands 2015 2014 Gross carrying amount $ 868,035 $ 892,555 Accumulated amortization (35,908 ) (7,698 ) Other intangible assets $ 832,127 $ 884,857

Equity Investments (Tables)

Equity Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Equity Investments Table	The following table presents the activity in the Partnership’s equity investments for the years ended December 31, 2015 and 2014 : Equity Investments thousands Fort (1) White (2) Rendezvous (3) Mont (4) TEG (5) TEP (6) FRP (7) Total Balance at December 31, 2013 $ 25,172 $ 35,039 $ 60,928 $ 122,480 $ 16,649 $ 197,731 $ 135,401 $ 593,400 Investment earnings (loss), net of amortization 6,344 11,912 1,729 29,029 650 6,108 2,064 57,836 Contributions — 10,456 — 3,957 352 6,623 42,033 63,421 Capitalized interest — — — — — — 857 857 Distributions (5,583 ) (11,330 ) (3,669 ) (34,129 ) (523 ) (5,622 ) (2,111 ) (62,967 ) Distributions in excess of cumulative earnings (8) — (1,762 ) (2,652 ) — (338 ) (6,047 ) (7,256 ) (18,055 ) Balance at December 31, 2014 $ 25,933 $ 44,315 $ 56,336 $ 121,337 $ 16,790 $ 198,793 $ 170,988 $ 634,492 Investment earnings (loss), net of amortization (3,200 ) 14,770 2,292 23,570 586 16,088 17,145 71,251 Contributions — 8,512 — (432 ) — 1,880 1,482 11,442 Distributions (5,611 ) (14,188 ) (4,233 ) (24,248 ) (803 ) (16,340 ) (16,631 ) (82,054 ) Distributions in excess of cumulative earnings (8) — (2,970 ) (3,482 ) (3,138 ) (290 ) (5,618 ) (746 ) (16,244 ) Balance at December 31, 2015 $ 17,122 $ 50,439 $ 50,913 $ 117,089 $ 16,283 $ 194,803 $ 172,238 $ 618,887 (1) The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners. (2) The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members. (3) The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members. (4) The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners. (5) The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members. (6) The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (7) The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (8) Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.
Summarized Equity Investments Financial Information Presented at 100 Percent Tables	The following tables present the summarized combined financial information for the Partnership’s equity investments (amounts represent 100% of investee financial information): Year Ended December 31, thousands 2015 2014 2013 Consolidated Statements of Income Revenues $ 668,797 $ 548,629 $ 261,705 Operating income 381,616 336,188 171,496 Net income 381,161 333,705 170,175 December 31, thousands 2015 2014 Consolidated Balance Sheets Current assets $ 156,180 $ 141,781 Property, plant and equipment, net 2,736,553 2,814,336 Other assets 43,713 48,799 Total assets $ 2,936,446 $ 3,004,916 Current liabilities 78,116 95,102 Non-current liabilities 9,072 22,615 Equity 2,849,258 2,887,199 Total liabilities and equity $ 2,936,446 $ 3,004,916

Components of Working Capital (

Components of Working Capital (Tables)	12 Months Ended
	Dec. 31, 2015
Components Of Working Capital [Abstract]
Accounts Receivable, Net Table	A summary of accounts receivable, net is as follows: December 31, thousands 2015 2014 Trade receivables, net $ 131,221 $ 105,646 Other receivables, net 49,772 3,597 Total accounts receivable, net $ 180,993 $ 109,243
Other Current Assets Table	A summary of other current assets is as follows: December 31, thousands 2015 2014 Natural gas liquids inventory $ 2,403 $ 5,316 Imbalance receivables 2,122 415 Prepaid insurance 2,296 2,443 Other 1,034 1,879 Total other current assets $ 7,855 $ 10,053
Accrued Liabilities Table	A summary of accrued liabilities is as follows: December 31, thousands 2015 2014 Accrued capital expenditures $ 60,702 $ 128,856 Accrued plant purchases 16,425 14,023 Accrued interest expense 26,194 24,741 Short-term asset retirement obligations 3,555 1,224 Short-term remediation and reclamation obligations 1,136 475 Income taxes payable 770 207 Other 8,036 1,263 Total accrued liabilities $ 116,818 $ 170,789

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Table	The following table provides a summary of changes in asset retirement obligations: Year Ended December 31, thousands 2015 2014 Carrying amount of asset retirement obligations at beginning of year $ 110,735 $ 78,535 Liabilities incurred 9,121 13,982 Liabilities settled (7,377 ) (4,195 ) Accretion expense 5,943 4,879 Revisions in estimated liabilities 2,105 17,534 Carrying amount of asset retirement obligations at end of year $ 120,527 $ 110,735

Debt and Interest Expense (Tabl

Debt and Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instruments [Abstract]
Debt Outstanding and Debt Activity Tables	The following table presents the Partnership’s outstanding debt as of December 31, 2015 and 2014: December 31, 2015 December 31, 2014 thousands Principal Carrying Value Fair Value (1) Principal Carrying Value Fair Value (1) 2021 Notes $ 500,000 $ 496,285 $ 513,645 $ 500,000 $ 495,714 $ 549,530 2022 Notes 670,000 672,572 595,744 670,000 672,930 681,942 2018 Notes 350,000 350,348 339,293 350,000 350,474 352,162 2044 Notes 400,000 393,923 321,499 400,000 393,836 417,619 2025 Notes 500,000 494,229 422,285 — — — RCF 300,000 300,000 300,000 510,000 510,000 510,000 Total long-term debt $ 2,720,000 $ 2,707,357 $ 2,492,466 $ 2,430,000 $ 2,422,954 $ 2,511,253 (1) Fair value is measured using the market approach and Level 2 inputs. 12. DEBT AND INTEREST EXPENSE (CONTINUED) Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2015 and 2014: thousands Carrying Value Balance at December 31, 2013 $ 1,418,169 RCF borrowings 1,160,000 Issuance of 2044 Notes 400,000 Issuance of 2018 Notes 100,000 Repayments of RCF borrowings (650,000 ) Other (5,215 ) Balance at December 31, 2014 $ 2,422,954 RCF borrowings 400,000 Issuance of 2025 Notes 500,000 Repayments of RCF borrowings (610,000 ) Other (5,597 ) Balance at December 31, 2015 $ 2,707,357
Interest Expense Table	The following table summarizes the amounts included in interest expense: Year Ended December 31, thousands 2015 2014 2013 Third parties Long-term debt $ 102,058 $ 81,495 $ 59,293 Amortization of debt issuance costs and commitment fees 5,734 5,103 4,449 Capitalized interest (8,318 ) (9,832 ) (11,945 ) Total interest expense – third parties 99,474 76,766 51,797 Affiliates Deferred purchase price obligation – Anadarko (1) 14,398 — — Total interest expense – affiliates 14,398 — — Interest expense $ 113,872 $ 76,766 $ 51,797 (1) See Note 2 for a discussion of the accretion and net present value of the Deferred purchase price obligation - Anadarko.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating Lease Obligations Table	The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2015 , that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement: thousands Operating Leases 2016 $ 2,614 2017 1,705 2018 109 2019 — 2020 — Thereafter — Total $ 4,428

Summary of Significant Accoun38

Summary of Significant Accounting Policies - Asset Table (Details)	Dec. 31, 2015unit
Operated [Member] | Natural Gas Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	12
Operated [Member] | Natural Gas Treating Facilities [Member]
Assets [Line Items]
Assets, number of units	12
Operated [Member] | Natural Gas Processing Plants/Trains [Member]
Assets [Line Items]
Assets, number of units	18	[1]
Operated [Member] | Natural Gas Liquids Pipelines [Member]
Assets [Line Items]
Assets, number of units	2
Operated [Member] | Natural Gas Pipelines [Member]
Assets [Line Items]
Assets, number of units	4
Operated Interests [Member] | Natural Gas Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	2
Operated Interests [Member] | Natural Gas Treating Facilities [Member]
Assets [Line Items]
Assets, number of units	4
Operated Interests [Member] | Natural Gas Processing Plants/Trains [Member]
Assets [Line Items]
Assets, number of units	5	[1]
Non-Operated Interests [Member] | Natural Gas Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	5
Equity Interests [Member] | Natural Gas Gathering Systems [Member]
Assets [Line Items]
Assets, number of units	2
Equity Interests [Member] | Natural Gas 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	[1]
Equity Interests [Member] | Natural Gas Liquids Pipelines [Member]
Assets [Line Items]
Assets, number of units	3
Equity Interests [Member] | Oil Pipeline [Member]
Assets [Line Items]
Assets, number of units	1
[1]	On December 3, 2015, an incident occurred at the DBM complex. See Note 7.

Summary of Significant Accoun39

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Thousands

Mar. 02, 2015

[6]

Mar. 08, 2013

[5]

Mar. 01, 2013

[4]

Nov. 30, 2014

Aug. 31, 2012

Jul. 31, 2009

Dec. 31, 2008

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Jan. 01, 2016

General partner's interest

2.00%

Imbalance receivables

$ 2,122

$ 415

Imbalance payables

1,600

700

Gain on divestiture and other, net

[1]

57,020

0

[2]

$ 0

[2]

Other assets

29,707

28,289

[3]

Long-term debt

$ 2,707,357

2,422,954

[3]

1,418,169

Restatement Adjustment [Member] | Accounting Standards Update 2015-03 And 2015-15 [Member] | Subsequent Event [Member]

Other assets

$ 16,700

Long-term debt

$ 16,700

Western Gas Partners Long Term Incentive Plan [Member]

Units authorized under LTIP

2,250,000

Units available under LTIP

2,128,015

Delaware Basin Midstream Complex [Member]

Gain on divestiture and other, net

$ 20,300

Insurance receivable

48,500

Operating Income (Loss) [Member] | Restatement Adjustment [Member]

Correction of an immaterial error

$ 25,000

$ 39,300

$ 20,500

Non-Operated Marcellus Interest [Member]

Percentage acquired

33.75%

33.75%

Anadarko-Operated Marcellus Interest [Member]

Percentage acquired

33.75%

33.75%

Newcastle [Member]

Percentage acquired

50.00%

50.00%

Delaware Basin JV Gathering LLC [Member]

Percentage acquired

50.00%

50.00%

Chipeta Processing Limited Liability Company [Member]

Percentage acquired

24.00%

51.00%

75.00%

Ownership interest by noncontrolling owner

25.00%

Incentive Distribution Rights [Member] | Western Gas Equity Partners, LP [Member]

General partner's interest

100.00%

General Partner [Member] | Western Gas Equity Partners, LP [Member]

Percentage acquired

100.00%

Fort Union [Member]

Equity investment ownership

14.81%

Rendezvous [Member]

Equity investment ownership

22.00%

White Cliffs [Member]

Equity investment ownership

10.00%

Mont Belvieu JV [Member]

Equity investment ownership

25.00%

Texas Express Gathering LLC [Member]

Equity investment ownership

20.00%

Texas Express Pipeline LLC [Member]

Equity investment ownership

20.00%

Front Range Pipeline LLC [Member]

Equity investment ownership

33.33%

[1]

Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1.

[2]

Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

[3]

Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

[4]

The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million.

[5]

The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a $1.1 million decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation.

[6]

The Partnership acquired Anadarko’s interest in Delaware Basin JV Gathering LLC (“DBJV”), which owns a 50% interest in a gathering system and related facilities (the “DBJV system”). The DBJV system is located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. The Partnership currently estimates the future payment will be $282.8 million, the net present value of which was $174.3 million as of the acquisition date. See DBJV acquisition—Deferred purchase price obligation - Anadarko below.

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisitions Table (Details) $ in Thousands

Mar. 02, 2015USD ($)

Nov. 25, 2014USD ($)shares

Mar. 03, 2014USD ($)shares

Sep. 03, 2013USD ($)

Jun. 05, 2013USD ($)

Mar. 08, 2013USD ($)

Mar. 01, 2013USD ($)shares

Nov. 30, 2014USD ($)shares

Dec. 31, 2013shares

[4]

May. 31, 2013shares

[5]

Dec. 31, 2015USD ($)shares

Dec. 31, 2014USD ($)shares

Dec. 31, 2013USD ($)

[1]

Business Acquisition [Line Items]

Borrowings

$ 889,606

$ 1,646,878

[1]

$ 957,503

Units issued | shares

498,009

10,913,853

General partner units issued | shares

2,583,068

2,583,068

Affiliates [Member]

Business Acquisition [Line Items]

Cash on hand

$ 12,664

$ 379,193

[1]

476,711

Class C Units [Member]

Business Acquisition [Line Items]

Units issued | shares

498,009

10,913,853

Proceeds from the issuance of units

$ 750,000

$ 0

$ 750,000

[1]

$ 0

General Partner [Member]

Business Acquisition [Line Items]

Units issued | shares

[3]

153,061

[2]

97,959

143,163

Non-Operated Marcellus Interest [Member]

Business Acquisition [Line Items]

Percentage acquired

33.75%

[6]

33.75%

Borrowings

[6]

$ 250,000

Cash on hand

[6]

$ 215,500

General partner units issued | shares

9,166

Non-Operated Marcellus Interest [Member] | Common Units [Member]

Business Acquisition [Line Items]

Common units issued | shares

[6]

449,129

Non-Operated Marcellus Interest [Member] | General Partner [Member]

Business Acquisition [Line Items]

Proceeds from the issuance of units

$ 500

Anadarko-Operated Marcellus Interest [Member]

Business Acquisition [Line Items]

Percentage acquired

33.75%

[7]

33.75%

Borrowings

[7]

$ 133,500

Purchase price adjustment

$ 1,100

Mont Belvieu Joint Venture [Member]

Business Acquisition [Line Items]

Equity investment ownership

[8]

25.00%

Cash on hand

[8]

$ 78,129

Mont Belvieu Joint Venture [Member] | Fractionation Train [Member]

Business Acquisition [Line Items]

Assets, number of units

2

Overland Trail Transmission Limited Liability Company [Member]

Business Acquisition [Line Items]

Percentage acquired

[9]

100.00%

Borrowings

[9]

$ 27,500

Texas Express and Front Range [Member]

Business Acquisition [Line Items]

Borrowings

[10]

$ 350,000

Cash on hand

[10]

$ 6,250

Common units issued | shares

314,786

General partner units issued | shares

6,296

Texas Express and Front Range [Member] | Common Units [Member]

Business Acquisition [Line Items]

Common units issued | shares

308,490

[10]

308,490

Texas Express and Front Range [Member] | General Partner [Member]

Business Acquisition [Line Items]

Common units issued | shares

6,296

Proceeds from the issuance of units

$ 400

Texas Express Pipeline LLC [Member]

Business Acquisition [Line Items]

Equity investment ownership

20.00%

Texas Express Gathering LLC [Member]

Business Acquisition [Line Items]

Equity investment ownership

20.00%

Front Range Pipeline LLC [Member]

Business Acquisition [Line Items]

Equity investment ownership

33.33%

Delaware Basin Midstream LLC [Member]

Business Acquisition [Line Items]

Percentage acquired

[11]

100.00%

Borrowings

[11]

$ 475,000

Cash on hand

[11]

$ 298,327

Delaware Basin Midstream LLC [Member] | Level 3 Inputs [Member]

Business Acquisition [Line Items]

Purchase price adjustment

$ 1,557,473

Delaware Basin Midstream LLC [Member] | Class C Units [Member]

Business Acquisition [Line Items]

Units issued | shares

[11]

10,913,853

Delaware Basin JV Gathering LLC [Member]

Business Acquisition [Line Items]

Percentage acquired

50.00%

[12]

50.00%

Delaware Basin JV Gathering LLC [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | Affiliates [Member] | Level 3 Inputs [Member]

Business Acquisition [Line Items]

Deferred purchase price obligation to Anadarko - acquisition date value

[12]

$ 174,276

Deferred purchase price obligation to Anadarko - future value

$ 282,800

[1]

Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

[2]

Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.

[3]

Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.

[4]

Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million.

[5]

Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option.

[6]

The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million.

[7]

The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a $1.1 million decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation.

[8]

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

[9]

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

[10]

The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million.

[11]

The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price.

[12]

The Partnership acquired Anadarko’s interest in Delaware Basin JV Gathering LLC (“DBJV”), which owns a 50% interest in a gathering system and related facilities (the “DBJV system”). The DBJV system is located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. The Partnership currently estimates the future payment will be $282.8 million, the net present value of which was $174.3 million as of the acquisition date. See DBJV acquisition—Deferred purchase price obligation - Anadarko below.

Acquisitions and Divestitures41

Acquisitions and Divestitures - Impact to Historical Consolidated Statements of Income Table (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenues and other		$ 1,561,372	$ 1,382,868	[1]	$ 1,085,482	[1]
Equity income, net	[2],[3],[4]	71,251	57,836	[1]	22,948	[1]
Net income (loss)		$ (63,437)	407,867	[1]	289,539	[1]
Delaware Basin JV Gathering LLC [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenues and other			62,112		32,545
Equity income, net			0		0
Net income (loss)			17,309		4,096
Partnership Historical [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenues and other	[5]		1,320,756		1,052,937
Equity income, net	[5]		57,836		22,948
Net income (loss)	[5]		$ 390,558		$ 285,443
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Income earned from equity investments is classified as affiliate. See Note 1.
[3]	Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.
[4]	Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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.
[5]	See Adjustments to previously issued financial statements in Note 1.

Acquisitions and Divestitures42

Acquisitions and Divestitures - Purchase Price Allocation Table (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	[1]
Business Acquisition [Line Items]
Goodwill	$ 389,686	$ 389,087
Delaware Basin Midstream LLC [Member] | Level 3 Inputs [Member]
Business Acquisition [Line Items]
Current assets	60,888
Property, plant and equipment	467,171
Goodwill	284,749
Other intangible assets	811,048
Accounts payables	(18,621)
Accrued liabilities	(37,360)
Deferred income taxes	(1,342)
Asset retirement obligations and other	(9,060)
Total purchase price	$ 1,557,473
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Acquisitions and Divestitures43

Acquisitions and Divestitures - Pro Forma Condensed Financial Information Table (Details) - Delaware Basin Midstream LLC [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues and other	$ 1,506,135	$ 1,162,749
Net income (loss)	349,729	243,478
Net income (loss) attributable to Western Gas Partners, LP	$ 335,704	$ 232,622
Net income (loss) per common unit - basic and diluted	$ 1.34	$ 1.12

Acquisitions and Divestitures44

Acquisitions and Divestitures - Additional Information (Details) - USD ($) $ in Thousands

Mar. 02, 2015

Nov. 25, 2014

Aug. 31, 2012

Jul. 31, 2009

Dec. 31, 2008

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Sep. 30, 2010

Property, Plant and Equipment [Line Items]

Deferred purchase price obligation - Anadarko

[1]

$ 188,674

$ 0

[2]

Revenues and other

1,561,372

1,382,868

[3]

$ 1,085,482

[3]

Operating expenses

1,652,109

962,176

[3]

781,171

[3]

Goodwill

389,686

389,087

[2]

Dew and Pinnacle Systems [Member]

Property, Plant and Equipment [Line Items]

Proceeds from the sale of assets

145,600

Gain on divestiture and other, net

77,300

Goodwill

5,100

Affiliates [Member]

Property, Plant and Equipment [Line Items]

Revenues and other

[4]

1,029,922

1,053,935

[3]

844,203

[3]

Operating expenses

265,231

219,182

221,224

Proceeds from the sale of assets

925

0

[3]

85

[3]

Deferred Purchase Price Obligation - Anadarko [Member] | Affiliates [Member]

Property, Plant and Equipment [Line Items]

Interest expense, related party

[5]

$ 14,398

0

0

Newcastle [Member]

Property, Plant and Equipment [Line Items]

Percentage acquired

50.00%

50.00%

Fort Union [Member]

Property, Plant and Equipment [Line Items]

Equity investment ownership

14.81%

Chipeta Processing Limited Liability Company [Member]

Property, Plant and Equipment [Line Items]

Percentage acquired

24.00%

51.00%

75.00%

White Cliffs [Member]

Property, Plant and Equipment [Line Items]

Equity investment ownership

10.00%

Delaware Basin JV Gathering LLC [Member]

Property, Plant and Equipment [Line Items]

Percentage acquired

50.00%

[6]

50.00%

Revenues and other

62,112

32,545

Delaware Basin JV Gathering LLC [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | Affiliates [Member]

Property, Plant and Equipment [Line Items]

Discount rate percentage

10.00%

Deferred purchase price obligation - Anadarko

$ 188,700

Interest expense, related party

14,400

0

$ 0

Delaware Basin JV Gathering LLC [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | Level 3 Inputs [Member] | Affiliates [Member]

Property, Plant and Equipment [Line Items]

Deferred purchase price obligation to Anadarko - future value

$ 282,800

Deferred purchase price obligation to Anadarko - acquisition date value

[6]

$ 174,276

Delaware Basin Midstream LLC [Member]

Property, Plant and Equipment [Line Items]

Percentage acquired

[7]

100.00%

Post-closing purchase price adjustments

3,500

Revenues and other

12,500

Operating expenses

$ 10,400

Delaware Basin Midstream LLC [Member] | Level 3 Inputs [Member]

Property, Plant and Equipment [Line Items]

Goodwill

$ 284,749

[1]

See Note 2.

[2]

Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

[3]

Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

[4]

Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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.

[5]

See Note 2 for a discussion of the accretion and net present value of the Deferred purchase price obligation - Anadarko.

[6]

The Partnership acquired Anadarko’s interest in Delaware Basin JV Gathering LLC (“DBJV”), which owns a 50% interest in a gathering system and related facilities (the “DBJV system”). The DBJV system is located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. The Partnership currently estimates the future payment will be $282.8 million, the net present value of which was $174.3 million as of the acquisition date. See DBJV acquisition—Deferred purchase price obligation - Anadarko below.

[7]

The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price.

Partnership Distributions - Cas

Partnership Distributions - Cash Distributions Table (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Dec. 31, 2015	[1]	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013
Distributions Made to Members or Limited Partners [Abstract]
Total quarterly distribution per unit	$ 0.800		$ 0.775	$ 0.750	$ 0.725	$ 0.700	$ 0.675	$ 0.650	$ 0.625	$ 0.600	$ 0.580	$ 0.560	$ 0.540
Total quarterly cash distribution	$ 152,588		$ 146,160	$ 139,736	$ 133,203	$ 126,044	$ 111,608	$ 105,655	$ 98,749	$ 92,609	$ 83,986	$ 79,315	$ 70,143
[1]	On January 21, 2016, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.800 per unit, or $152.6 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution was paid on February 11, 2016, to unitholders of record at the close of business on February 1, 2016.

Partnership Distributions - PIK

Partnership Distributions - PIK Class C Units Distributions Table (Details) - Class C Units [Member] - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
PIK Class C units	323,584	181,048	153,020	118,230	45,711	[1]
Implied fair value	$ 10,070	$ 9,724	$ 8,721	$ 8,101	$ 3,072	[1]
Number of days in prorated period					37 days
[1]	Prorated for the 37-day period the Class C units were outstanding during the fourth quarter of 2014.

Partnership Distributions - Add

Partnership Distributions - Additional Information (Details)	12 Months Ended
	Dec. 31, 2015
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	1.80%
Maximum [Member]
Distribution Made to Limited Partner [Line Items]
Distribution sharing percentage	49.80%
Class C Units [Member]
Distribution Made to Limited Partner [Line Items]
Discount rate percentage	6.00%

Equity and Partners' Capital -

Equity and Partners' Capital - Equity Offerings Table (Details) - USD ($) $ / shares in Units, $ in Thousands

Jan. 03, 2014

Nov. 30, 2014

Dec. 31, 2013

May. 31, 2013

Dec. 31, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Aug. 31, 2014

Aug. 31, 2012

Capital Unit [Line Items]

Units issued

498,009

10,913,853

Price per unit

$ 70.85

[1]

$ 61.51

[2]

$ 61.18

[3]

$ 61.51

[2]

Underwriting discount and other offering expenses

$ 18,615

[1]

$ 9,447

[2]

$ 13,203

[3]

$ 9,447

[2]

Net proceeds

$ 602,967

[1]

291,827

[2]

$ 424,733

[3]

General partner's interest

2.00%

Option on Securities [Member]

Capital Unit [Line Items]

Net proceeds

$ 18,100

$ 77,000

125 Million COP [Member]

Capital Unit [Line Items]

Average price per unit

$ 73.48

[4]

$ 60.84

[5]

Underwriting discount and other offering expenses

$ 965

[5]

$ 1,738

[4]

$ 965

[5]

Net proceeds

83,245

[4]

41,603

[5]

Maximum aggregate principal of common units

$ 125,000

Gross proceeds

$ 85,000

$ 42,600

500 Million COP [Member]

Capital Unit [Line Items]

Common units issued

873,525

Average price per unit

[6]

$ 66.61

Underwriting discount and other offering expenses

[6]

$ 805

$ 805

Net proceeds

[6]

57,385

Maximum aggregate principal of common units

$ 500,000

Gross proceeds

0

58,200

Commissions paid

$ 0

$ 600

Common Units [Member]

Capital Unit [Line Items]

Common units issued

8,620,153

[1]

4,800,000

[2]

7,015,000

[3]

Common Units [Member] | Option on Securities [Member]

Capital Unit [Line Items]

Common units issued

300,000

1,120,153

915,000

Common Units [Member] | 125 Million COP [Member]

Capital Unit [Line Items]

Common units issued

1,133,384

[4]

685,735

[5]

Common Units [Member] | 500 Million COP [Member]

Capital Unit [Line Items]

Common units issued

[6]

873,525

General Partner [Member]

Capital Unit [Line Items]

Units issued

[7]

153,061

[1]

97,959

[2]

143,163

[3]

General Partner [Member] | 125 Million COP [Member]

Capital Unit [Line Items]

Units issued

[7]

23,132

[4]

13,996

[5]

[1]

Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.

[2]

Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million.

[3]

Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option.

[4]

Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.

[5]

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

[6]

Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million, respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015.

[7]

Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.

Equity and Partners' Capital 49

Equity and Partners' Capital - Limited Partner and General Partner Units Table (Details) - shares

Mar. 03, 2014

[4]

Nov. 30, 2014

[1]

Dec. 31, 2013

May. 31, 2013

[3]

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Capital Unit [Line Items]

Balance

141,192,051

119,717,157

Units issued

498,009

10,913,853

WES LTIP award vestings

8,310

10,403

Balance

119,717,157

142,571,895

141,192,051

119,717,157

Texas Express and Front Range [Member]

Capital Unit [Line Items]

Acquisition

314,786

December 2013 Equity Offering [Member]

Capital Unit [Line Items]

Total units

306,122

125 Million COP [Member]

Capital Unit [Line Items]

Total units

1,156,516

November 2014 Equity Offering [Member]

Capital Unit [Line Items]

Total units

8,773,214

500 Million COP [Member]

Capital Unit [Line Items]

Offering

873,525

Common Units [Member]

Capital Unit [Line Items]

Balance

127,695,130

117,322,812

Offering

8,620,153

4,800,000

[2]

7,015,000

WES LTIP award vestings

8,310

10,291

Balance

117,322,812

128,576,965

127,695,130

117,322,812

Common Units [Member] | Texas Express and Front Range [Member]

Capital Unit [Line Items]

Acquisition

308,490

308,490

Common Units [Member] | December 2013 Equity Offering [Member]

Capital Unit [Line Items]

Offering

300,000

Common Units [Member] | 125 Million COP [Member]

Capital Unit [Line Items]

Offering

1,133,384

[5]

685,735

[6]

Common Units [Member] | November 2014 Equity Offering [Member]

Capital Unit [Line Items]

Offering

8,620,153

Common Units [Member] | 500 Million COP [Member]

Capital Unit [Line Items]

Offering

[7]

873,525

Class C Units [Member]

Capital Unit [Line Items]

Balance

10,913,853

0

Units issued

498,009

10,913,853

Balance

0

11,411,862

10,913,853

0

General Partner [Member]

Capital Unit [Line Items]

Balance

2,583,068

2,394,345

Units issued

[8]

153,061

97,959

[2]

143,163

WES LTIP award vestings

112

Balance

2,394,345

2,583,068

2,583,068

2,394,345

General Partner [Member] | Texas Express and Front Range [Member]

Capital Unit [Line Items]

Acquisition

6,296

General Partner [Member] | December 2013 Equity Offering [Member]

Capital Unit [Line Items]

Units issued

6,122

General Partner [Member] | 125 Million COP [Member]

Capital Unit [Line Items]

Units issued

[8]

23,132

[5]

13,996

[6]

General Partner [Member] | November 2014 Equity Offering [Member]

Capital Unit [Line Items]

Units issued

153,061

[1]

Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.

[2]

Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million.

[3]

Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option.

[4]

The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million.

[5]

Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.

[6]

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

[7]

Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million, respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015.

[8]

Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.

Equity and Partners' Capital 50

Equity and Partners' Capital - Calculation of Net Income (Loss) Per Unit Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Earnings Per Unit [Line Items]
Net income (loss) attributable to Western Gas Partners, LP		$ (73,538)	$ 393,842	[1]	$ 278,723	[1]
Pre-acquisition net (income) loss allocated to Anadarko		(1,742)	(16,353)	[1]	(8,224)	[1]
General partner interest in net (income) loss	[2]	(180,996)	(120,980)	[1]	(69,633)	[1]
Limited partners' interest in net income (loss)	[2]	$ (256,276)	$ 256,509	[1]	$ 200,866	[1]
Net income (loss) per common unit - basic	[3]	$ (1.95)	$ 2.13	[1]	$ 1.83	[1]
Net income (loss) per common unit - diluted	[3],[4]	$ (1.95)	$ 2.12	[1]	$ 1.83	[1]
Weighted-average units outstanding - diluted		139,459	120,928		109,872
Common Units [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income (loss)	[5]	$ (250,210)	$ 254,737		$ 200,866
Weighted-average units outstanding - basic		128,345	119,822		109,872
Class C Units [Member]
Earnings Per Unit [Line Items]
Limited partners' interest in net income (loss)	[5]	$ (6,066)	$ 1,772		$ 0
Weighted-average units outstanding - basic	[4]	11,114	1,106		0
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 4.
[3]	See Note 4 for the calculation of net income (loss) per common unit.
[4]	Inclusion of Class C units in the calculation for the year ended December 31, 2015, would have had an anti-dilutive effect.
[5]	Adjusted to reflect amortization for the beneficial conversion feature. See Class C units above for a discussion of the Class C units.

Equity and Partners' Capital 51

Equity and Partners' Capital - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	Nov. 30, 2014		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013		May. 31, 2013	[3]
Schedule Of Investments [Line Items]
Units issued			498,009	10,913,853
Price per unit	$ 70.85	[1]				$ 61.51	[2]	$ 61.18
Beneficial conversion feature of Class C units				$ 0
General partner units owned			2,583,068	2,583,068
General partner's interest	2.00%
Western Gas Equity Partners, LP [Member]
Schedule Of Investments [Line Items]
General partner units owned			2,583,068
General partner's interest			1.80%
Other Subsidiaries Of Anadarko [Member]
Schedule Of Investments [Line Items]
Limited partner ownership interest			8.50%
Class C Units [Member]
Schedule Of Investments [Line Items]
Units issued			498,009	10,913,853
Price per unit	$ 68.72
Proceeds from the issuance of Class C units	$ 750,000		$ 0	$ 750,000	[4]	$ 0	[4]
Beneficial conversion feature of Class C units				$ 34,800
Limited partner units owned			11,411,862	10,913,853
Class C Units [Member] | Other Subsidiaries Of Anadarko [Member]
Schedule Of Investments [Line Items]
Units issued	10,913,853
Limited partner units owned			11,411,862
Class C Units [Member] | Maximum [Member]
Schedule Of Investments [Line Items]
Redeemable option on units	$ 150,000
Common Units [Member]
Schedule Of Investments [Line Items]
Limited partner units owned			128,576,965	127,695,130
Common Units [Member] | Western Gas Equity Partners, LP [Member]
Schedule Of Investments [Line Items]
Limited partner units owned			49,296,205
Limited partner ownership interest			34.60%
Common Units [Member] | Other Subsidiaries Of Anadarko [Member]
Schedule Of Investments [Line Items]
Limited partner units owned			757,619
Common Units [Member] | Public [Member]
Schedule Of Investments [Line Items]
Limited partner units owned			78,523,141
Limited partner ownership interest			55.10%
Incentive Distribution Rights [Member] | Western Gas Equity Partners, LP [Member]
Schedule Of Investments [Line Items]
General partner's interest			100.00%
[1]	Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.
[2]	Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million.
[3]	Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option.
[4]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Transactions with Affiliates -

Transactions with Affiliates - Commodity Price Swap Agreements Table (Details) - Year 2016 [Member]	Dec. 31, 2015$ / bbl$ / MMBTU
Ethane [Member] | Minimum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	18.41
Ethane [Member] | Maximum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	23.11
Propane [Member] | Minimum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	47.08
Propane [Member] | Maximum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	52.90
Isobutane [Member] | Minimum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	62.09
Isobutane [Member] | Maximum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	73.89
Normal butane [Member] | Minimum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	54.62
Normal butane [Member] | Maximum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	64.93
Natural gasoline [Member] | Minimum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	72.88
Natural gasoline [Member] | Maximum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	81.68
Condensate [Member] | Minimum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	76.47
Condensate [Member] | Maximum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	81.68
Natural gas (per MMBtu) [Member] | Minimum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU	4.87
Natural gas (per MMBtu) [Member] | Maximum [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU	5.96

Transactions with Affiliates 53

Transactions with Affiliates - Gains (Losses) on Commodity Price Swap Agreements Table (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gains (losses) on commodity price swap agreements related to sales and purchases
Gains (losses) on commodity price swap agreements		$ 66,292	$ 54,868	$ 38,164
Sales [Member]
Gains (losses) on commodity price swap agreements related to sales and purchases
Gains (losses) on commodity price swap agreements	[1]	191,236	123,360	123,458
Sales [Member] | Natural Gas [Member]
Gains (losses) on commodity price swap agreements related to sales and purchases
Gains (losses) on commodity price swap agreements	[1]	45,978	9,494	21,382
Sales [Member] | Natural Gas Liquids [Member]
Gains (losses) on commodity price swap agreements related to sales and purchases
Gains (losses) on commodity price swap agreements	[1]	145,258	113,866	102,076
Purchases [Member]
Gains (losses) on commodity price swap agreements related to sales and purchases
Gains (losses) on commodity price swap agreements	[2]	$ (124,944)	$ (68,492)	$ (85,294)
[1]	Reported in affiliate natural gas, natural gas liquids and drip condensate sales in the consolidated statements of income in the period in which the related sale is recorded.
[2]	Reported in cost of product in the consolidated statements of income in the period in which the related purchase is recorded.

Transactions with Affiliates 54

Transactions with Affiliates - Commodity Price Swap Agreements Extensions Tables (Details)	Dec. 08, 2015$ / bbl$ / MMBTU		Jun. 25, 2015$ / bbl$ / MMBTU
DJ Basin Complex [Member] | Ethane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	0.60	[1]	1.96	[2]
DJ Basin Complex [Member] | Ethane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price			18.41
DJ Basin Complex [Member] | Ethane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	18.41
DJ Basin Complex [Member] | Propane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	10.98	[1]	13.10	[2]
DJ Basin Complex [Member] | Propane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price			47.08
DJ Basin Complex [Member] | Propane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	47.08
DJ Basin Complex [Member] | Isobutane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	17.23	[1]	19.75	[2]
DJ Basin Complex [Member] | Isobutane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price			62.09
DJ Basin Complex [Member] | Isobutane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	62.09
DJ Basin Complex [Member] | Normal butane [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	16.86	[1]	18.99	[2]
DJ Basin Complex [Member] | Normal butane [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price			54.62
DJ Basin Complex [Member] | Normal butane [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	54.62
DJ Basin Complex [Member] | Natural gasoline [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	26.15	[1]	52.59	[2]
DJ Basin Complex [Member] | Natural gasoline [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price			72.88
DJ Basin Complex [Member] | Natural gasoline [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	72.88
DJ Basin Complex [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	34.65	[1]	52.59	[2]
DJ Basin Complex [Member] | Condensate [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price			76.47
DJ Basin Complex [Member] | Condensate [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	76.47
DJ Basin Complex [Member] | Natural gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price | $ / MMBTU	2.11	[1]	2.75	[2]
DJ Basin Complex [Member] | Natural gas (per MMBtu) [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU			5.96
DJ Basin Complex [Member] | Natural gas (per MMBtu) [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU	5.96
Hugoton System [Member] | Condensate [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price	18.81	[1]	32.56	[2]
Hugoton System [Member] | Condensate [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price			78.61
Hugoton System [Member] | Condensate [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price	78.61
Hugoton System [Member] | Natural gas (per MMBtu) [Member]
Commodity Price Risk Swap [Line Items]
Commodity market price | $ / MMBTU	2.12	[1]	2.74	[2]
Hugoton System [Member] | Natural gas (per MMBtu) [Member] | Year 2015 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU			5.50
Hugoton System [Member] | Natural gas (per MMBtu) [Member] | Year 2016 [Member]
Commodity Price Risk Swap [Line Items]
Commodity swap fixed price | $ / MMBTU	5.50
[1]	Represents the NYMEX forward strip price as of December 8, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.
[2]	Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of June 25, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

Transactions with Affiliates 55

Transactions with Affiliates - Omnibus Agreement Table (Details) - Omnibus Agreement [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Allocated costs from Anadarko	$ 31,846	$ 28,255	$ 24,034
General and Administrative Expenses [Member]
Related Party Transaction [Line Items]
Allocated costs from Anadarko	22,896	20,249	16,882
Public Company Expenses [Member]
Related Party Transaction [Line Items]
Allocated costs from Anadarko	$ 8,950	$ 8,006	$ 7,152

Transactions with Affiliates 56

Transactions with Affiliates - LTIP Award Activity Table (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract]
Value per unit of phantom units outstanding at beginning of year	$ 60.74	$ 49.47	$ 41.77
Value per unit of phantom units vested during the period	60.69	49.55	41.28
Value per unit of phantom units granted during the period	69.10	68.14	62.49
Value per unit of phantom units outstanding at end of year	$ 68.78	$ 60.74	$ 49.47
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Phantom units outstanding at beginning of year	9,522	16,844	25,619
Phantom units vested	(9,257)	(13,122)	(14,695)
Phantom units granted	5,212	5,800	5,920
Phantom units outstanding at end of year	5,477	9,522	16,844

Transactions with Affiliates 57

Transactions with Affiliates - Equipment Purchases and Sales Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Related Party Transaction [Line Items]
Partners’ capital adjustment	$ 4,767	$ 10,733	[1]	$ 5,855	[1]
Affiliates [Member] | Purchases [Member]
Related Party Transaction [Line Items]
Cash consideration - purchases	12,664	22,943		11,211
Net carrying value	7,944	12,210		5,309
Partners’ capital adjustment	4,720	10,733		5,902
Affiliates [Member] | Sales [Member]
Related Party Transaction [Line Items]
Cash consideration - sales	925	0		85
Net carrying value	972	0		38
Partners’ capital adjustment	$ 47	$ 0		$ (47)
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Transactions with Affiliates 58

Transactions with Affiliates - Summary of Affiliate Transactions Table (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Related Party Transaction [Line Items]
Revenues and other		$ 1,561,372	$ 1,382,868	[1]	$ 1,085,482	[1]
Equity income, net	[2],[3],[4]	71,251	57,836	[1]	22,948	[1]
Cost of product	[5]	528,435	454,445	[1]	373,171	[1]
Operation and maintenance	[5]	296,774	255,844	[1]	201,759	[1]
General and administrative	[5]	38,108	36,223	[1]	31,353	[1]
Operating expenses		1,652,109	962,176	[1]	781,171	[1]
Interest income	[6]	16,900	16,900	[1]	16,900	[1]
Interest expense	[7]	113,872	76,766	[1]	51,797	[1]
Distributions to unitholders	[8]	545,143	408,621	[1]	299,101	[1]
Above-market component of swap extensions with Anadarko	[8]	18,449	0	[1]	0	[1]
Affiliates [Member]
Related Party Transaction [Line Items]
Revenues and other	[4]	1,029,922	1,053,935	[1]	844,203	[1]
Cost of product	[4]	167,420	127,906		136,570
Operation and maintenance	[9]	67,119	62,306		59,698
General and administrative	[10]	30,692	28,970		24,956
Operating expenses		265,231	219,182		221,224
Interest expense	[11]	14,398	0		0
Distributions to unitholders	[12]	$ 314,200	$ 234,024		$ 169,150
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Income earned from equity investments is classified as affiliate. See Note 1.
[3]	Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.
[4]	Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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.
[5]	Cost of product includes product purchases from Anadarko (as defined in Note 1) of $167.4 million, $127.9 million and $136.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Operation and maintenance includes charges from Anadarko of $67.1 million, $62.3 million and $59.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. General and administrative includes charges from Anadarko of $30.7 million, $29.0 million and $25.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 5.
[6]	Represents interest income recognized on the note receivable from Anadarko.
[7]	Includes affiliate (as defined in Note 1) interest expense of $14.4 million for the year ended December 31, 2015, and zero for each of the years ended December 31, 2014 and 2013. See Note 2 and Note 12.
[8]	See Note 5.
[9]	Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
[10]	Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).
[11]	For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 12).
[12]	Represents distributions paid under the partnership agreement (see Note 3 and Note 4).

Transactions with Affiliates 59

Transactions with Affiliates - Additional Information (Details) - USD ($)		1 Months Ended	12 Months Ended
		May. 31, 2008	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Related Party Transaction [Line Items]
Note receivable - Anadarko			$ 260,000,000	$ 260,000,000	[1]
Above-market component of swap extensions with Anadarko	[2]		18,449,000
Contributions of equity-based compensation from Anadarko	[3]		$ 3,551,000	3,167,000		$ 2,923,000
Western Gas Partners Long Term Incentive Plan [Member]
Related Party Transaction [Line Items]
Units vesting period			3 years
Equity-based compensation expense			$ 500,000	600,000		600,000
Weighted-average term of unvested awards			4 months 13 days
Western Gas Equity Partners Long Term Incentive Plan [Member] | Anadarko Incentive Plans [Member]
Related Party Transaction [Line Items]
Equity-based compensation expense			$ 3,900,000	3,500,000		3,000,000
Unvested equity-based compensation expense			$ 7,300,000
Weighted-average term of unvested awards			2 years 7 days
Contributions of equity-based compensation from Anadarko			$ 3,600,000	$ 3,200,000		$ 2,900,000
Gathering, Treating and Transportation [Member]
Related Party Transaction [Line Items]
Affiliate throughput percent			43.00%	49.00%		54.00%
Processing [Member]
Related Party Transaction [Line Items]
Affiliate throughput percent			51.00%	57.00%		59.00%
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] | Level 2 Inputs [Member] | Market Approach Valuation Technique [Member]
Related Party Transaction [Line Items]
Fair value of the note receivable			$ 252,300,000	$ 317,800,000
Independent Director [Member] | Western Gas Partners Long Term Incentive Plan [Member]
Related Party Transaction [Line Items]
Units vesting period			1 year
Anadarko [Member] | Western Gas Partners Long Term Incentive Plan [Member]
Related Party Transaction [Line Items]
Unvested equity-based compensation expense			$ 100,000
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	See Note 5.
[3]	Associated with the Anadarko Incentive Plans as defined and described in Note 1 and Note 5.

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Current income tax expense (benefit)
Federal income tax expense (benefit)	$ 590	$ (1,729)		$ (35,872)
State income tax expense (benefit)	858	63		497
Total current income tax expense (benefit)	1,448	(1,666)		(35,375)
Deferred income tax expense (benefit)
Federal income tax expense (benefit)	348	10,612		40,846
State income tax expense (benefit)	1,584	2,713		(811)
Total deferred income tax expense (benefit)	1,932	13,325	[1]	40,035	[1]
Total income tax expense (benefit)	$ 3,380	$ 11,659	[1]	$ 4,660	[1]
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Income Taxes - Tax Rate Reconci

Income Taxes - Tax Rate Reconciliation Table (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Related Party Transaction [Line Items]
Income (loss) before income taxes		$ (60,057)	$ 419,526	[1]	$ 294,199	[1]
Statutory tax rate		0.00%	0.00%		0.00%
Adjustments resulting from:
Federal taxes on income		$ 0	$ 0		$ 0
State taxes on income (net of federal benefit) and Texas margin tax expense (benefit)	[2]	2,411	2,481		(1,359)
Income tax expense (benefit)		$ 3,380	$ 11,659	[1]	$ 4,660	[1]
Effective tax rate		(6.00%)	3.00%		2.00%
Change in deferred state income taxes		$ 2,200
Change in Texas margin tax rates		0.25%
Pre Acquisition From Parent [Member]
Adjustments resulting from:
Federal taxes on income		$ 942	$ 8,988		$ 5,390
State taxes on income (net of federal benefit) and Texas margin tax expense (benefit)		$ 27	$ 190		$ 629
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Includes a reduction of $2.2 million in deferred state income taxes. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25%. The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted.

Income Taxes - Income Tax Tempo

Income Taxes - Income Tax Temporary Differences Table (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Depreciable property	$ (4,418)	$ (44,725)
Credit carryforwards	512	526
Other intangible assets	(2,070)	(1,450)
Other	13	7
Net long-term deferred income tax liabilities	$ (5,963)	$ (45,642)	[1]
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Credit carryforwards	$ 512	$ 526
Tax credit carryforward, expiration date	Dec. 31, 2026

Property, Plant and Equipment -

Property, Plant and Equipment - Historical Cost Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 5,904,637	$ 5,626,650	[1]
Accumulated depreciation	1,614,663	1,055,207	[1]
Net property, plant and equipment	4,289,974	4,571,443	[1]
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	3,191	2,884
Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 5,420,762	4,972,892
Gathering Systems [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Gathering Systems [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	$ 136,290	151,107
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	$ 324,720	483,347
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 19,674	$ 16,420
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
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Property, Plant and Equipment65

Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Impairments	$ 514,096	$ 3,084	[1]	$ 1,267	[1]
Unguaranteed residual value				$ 4,600
Property, plant and equipment	5,904,637	5,626,650	[2]
Delaware Basin Midstream Complex [Member]
Property, Plant and Equipment [Line Items]
Loss on property from damages	68,800
Red Desert Complex [Member]
Property, Plant and Equipment [Line Items]
Impairments	280,200
Red Desert Complex [Member] | Fair Value Measurements Nonrecurring [Member] | Level 3 Inputs [Member] | Income Approach Valuation Technique [Member]
Property, Plant and Equipment [Line Items]
Estimated salvage value	6,300
Hilight System [Member]
Property, Plant and Equipment [Line Items]
Impairments	220,900
Hilight System [Member] | Fair Value Measurements Nonrecurring [Member] | Level 3 Inputs [Member] | Income Approach Valuation Technique [Member]
Property, Plant and Equipment [Line Items]
Estimated fair value	28,800
Other [Member]
Property, Plant and Equipment [Line Items]
Impairments	13,000
Property, plant and equipment	$ 19,674	16,420
Natural Gas Processing Plant [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		4,600
Equipment [Member] | Fair Value Measurements Nonrecurring [Member] | Level 3 Inputs [Member] | Income Approach Valuation Technique [Member]
Property, Plant and Equipment [Line Items]
Estimated salvage value		$ 2,400
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Goodwill and Intangibles - Othe

Goodwill and Intangibles - Other Intangible Assets Table (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Gross carrying amount	$ 868,035	$ 892,555
Accumulated amortization	(35,908)	(7,698)
Other intangible assets	$ 832,127	$ 884,857	[1]
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Goodwill and Intangibles - Addi

Goodwill and Intangibles - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Amortization expense for intangible assets	$ 28.2	$ 4.3	$ 1.4
Estimated amortization expense for intangible assets in 2016	28.4
Estimated amortization expense for intangible assets in 2017	28.4
Estimated amortization expense for intangible assets in 2018	28.4
Estimated amortization expense for intangible assets in 2019	28.4
Estimated amortization expense for intangible assets in 2020	$ 28.4
Platte Valley [Member]
Finite-Lived Intangible Assets [Line Items]
Straight-line basis of amortization	50 years
Chipeta Processing Limited Liability Company [Member]
Finite-Lived Intangible Assets [Line Items]
Straight-line basis of amortization	10 years
Delaware Basin Midstream LLC [Member]
Finite-Lived Intangible Assets [Line Items]
Straight-line basis of amortization	30 years

Equity Investments - Equity Inv

Equity Investments - Equity Investments Table (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)unit		Dec. 31, 2014USD ($)		Dec. 31, 2013USD ($)
Schedule of Equity Method Investments [Line Items]
Balance		$ 634,492	[1]	$ 593,400
Investment earnings (loss), net of amortization	[2],[3],[4]	71,251		57,836	[5]	$ 22,948	[5]
Contributions		11,442		64,278	[5]	294,693	[5]
Capitalized interest				857
Distributions	[3]	(82,054)		(62,967)	[5]	(17,698)	[5]
Distributions in excess of cumulative earnings	[3]	(16,244)	[6]	(18,055)	[5],[6]	(4,438)	[5]
Balance		618,887		634,492	[1]	593,400
Equity Investments [Member]
Schedule of Equity Method Investments [Line Items]
Contributions		11,442		63,421
Fort Union [Member]
Schedule of Equity Method Investments [Line Items]
Balance	[7]	25,933		25,172
Investment earnings (loss), net of amortization	[7]	(3,200)		6,344
Contributions	[7]	0		0
Capitalized interest	[7]			0
Distributions	[7]	(5,611)		(5,583)
Distributions in excess of cumulative earnings	[6],[7]	0		0
Balance	[7]	$ 17,122		25,933		25,172
Equity investment ownership		14.81%
Approval percentage		65.00%
White Cliffs [Member]
Schedule of Equity Method Investments [Line Items]
Balance	[8]	$ 44,315		35,039
Investment earnings (loss), net of amortization	[8]	14,770		11,912
Contributions	[8]	8,512		10,456
Capitalized interest	[8]			0
Distributions	[8]	(14,188)		(11,330)
Distributions in excess of cumulative earnings	[6],[8]	(2,970)		(1,762)
Balance	[8]	$ 50,439		44,315		35,039
Equity investment ownership		10.00%
Approval percentage		75.00%
Rendezvous [Member]
Schedule of Equity Method Investments [Line Items]
Balance	[9]	$ 56,336		60,928
Investment earnings (loss), net of amortization	[9]	2,292		1,729
Contributions	[9]	0		0
Capitalized interest	[9]			0
Distributions	[9]	(4,233)		(3,669)
Distributions in excess of cumulative earnings	[6],[9]	(3,482)		(2,652)
Balance	[9]	$ 50,913		56,336		60,928
Equity investment ownership		22.00%
Approval percentage		100.00%
Mont Belvieu JV [Member]
Schedule of Equity Method Investments [Line Items]
Balance	[10]	$ 121,337		122,480
Investment earnings (loss), net of amortization	[10]	23,570		29,029
Contributions	[10]	(432)		3,957
Capitalized interest	[10]			0
Distributions	[10]	(24,248)		(34,129)
Distributions in excess of cumulative earnings	[6],[10]	(3,138)		0
Balance	[10]	$ 117,089		121,337		122,480
Equity investment ownership		25.00%
Approval percentage		50.00%
Mont Belvieu JV [Member] | Fractionation Train [Member]
Schedule of Equity Method Investments [Line Items]
Assets, number of units | unit		2
Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Balance	[11]	$ 16,790		16,649
Investment earnings (loss), net of amortization	[11]	586		650
Contributions	[11]	0		352
Capitalized interest	[11]			0
Distributions	[11]	(803)		(523)
Distributions in excess of cumulative earnings	[6],[11]	(290)		(338)
Balance	[11]	$ 16,283		16,790		16,649
Equity investment ownership		20.00%
Approval percentage		50.00%
Texas Express Gathering LLC [Member] | Natural Gas Liquids Gathering System [Member]
Schedule of Equity Method Investments [Line Items]
Assets, number of units | unit		2
Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Balance	[12]	$ 198,793		197,731
Investment earnings (loss), net of amortization	[12]	16,088		6,108
Contributions	[12]	1,880		6,623
Capitalized interest	[12]			0
Distributions	[12]	(16,340)		(5,622)
Distributions in excess of cumulative earnings	[6],[12]	(5,618)		(6,047)
Balance	[12]	$ 194,803		198,793		197,731
Equity investment ownership		20.00%
Approval percentage		50.00%
Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Balance	[13]	$ 170,988		135,401
Investment earnings (loss), net of amortization	[13]	17,145		2,064
Contributions	[13]	1,482		42,033
Capitalized interest	[13]			857
Distributions	[13]	(16,631)		(2,111)
Distributions in excess of cumulative earnings	[6],[13]	(746)		(7,256)
Balance	[13]	$ 172,238		$ 170,988		$ 135,401
Equity investment ownership		33.33%
Approval percentage		50.00%
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Income earned from equity investments is classified as affiliate. See Note 1.
[3]	Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.
[4]	Represents amounts earned or incurred on and subsequent to the date of acquisition of the 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.
[5]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[6]	Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.
[7]	The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners.
[8]	The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.
[9]	The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.
[10]	The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.
[11]	The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.
[12]	The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.
[13]	The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.

Equity Investments - Summarized

Equity Investments - Summarized Combined Financial Data For Equity Investments - Income Statement Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$ 668,797	$ 548,629	$ 261,705
Operating income	381,616	336,188	171,496
Net income	$ 381,161	$ 333,705	$ 170,175

Equity Investments - Summariz70

Equity Investments - Summarized Combined Financial Data For Equity Investments - Balance Sheet Table (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$ 156,180	$ 141,781
Property, plant and equipment, net	2,736,553	2,814,336
Other assets	43,713	48,799
Total assets	2,936,446	3,004,916
Current liabilities	78,116	95,102
Non-current liabilities	9,072	22,615
Equity	2,849,258	2,887,199
Total liabilities and equity	$ 2,936,446	$ 3,004,916

Equity Investments - Additional

Equity Investments - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Fort Union [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment impairment loss	$ 9.5
Equity investment ownership	14.81%
Rendezvous [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment difference between carrying and underlying value	$ 40.1
Equity investment ownership	22.00%
White Cliffs [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment difference between carrying and underlying value	$ (8.1)
Equity investment ownership	10.00%
White Cliffs [Member] | Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment ownership	0.40%

Components of Working Capital

Components of Working Capital - Accounts Receivable, Net Table (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Receivables [Abstract]
Trade receivables, net		$ 131,221	$ 105,646
Other receivables, net		49,772	3,597
Total accounts receivable, net	[1]	$ 180,993	$ 109,243	[2]
[1]	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $42.7 million and $64.7 million as of December 31, 2015 and 2014, respectively. Accounts receivable, net as of December 31, 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Components of Working Capital -

Components of Working Capital - Other Current Assets Table (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Other Current Assets [Line Items]
Natural gas liquids inventory		$ 2,403	$ 5,316
Imbalance receivables		2,122	415
Prepaid insurance		2,296	2,443
Other		1,034	1,879
Total other current assets	[1]	$ 7,855	$ 10,053	[2]
[1]	Other current assets includes imbalance receivables from affiliates of zero and $0.2 million as of December 31, 2015 and 2014, respectively.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Components of Working Capital74

Components of Working Capital - Accrued Liabilities Table (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities [Line Items]
Accrued interest expense	$ 26,194	$ 24,741
Short-term asset retirement obligations	3,555	1,224
Short-term remediation and reclamation obligations	1,136	475
Income taxes payable	770	207
Total accrued liabilities	116,818	170,789	[1]
Accrued Capital Expenditures [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	60,702	128,856
Accrued Plant Purchases [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	16,425	14,023
Other Accrued Liabilities [Member]
Accrued Liabilities [Line Items]
Other accrued liabilities	$ 8,036	$ 1,263
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Asset Retirement Obligations -

Asset Retirement Obligations - Asset Retirement Obligations Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Carrying amount of asset retirement obligations at beginning of year	$ 110,735	$ 78,535
Liabilities incurred	9,121	13,982
Liabilities settled	(7,377)	(4,195)
Accretion expense	5,943	4,879
Revisions in estimated liabilities	2,105	17,534
Carrying amount of asset retirement obligations at end of year	$ 120,527	$ 110,735

Debt and Interest Expense - Deb

Debt and Interest Expense - Debt Outstanding Table (Details) - USD ($)		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Total long-term debt principal		$ 2,720,000,000	$ 2,430,000,000
Carrying value		2,707,357,000	2,422,954,000	[1]	$ 1,418,169,000
Market Approach Valuation Technique [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[2]	2,492,466,000	2,511,253,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Principal		300,000,000	510,000,000
Carrying value		300,000,000	510,000,000
Revolving Credit Facility [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[2]	300,000,000	510,000,000
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Principal		500,000,000	500,000,000
Carrying value		496,285,000	495,714,000
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[2]	513,645,000	549,530,000
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Principal		670,000,000	670,000,000
Carrying value		672,572,000	672,930,000
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[2]	595,744,000	681,942,000
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Principal		350,000,000	350,000,000
Carrying value		350,348,000	350,474,000
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[2]	339,293,000	352,162,000
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Principal		400,000,000	400,000,000
Carrying value		393,923,000	393,836,000
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[2]	321,499,000	417,619,000
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Principal		500,000,000	0
Carrying value		494,229,000	0
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member]
Debt Instrument [Line Items]
Fair value	[2]	$ 422,285,000	$ 0
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[2]	Fair value is measured using the market approach and Level 2 inputs.

Debt and Interest Expense - D77

Debt and Interest Expense - Debt Activity Table (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014
Debt Instrument [Line Items]
Beginning balance	$ 2,422,954	[1]	$ 1,418,169
Other	(5,597)		(5,215)
Ending balance	2,707,357		2,422,954	[1]
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Beginning balance	393,836
Issuance of Senior Notes			400,000
Ending balance	393,923		393,836
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Beginning balance	350,474
Issuance of Senior Notes			100,000
Ending balance	350,348		350,474
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Beginning balance	0
Issuance of Senior Notes	500,000
Ending balance	494,229		0
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Beginning balance	510,000
Borrowings	400,000		1,160,000
Repayments	(610,000)		(650,000)
Ending balance	$ 300,000		$ 510,000
[1]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.

Debt and Interest Expense - Int

Debt and Interest Expense - Interest Expense Table (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Interest expense	[1]	$ 113,872	$ 76,766	[2]	$ 51,797	[2]
Third Parties [Member]
Debt Instrument [Line Items]
Long-term debt		102,058	81,495		59,293
Amortization of debt issuance costs and commitment fees		5,734	5,103		4,449
Capitalized interest		(8,318)	(9,832)		(11,945)
Interest expense		99,474	76,766		51,797
Affiliates [Member]
Debt Instrument [Line Items]
Interest expense	[3]	14,398	0		0
Affiliates [Member] | Deferred Purchase Price Obligation - Anadarko [Member]
Debt Instrument [Line Items]
Interest expense, related party	[4]	$ 14,398	$ 0		$ 0
[1]	Includes affiliate (as defined in Note 1) interest expense of $14.4 million for the year ended December 31, 2015, and zero for each of the years ended December 31, 2014 and 2013. See Note 2 and Note 12.
[2]	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.
[3]	For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 12).
[4]	See Note 2 for a discussion of the accretion and net present value of the Deferred purchase price obligation - Anadarko.

Debt and Interest Expense - Add

Debt and Interest Expense - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2015	Mar. 31, 2014
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Facility, maximum borrowing capacity	$ 1,200,000,000
Facility, expandable maximum borrowing capacity	$ 1,500,000,000
Facility, interest rate at period end	1.73%	1.47%
Facility, fee rate	0.20%	0.20%
Facility, outstanding borrowings	$ 300,000,000
Outstanding letters of credit	6,400,000
Facility, available borrowing capacity	$ 893,600,000
Facility, expiration date	Feb. 26, 2019
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] | Minimum [Member]
Debt Instrument [Line Items]
Facility, fee rate	0.15%
Revolving Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added	0.975%
Revolving Credit Facility [Member] | Minimum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added	0.00%
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Facility, fee rate	0.30%
Revolving Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Applicable margin added	1.45%
Revolving Credit Facility [Member] | Maximum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable margin added	0.45%
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Fixed interest rate	5.375%
Debt instrument, maturity date	Jun. 1, 2021
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Fixed interest rate	4.00%
Debt instrument, maturity date	Jul. 1, 2022
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Fixed interest rate	2.60%
Offering percent				100.857%
Effective interest rate	2.743%
Underwriting discount		$ 600,000
Debt instrument, maturity date	Aug. 15, 2018
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Fixed interest rate	5.45%
Offering percent				98.443%
Effective interest rate	5.633%
Underwriting discount		$ 3,500,000
Debt instrument, maturity date	Apr. 1, 2044
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Fixed interest rate	3.95%
Offering percent			98.789%
Effective interest rate	4.205%
Underwriting discount	$ 3,300,000
Debt instrument, maturity date	Jun. 1, 2025

Commitments and Contingencies -

Commitments and Contingencies - Operating Lease Obligations Table (Details) $ in Thousands	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,016	$ 2,614
2,017	1,705
2,018	109
2,019	0
2,020	0
Thereafter	0
Total	$ 4,428

Commitments and Contingencies81

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Liability for remediation and reclamation obligations	$ 2.6	$ 2
Term of obligation	5 years
Committed capital	$ 45
Rent expense associated with office, warehouse and equipment leases	$ 18.9	$ 9.4	$ 7.6

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 24, 2016	Dec. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	[1]	Dec. 31, 2013	[2]	May. 31, 2013	[3]
Subsequent Event [Line Items]
Price per unit				$ 70.85		$ 61.51		$ 61.18
Units issued		498,009	10,913,853
Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Borrowings		$ 400,000	$ 1,160,000
Subsequent Event [Member] | Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Borrowings	$ 247,500
Subsequent Event [Member] | Convertible Preferred Units [Member]
Subsequent Event [Line Items]
Proceeds from the issuance of units	$ 449,000
Convertible preferred units, distribution rate percentage	8.50%
Price per unit	$ 32
Convertible preferred units, over-allotment period	30 days
Net proceeds from the issuance of units	$ 440,000
Convertible preferred units, distribution per unit	$ 2.72
Convertible preferred units, units issued upon conversion	1
Subsequent Event [Member] | Convertible Preferred Units [Member] | Option on Securities [Member]
Subsequent Event [Line Items]
Proceeds from the issuance of units	$ 252,600
Subsequent Event [Member] | Common Units [Member] | Anadarko [Member]
Subsequent Event [Line Items]
Price per unit	$ 29.91
Units issued	1,253,761
Subsequent Event [Member] | Common Units [Member] | Western Gas Equity Partners, LP [Member]
Subsequent Event [Line Items]
Price per unit	$ 29.91
Units issued	835,841
Subsequent Event [Member] | Springfield Pipeline LLC [Member]
Subsequent Event [Line Items]
Percentage acquired	100.00%
Acquisition price	$ 750,000
Subsequent Event [Member] | Springfield System [Member]
Subsequent Event [Line Items]
Percentage acquired	50.10%
[1]	Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.
[2]	Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million.
[3]	Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option.