Edgar Filing: Western Gas Partners LP

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Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2016


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

For the transition period from to

Commission file number: 001-34046

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)



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

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

(832) 636-6000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

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

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

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

There were 130,671,970 common units outstanding as of October 31, 2016.

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TABLE OF CONTENTS



			PAGE
PART I		FINANCIAL INFORMATION (UNAUDITED)
	Item 1.	Financial Statements
		Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015	6
		Consolidated Balance Sheets as of September 30, 2016, and December 31, 2015	7
		Consolidated Statement of Equity and Partners’ Capital for the nine months ended September 30, 2016	8
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	9
		Notes to Consolidated Financial Statements	10
		Note 1. Description of Business and Basis of Presentation	10
		Note 2. Acquisitions and Divestitures	14
		Note 3. Partnership Distributions	16
		Note 4. Equity and Partners’ Capital	17
		Note 5. Transactions with Affiliates	21
		Note 6. Property, Plant and Equipment	26
		Note 7. Equity Investments	26
		Note 8. Components of Working Capital	27
		Note 9. Debt and Interest Expense	28
		Note 10. Commitments and Contingencies	29
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
		Cautionary Note Regarding Forward-Looking Statements	30
		Executive Summary	32
		Acquisitions and Divestitures	33
		Equity Offerings	34
		Results of Operations	35
		Operating Results	35
		Key Performance Metrics	42
		Liquidity and Capital Resources	48
		Contractual Obligations	54
		Off-Balance Sheet Arrangements	54
		Recent Accounting Developments	54
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
	Item 4.	Controls and Procedures	56
PART II		OTHER INFORMATION
	Item 1.	Legal Proceedings	57
	Item 1A.	Risk Factors	57
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
	Item 6.	Exhibits	60

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COMMONLY USED TERMS AND DEFINITIONS

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

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

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

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

April 2016 Series A units: The 7,892,220 Series A Preferred units issued pursuant to the full exercise of the option granted in connection with the issuance of the March 2016 Series A units.

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

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

Chipeta: Chipeta Processing, LLC.

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

COP: Continuous offering programs.

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

DBJV: Delaware Basin JV Gathering LLC.

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

DBM: Delaware Basin Midstream, LLC.

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

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

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

Equity investment throughput: Our 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput, 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.

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

Fort Union: Fort Union Gas Gathering, LLC.

FRP: Front Range Pipeline LLC.

GAAP: Generally accepted accounting principles in the United States.

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General partner: Western Gas Holdings, LLC.

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

IPO: Initial public offering.

LIBOR: London Interbank Offered Rate.

March 2016 Series A units: The 14,030,611 Series A Preferred units issued in March 2016 in connection with the acquisition of Springfield.

MBbls/d: One thousand barrels per day.

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

MIGC: MIGC, LLC.

MLP: Master limited partnership.

MMBtu: One million British thermal units.

MMcf: One million cubic feet.

MMcf/d: One million cubic feet per day.

Mont Belvieu JV: Enterprise EF78 LLC.

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

Non-Operated Marcellus Interest: Our 33.75% interest in the Liberty and Rome gas gathering systems and related facilities located in northern Pennsylvania.

PIK Class C units: Additional Class C units issued as quarterly distributions to the holder of our Class C units.

RCF: Our senior unsecured revolving credit facility.

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

Rendezvous: Rendezvous Gas Services, LLC.

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

SEC: U.S. Securities and Exchange Commission.

Springfield: Springfield Pipeline LLC.

Springfield interest: Springfield’s 50.1% interest in the Springfield system.

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

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

Springfield system: Consists of the Springfield gas gathering system and Springfield oil gathering system.

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

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TEG: Texas Express Gathering LLC.

TEP: Texas Express Pipeline LLC.

WGP: Western Gas Equity Partners, LP.

White Cliffs: White Cliffs Pipeline, LLC.

2018 Notes: Our 2.600% Senior Notes due 2018.

2021 Notes: Our 5.375% Senior Notes due 2021.

2022 Notes: Our 4.000% Senior Notes due 2022.

2025 Notes: Our 3.950% Senior Notes due 2025.

2026 Notes: Our 4.650% Senior Notes due 2026.

2044 Notes: Our 5.450% Senior Notes due 2044.

$500.0 million COP: The COP contemplated by the registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of our common units.

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PART I. FINANCIAL INFORMATION (UNAUDITED)

Item 1. Financial Statements

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)



	Three Months Ended September 30,						Nine Months Ended September 30,
thousands except per-unit amounts	2016			2015 ⁽¹⁾			2016			2015 ⁽¹⁾
Revenues and other – affiliates
Gathering, processing and transportation	$	189,465		$	188,947		$	563,916		$	576,631
Natural gas and natural gas liquids sales	135,847			105,032			336,385			345,385
Other	—			870			—			1,172
Total revenues and other – affiliates	325,312			294,849			900,301			923,188
Revenues and other – third parties
Gathering, processing and transportation	125,727			94,082			346,416			267,566
Natural gas and natural gas liquids sales	28,189			41,968			43,200			141,489
Other	2,417			1,616			3,533			3,271
Total revenues and other – third parties	156,333			137,666			393,149			412,326
Total revenues and other	481,645			432,515			1,293,450			1,335,514
Equity income, net – affiliates	20,294			21,976			56,801			59,137
Operating expenses
Cost of product ⁽²⁾	145,643			127,704			326,959			414,328
Operation and maintenance ⁽²⁾	74,755			88,722			226,141			242,744
General and administrative ⁽²⁾	11,382			10,143			33,542			30,632
Property and other taxes	10,670			9,042			33,098			27,908
Depreciation and amortization	67,246			67,367			199,646			204,896
Impairments	2,392			2,335			11,313			276,579
Total operating expenses	312,088			305,313			830,699			1,197,087
Gain (loss) on divestiture and other, net	(6,230		)	77,254			(8,769		)	77,248
Proceeds from business interruption insurance claims	13,667			—			16,270			—
Operating income (loss)	197,288			226,432			527,053			274,812
Interest income – affiliates	4,225			4,225			12,675			12,675
Interest expense ⁽³⁾	(30,768		)	(31,773		)	(75,687		)	(82,337		)
Other income (expense), net	153			85			224			227
Income (loss) before income taxes	170,898			198,969			464,265			205,377
Income tax (benefit) expense	472			12,644			7,431			37,160
Net income (loss)	170,426			186,325			456,834			168,217
Net income attributable to noncontrolling interest	2,680			2,188			8,507			8,230
Net income (loss) attributable to Western Gas Partners, LP	$	167,746		$	184,137		$	448,327		$	159,987
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Gas Partners, LP	$	167,746		$	184,137		$	448,327		$	159,987
Pre-acquisition net (income) loss allocated to Anadarko	—			(19,848		)	(11,326		)	(63,606		)
Series A Preferred units interest in net (income) loss ⁽⁴⁾	(25,539		)	—			(50,989		)	—
General partner interest in net (income) loss ⁽⁴⁾	(60,551		)	(50,267		)	(174,332		)	(133,415		)
Common and Class C limited partners’ interest in net income (loss) ⁽⁴⁾	81,656			114,022			211,680			(37,034		)
Net income (loss) per common unit – basic and diluted ⁽⁵⁾	$	0.54		$	0.79		$	1.39		$	(0.35	)


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

⁽²⁾

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $21.3 million and $68.0 million for the three and nine months ended September 30, 2016, respectively, and $35.7 million and $132.6 million for the three and nine months ended September 30, 2015, respectively. Operation and maintenance includes charges from Anadarko of $15.1 million and $50.7 million for the three and nine months ended September 30, 2016, respectively, and $19.4 million and $56.1 million for the three and nine months ended September 30, 2015, respectively. General and administrative includes charges from Anadarko of $9.5 million and $27.6 million for the three and nine months ended September 30, 2016, respectively, and $8.5 million and $24.7 million for the three and nine months ended September 30, 2015, respectively. See Note 5.


⁽³⁾	Includes affiliate (as defined in Note 1) amounts of $1.2 million and $12.1 million for the three and nine months ended September 30, 2016, respectively, and $(4.3) million and $(9.9) million for the three and nine months ended September 30, 2015, respectively. See Note 2 and Note 9.


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


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

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



thousands except number of units	September 30, 2016		December 31, 2015 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	144,447	$	98,033
Accounts receivable, net ⁽²⁾	214,150		193,329
Other current assets	9,217		7,855
Total current assets	367,814		299,217
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	6,912,906		6,556,778
Less accumulated depreciation	1,882,012		1,697,999
Net property, plant and equipment	5,030,894		4,858,779
Goodwill	419,186		419,186
Other intangible assets	810,805		832,127
Equity investments	599,286		618,887
Other assets	13,113		13,001
Total assets	$	7,501,098	$	7,301,197
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables	$	101,101	$	98,661
Accrued ad valorem taxes	31,120		17,808
Accrued liabilities	122,164		119,019
Total current liabilities	254,385		235,488
Long-term debt	2,907,395		2,690,651
Deferred income taxes	6,360		139,704
Asset retirement obligations and other	139,604		128,652
Deferred purchase price obligation – Anadarko ⁽³⁾	16,425		188,674
Total long-term liabilities	3,069,784		3,147,681
Total liabilities	3,324,169		3,383,169
Equity and partners’ capital
Series A Preferred units (21,922,831 and zero units issued and outstanding at September 30, 2016, and December 31, 2015, respectively) ⁽⁴⁾	628,548		—
Common units (130,671,970 and 128,576,965 units issued and outstanding at September 30, 2016, and December 31, 2015, respectively)	2,604,524		2,588,991
Class C units (12,160,424 and 11,411,862 units issued and outstanding at September 30, 2016, and December 31, 2015, respectively) ⁽⁵⁾	741,183		710,891
General partner units (2,583,068 units issued and outstanding at September 30, 2016, and December 31, 2015)	138,040		120,164
Net investment by Anadarko	—		430,598
Total partners’ capital	4,112,295		3,850,644
Noncontrolling interest	64,634		67,384
Total equity and partners’ capital	4,176,929		3,918,028
Total liabilities, equity and partners’ capital	$	7,501,098	$	7,301,197


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


⁽²⁾	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $91.6 million and $42.7 million as of September 30, 2016, and December 31, 2015, respectively. Accounts receivable, net as of September 30, 2016, and December 31, 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.


⁽³⁾	See Note 2.


⁽⁴⁾	The Series A Preferred units are convertible into common units at the holder’s election on a one-for-one basis at any time after the second anniversary of the issuance date. See Note 4.


⁽⁵⁾	The 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. See Note 4.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(UNAUDITED)



	Partners’ Capital
thousands	Net Investment by Anadarko			Common Units			Class C Units		Series A Preferred Units			General Partner Units			Noncontrolling Interest			Total
Balance at December 31, 2015 ⁽¹⁾	$	430,598		$	2,588,991		$	710,891	$	—		$	120,164		$	67,384		$	3,918,028
Net income (loss)	11,326			209,958			21,835		30,876			174,332			8,507			456,834
Above-market component of swap extensions with Anadarko ⁽²⁾	—			34,782			—		—			—			—			34,782
Issuance of common units, net of offering expenses	—			25,000			—		—			—			—			25,000
Issuance of Series A Preferred units, net of offering expenses	—			—			—		686,937			—			—			686,937
Beneficial conversion feature of Series A Preferred units	—			93,409			—		(93,409		)	—			—			—
Amortization of beneficial conversion feature of Class C units and Series A Preferred units	—			(28,570		)	8,457		20,113			—			—			—
Distributions to noncontrolling interest owner	—			—			—		—			—			(11,257		)	(11,257		)
Distributions to unitholders	—			(317,813		)	—		(15,969		)	(156,507		)	—			(490,289		)
Acquisitions from affiliates	(547,989		)	(164,511		)	—		—			—			—			(712,500		)
Revision to Deferred purchase price obligation – Anadarko ⁽³⁾	—			160,152			—		—			—			—			160,152
Contributions of equity-based compensation from Anadarko	—			3,006			—		—			60			—			3,066
Net pre-acquisition contributions from (distributions to) Anadarko	(29,335		)	—			—		—			—			—			(29,335		)
Net distributions to Anadarko of other assets	—			(572		)	—		—			(9		)	—			(581		)
Elimination of net deferred tax liabilities	135,400			—			—		—			—			—			135,400
Other	—			692			—		—			—			—			692
Balance at September 30, 2016	$	—		$	2,604,524		$	741,183	$	628,548		$	138,040		$	64,634		$	4,176,929


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


⁽²⁾	See Note 5.


⁽³⁾	See Note 2.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Nine Months Ended September 30,
thousands	2016			2015 ⁽¹⁾
Cash flows from operating activities
Net income (loss)	$	456,834		$	168,217
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	199,646			204,896
Impairments	11,313			276,579
Non-cash equity-based compensation expense	3,570			3,257
Deferred income taxes	2,321			9,996
Accretion and amortization of long-term obligations, net	(9,176		)	12,296
Equity income, net – affiliates	(56,801		)	(59,137		)
Distributions from equity investment earnings – affiliates	59,671			60,645
(Gain) loss on divestiture and other, net	8,769			(77,248		)
Lower of cost or market inventory adjustments	41			—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(41,108		)	(18,617		)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net	24,103			17,695
Change in other items, net	(1,445		)	(1,686		)
Net cash provided by operating activities	657,738			596,893
Cash flows from investing activities
Capital expenditures	(372,725		)	(505,848		)
Contributions in aid of construction costs from affiliates	4,927			—
Acquisitions from affiliates	(716,465		)	(10,369		)
Acquisitions from third parties	—			(3,514		)
Investments in equity affiliates	139			(9,052		)
Distributions from equity investments in excess of cumulative earnings – affiliates	16,592			12,409
Proceeds from the sale of assets to affiliates	623			700
Proceeds from the sale of assets to third parties	7,819			147,023
Proceeds from property insurance claims	18,398			—
Net cash used in investing activities	(1,040,692		)	(368,651		)
Cash flows from financing activities
Borrowings, net of debt issuance costs	1,094,600			769,606
Repayments of debt	(880,000		)	(610,000		)
Increase (decrease) in outstanding checks	(1,070		)	(2,435		)
Proceeds from the issuance of common units, net of offering expenses	25,000			57,353
Proceeds from the issuance of Series A Preferred units, net of offering expenses	686,937			—
Distributions to unitholders⁽²⁾	(490,289		)	(398,983		)
Distributions to noncontrolling interest owner	(11,257		)	(10,150		)
Net contributions from (distributions to) Anadarko	(29,335		)	(35,403		)
Above-market component of swap extensions with Anadarko ⁽²⁾	34,782			7,916
Net cash provided by (used in) financing activities	429,368			(222,096		)
Net increase (decrease) in cash and cash equivalents	46,414			6,146
Cash and cash equivalents at beginning of period	98,033			67,054
Cash and cash equivalents at end of period	$	144,447		$	73,200
Supplemental disclosures
Acquisition of DBJV from Anadarko	$	(172,249	)	$	174,276
Net distributions to (contributions from) Anadarko of other assets	581			4,250
Interest paid, net of capitalized interest	82,529			60,612
Taxes paid (reimbursements received)	67			(138		)


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


⁽²⁾	See Note 5.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership (“MLP”) 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”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership (see Western Gas Equity Partners, LP below). WGP has no independent operations or material assets other than owning the partnership interests in WES (see Holdings of Partnership equity in Note 4). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” The “MGR assets” include the Red Desert complex and the Granger straddle plant.

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 September 30, 2016, 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
Gathering systems	12	4	5	2
Treating facilities	13	12	—	3
Natural gas processing plants/trains	19	5	—	2
NGL pipelines	2	—	—	3
Natural gas pipelines	5	—	—	—
Oil pipelines	—	1	—	1

These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), North-central Pennsylvania and Texas. The Partnership commenced operation of Train IV in May 2016 and Train V in October 2016, both of which are processing plants at the DBM complex. The Partnership has also made progress payments toward the construction of another cryogenic unit at the DBM complex (“Train VI”). The Partnership is evaluating when construction of Train VI will start and believes the earliest the plant may come online is the fourth quarter of 2017.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Basis of presentation. The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements:



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


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


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


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

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated.

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

Certain information and note disclosures commonly included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s 2015 Form 10-K, as filed with the SEC on February 25, 2016, certain sections of which were recast to reflect the results of the Springfield interest in the Partnership’s Current Report on Form 8-K, as filed with the SEC on June 10, 2016. Management believes that the disclosures made are adequate to make the information not misleading.

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

Presentation of Partnership assets. The term “Partnership assets” refers to the assets owned and interests accounted for under the equity method (see Note 7) by the Partnership as of September 30, 2016. 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.

Insurance recoveries. 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 operations as a component of Operating income (loss).

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 (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and is expected to be returned to service by the end of 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returned to full service in May 2016. As of September 30, 2016, and December 31, 2015, the consolidated balance sheets include receivables of $28.8 million and $49.0 million, respectively, for a property insurance claim related to the incident at the DBM complex. As of September 30, 2016, the Partnership had received $34.7 million in cash proceeds from insurers related to the incident at the DBM complex, including $16.3 million in proceeds from business interruption insurance claims and $18.4 million in proceeds from property insurance claims.

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

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2015-06, Earnings Per Share (Topic 260)—Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. This ASU provides guidance for the presentation of historical earnings per unit for MLPs that apply the two-class method of calculating earnings per unit. When a general partner transfers or “drops down” net assets to an MLP, 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. The Partnership applies the two-class method of calculating earnings per unit as described above (including the allocation of pre-acquisition net income (loss) to the general partner), and discloses the rights to earnings (losses) noted above. As such, there was no impact to the Partnership’s consolidated financial statements upon adoption of this ASU on January 1, 2016.

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 resulted in a reclassification that reduced Other assets and Long-term debt by $16.7 million on the Partnership’s consolidated balance sheet at December 31, 2015. See Note 9.

ASU 2015-02, Consolidation (Topic 810)—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. The Partnership 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 and disclosure purposes. As such, the adoption of this ASU on January 1, 2016, did not impact the Partnership’s consolidated financial statements.

New accounting standards issued but not yet adopted. ASU 2016-16, Income Taxes (Topic 740)—Intra-Entity Transfers of Assets Other Than Inventory. This ASU requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a modified retrospective approach, with early adoption permitted. The Partnership is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

ASU 2016-15, Statement of Cash Flows (Topic 230)—Classification of Certain Cash Receipts and Cash Payments. This ASU provides clarification on how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Partnership does not expect the adoption of this ASU to have a material impact on its consolidated statement of cash flows.

ASU 2016-02, Leases (Topic 842). This ASU requires the lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Partnership is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes current revenue recognition requirements. The codification was amended through additional ASUs and, as amended, 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.

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2. ACQUISITIONS AND DIVESTITURES

The following table presents the acquisitions completed by the Partnership during 2016 and 2015, and identifies the funding sources for such acquisitions:



thousands except unit and percent amounts	Acquisition Date	Percentage Acquired		Deferred Purchase Price Obligation - Anadarko		Borrowings		Common Units Issued	Series A Preferred Units Issued
DBJV ⁽¹⁾	03/02/2015	100	%	$	174,276	$	—	—	—
Springfield ⁽²⁾	03/14/2016	100	%	—		247,500		2,089,602	14,030,611

⁽¹⁾

The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are 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. At the acquisition date, the Partnership estimated the future payment would be $282.8 million, the net present value of which was $174.3 million. For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below.

⁽²⁾

The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units.

Springfield acquisition. Because the acquisition of Springfield was a transfer of net assets between entities under common control, the Partnership’s historical financial statements and operational data previously filed with the SEC have been recast in this Form 10-Q to include the results attributable to the Springfield interest as if the Partnership owned Springfield for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of Springfield 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 Springfield during the periods reported.

The following table presents the impact of the Springfield interest on Revenues and other and Net income (loss) as presented in the Partnership’s historical consolidated statements of operations:



	Three Months Ended September 30, 2015
thousands	Partnership Historical		Springfield Interest		Eliminations			Combined
Revenues and other	$	385,101	$	47,431	$	(17	)	$	432,515
Net income (loss)	166,477		19,848		—			186,325

	Nine Months Ended September 30, 2015
thousands	Partnership Historical		Springfield Interest		Eliminations			Combined
Revenues and other	$	1,190,082	$	145,482	$	(50	)	$	1,335,514
Net income (loss)	106,353		61,864		—			168,217

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2. ACQUISITIONS AND DIVESTITURES (CONTINUED)

DBJV acquisition - 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 DBJV for the calendar years 2018 and 2019, less (b) the Partnership’s share of all capital expenditures incurred for DBJV 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 DBJV 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 DBJV) was $282.8 million, which had a net present value of $174.3 million, using a discount rate of 10%. During the nine months ended September 30, 2016, the Partnership recognized an aggregate $259.9 million decrease in the estimated future payment obligation, resulting in a net present value of $16.4 million for this obligation at September 30, 2016, calculated using a discounted cash flow model with a 10% discount rate. The reduction in the value of the deferred purchase price obligation is primarily due to revisions reflecting a decrease in the Partnership’s estimate of 2018 and 2019 Net Earnings and an increase in the Partnership’s estimate of aggregate capital expenditures to be incurred by DBJV through February 29, 2020.

The following table summarizes the financial statement impact of the Deferred purchase price obligation - Anadarko:



	Deferred purchase price obligation - Anadarko			Estimated future payment obligation
Balance at March 2, 2015 – Acquisition date	$	174,276		$	282,807
Accretion expense ⁽¹⁾	14,398
Balance at December 31, 2015	188,674			282,807
Accretion expense ⁽¹⁾	4,537
Balance at March 31, 2016	193,211			282,807
Accretion revision ⁽²⁾	(15,461		)
Revision to Deferred purchase price obligation – Anadarko ⁽³⁾	(148,600		)
Balance at June 30, 2016	29,150			41,666
Accretion revision ⁽²⁾	(1,173		)
Revision to Deferred purchase price obligation – Anadarko ⁽³⁾	(11,552		)
Balance at September 30, 2016	$	16,425		$	22,920


⁽¹⁾	Accretion expense was recorded as a charge to Interest expense on the consolidated statements of operations.


⁽²⁾	Interest expense on the consolidated statements of operations includes financing-related accretion revisions of $(1.2) million and $(12.1) million for the three and nine months ended September 30, 2016, respectively.


⁽³⁾	Recorded as revisions within Common units on the consolidated balance sheets and consolidated statement of equity and partners’ capital.

Assets held for sale - Hugoton system. During the third quarter of 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, satisfied criteria to be considered held for sale. The assets were remeasured to their current fair value using a market approach and Level 2 fair-value measurement, resulting in a loss of $6.2 million at September 30, 2016, recorded as Gain (loss) on divestiture and other, net in the Partnership’s consolidated statements of operations. At September 30, 2016, the Partnership’s consolidated balance sheet included long-term assets of $65.6 million and long-term liabilities of $8.4 million associated with assets held for sale. The sale of these assets closed on October 31, 2016.

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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
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	0.800		152,588		February 2016
2016
March 31	$	0.815	$	158,905	May 2016
June 30	0.830		162,827		August 2016
September 30 ⁽¹⁾	0.845		166,742		November 2016

⁽¹⁾

The Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders for the third quarter of 2016 of $0.845 per unit, or $166.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below) and Series A Preferred units (see Series A Preferred unit distributions below). The cash distribution is payable on November 10, 2016, to unitholders of record at the close of business on October 31, 2016.

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 made distributions to APC Midstream Holdings, LLC (“AMH”), the holder of the Class C units, of (i) 214,416 PIK Class C units in August 2016, for the quarterly distribution period ended June 30, 2016, (ii) 210,562 PIK Class C units in May 2016, for the quarterly distribution period ended March 31, 2016, and (iii) 323,584 PIK Class C units in February 2016, for the quarterly distribution period ended December 31, 2015.

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3. PARTNERSHIP DISTRIBUTIONS (CONTINUED)

Series A Preferred unit distributions. As further described in Note 4, the Partnership issued Series A Preferred units representing limited partner interests in the Partnership to private investors in March 2016 and April 2016. The Series A Preferred unitholders receive quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. The holders of the Series A Preferred units are entitled to certain rights that are senior to the rights of holders of common and Class C units, such as rights to distributions and rights upon liquidation of the Partnership. No payment or distribution on any junior equity security of the Partnership, including common and Class C units, for any quarter is permitted prior to the payment in full of the Series A Preferred unit distribution (including any outstanding arrearages). For the quarter ended September 30, 2016, the Series A Preferred unitholders will receive an aggregate cash distribution of $14.9 million (to be paid in November 2016). For the quarter ended June 30, 2016, the Series A Preferred unitholders received an aggregate cash distribution of $14.1 million (paid in August 2016) comprised of a quarterly per unit distribution prorated for the 77-day period 7,892,220 Series A Preferred units were outstanding during the second quarter of 2016 and a full quarterly per unit distribution on 14,030,611 Series A Preferred units. For the quarter ended March 31, 2016, the Series A Preferred unitholders received an aggregate cash distribution of $1.9 million (paid in May 2016), based on the quarterly per unit distribution prorated for the 18-day period 14,030,611 Series A Preferred units were outstanding during the first quarter of 2016. See Note 4 for further discussion of the Series A Preferred units.

4. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. 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 (“$500.0 million COP”), during the year ended December 31, 2015, the Partnership issued 873,525 common units, at an average price of $66.61, generating proceeds of $57.4 million (net of $0.8 million for the underwriting discount and other offering expenses). Net proceeds were used for general partnership purposes, including funding capital expenditures. Gross proceeds generated during the year ended December 31, 2015, were $58.2 million. Commissions paid during the year ended December 31, 2015, were $0.6 million. The Partnership issued no common units under the $500.0 million COP during the nine months ended September 30, 2016.

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 a 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 September 30, 2016, no such proceeds had been received, and no Class C units had been redeemed.

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, it 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.

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4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Series A Preferred units. In connection with the closing of the Springfield acquisition on March 14, 2016, the Partnership issued 14,030,611 Series A Preferred units (the “March 2016 Series A units”) to private investors for a cash purchase price of $32.00 per unit, generating proceeds of $440.0 million (net of fees and expenses, including a 2.0% transaction fee paid to the private investors). In April 2016, the Partnership issued an additional 7,892,220 Series A Preferred units (the “April 2016 Series A units”) pursuant to the full exercise of an option granted in connection with the March 2016 Series A units issuance, generating net proceeds of $246.9 million. The Series A Preferred unitholders may convert the Series A Preferred units into common units on a one-for-one basis at any time after the second anniversary of the issuance date, in whole or in part, subject to certain conversion thresholds. Similarly, the Partnership may convert the Series A Preferred units at any time after the third anniversary of the issuance date, in whole or in part, if the closing price of the Partnership’s common units is greater than $48.00 per common unit for 20 of the 30 preceding trading days, and subject to other certain conversion thresholds. In addition, upon certain events involving a change of control, the Series A Preferred unitholders may elect on an individual basis, subject to certain conditions, to (i) convert their Series A Preferred units to common units at the then applicable conversion rate, (ii) if the Partnership is not the surviving entity (or if the Partnership is the surviving entity, but its common units will cease to be listed), require the Partnership to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue a substantially equivalent security (or convert into common units based on a specified formula, if the Partnership is unable to cause such substantially equivalent securities to be issued), (iii) if the Partnership is the surviving entity, continue to hold their Series A Preferred units, or (iv) require the Partnership to redeem the Series A Preferred units at a price per Series A Preferred unit of $32.32, plus accrued and unpaid distributions to be paid in cash or common units at the discretion of the Partnership.

The Series A Preferred unitholders will vote on an as-converted basis with the Partnership’s common unitholders and will have certain other class voting rights with respect to any amendment to the partnership agreement that would adversely affect any rights, preferences or privileges of the Series A Preferred unitholders. In connection with the issuance of the Series A Preferred units, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Series A Preferred unit purchasers relating to the registered resale of the common units representing limited partner interests in the Partnership issuable upon conversion of the Series A Preferred units. Pursuant to the Registration Rights Agreement, the Partnership is required to use its commercially reasonable efforts to file and maintain a registration statement for the resale of the converted Series A Preferred units, with such registration statement to become effective no later than March 2018.

The March 2016 Series A units and the April 2016 Series A units were issued at a discount to the then-current market price of the common units into which they are convertible. The discount on the March 2016 Series A units, totaling $21.7 million, represents a beneficial conversion feature, and on the date the Preferred Unit Purchase Agreement was signed (the “commitment date”), it was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the March 2016 Series A units on the commitment date. The discount on the April 2016 Series A units, totaling $71.7 million, also represents a beneficial conversion feature and on the date the option to purchase additional Series A units was exercised (the “notice date”), it was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the April 2016 Series A units on the notice date. The beneficial conversion features are considered non-cash distributions that will be recognized from each issuance date through the date of earliest conversion, resulting in an increase in Series A Preferred unitholders’ capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion features are amortized assuming a conversion date of March 14, 2018 for the March 2016 Series A units and a conversion date of April 15, 2018 for the April 2016 Series A units, using the effective yield method.

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4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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

The following table summarizes the common, Class C, Series A Preferred and general partner units issued during the nine months ended September 30, 2016:



	Common Units	Class C Units	Series A Preferred Units	General Partner Units	Total
Balance at December 31, 2015	128,576,965	11,411,862	—	2,583,068	142,571,895
PIK Class C units	—	748,562	—	—	748,562
Springfield acquisition	2,089,602	—	14,030,611	—	16,120,213
April 2016 Series A units	—	—	7,892,220	—	7,892,220
Long-Term Incentive Plan award vestings	5,403	—	—	—	5,403
Balance at September 30, 2016	130,671,970	12,160,424	21,922,831	2,583,068	167,338,293

Holdings of Partnership equity. As of September 30, 2016, WGP held 50,132,046 common units, representing a 30.0% 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 1.5% general partner interest in the Partnership, and 100% of the incentive distribution rights. As of September 30, 2016, other subsidiaries of Anadarko held 2,011,380 common units and 12,160,424 Class C units, representing an aggregate 8.5% limited partner interest in the Partnership. As of September 30, 2016, the public held 78,528,544 common units, representing a 46.9% limited partner interest in the Partnership and private investors held 21,922,831 Series A Preferred units, representing a 13.1% limited partner interest in the Partnership.

Net income (loss) per unit for common units. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of the acquisition of the Partnership assets, net of distributions on the Series A Preferred units and amortization of the Series A Preferred unit beneficial conversion features (see Series A Preferred units above), is allocated to the general partner, the common unitholders and the Class C unitholder, in accordance with their respective weighted-average ownership percentages (exclusive of the Series A Preferred unit limited partnership interest) and, when applicable, giving effect to incentive distributions allocable to the general partner. The allocable limited partners’ interest in net income (loss) is also net of amortization of the beneficial conversion feature related to the Class C units (see Class C units above) and is allocated between the common and Class C unitholders by applying the provisions of the partnership agreement that govern actual cash distributions and capital account allocations, as if all earnings for the period had been distributed. 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.

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. The Series A Preferred units are not considered a participating security as they only have distribution rights up to the specified per-unit quarterly distribution and have no rights to the Partnership’s undistributed earnings. 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 adjusted for distributions on the Series A Preferred units and a reallocation of the limited partners’ interest in net income (loss) assuming conversion of the Series A Preferred units into 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 (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming conversion of the Series A Preferred units.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
thousands except per-unit amounts	2016			2015			2016			2015
Net income (loss) attributable to Western Gas Partners, LP	$	167,746		$	184,137		$	448,327		$	159,987
Pre-acquisition net (income) loss allocated to Anadarko	—			(19,848		)	(11,326		)	(63,606		)
Series A Preferred units interest in net (income) loss ⁽¹⁾	(25,539		)	—			(50,989		)	—
General partner interest in net (income) loss	(60,551		)	(50,267		)	(174,332		)	(133,415		)
Common and Class C limited partners’ interest in net income (loss)	$	81,656		$	114,022		$	211,680		$	(37,034	)
Net income (loss) allocable to common units ⁽¹⁾	$	70,204		$	101,140		$	181,388		$	(44,999	)
Net income (loss) allocable to Class C units ⁽¹⁾	11,452			12,882			30,292			7,965
Common and Class C limited partners’ interest in net income (loss)	$	81,656		$	114,022		$	211,680		$	(37,034	)
Net income (loss) per unit
Common units – basic and diluted ⁽²⁾	$	0.54		$	0.79		$	1.39		$	(0.35	)
Weighted-average units outstanding
Common units – basic and diluted	130,672			128,575			130,112			128,267
Excluded due to anti-dilutive effect:
Class C units	12,063			11,161			11,835			11,042
Series A Preferred units assuming conversion to common units	21,923			—			15,160			—


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


⁽²⁾	The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 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 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was $308.1 million and $252.3 million at September 30, 2016, and December 31, 2015, 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 9.

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. 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 September 30, 2016:



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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 operations:



	Three Months Ended September 30,						Nine Months Ended September 30,
thousands	2016			2015			2016			2015
Gains (losses) on commodity price swap agreements related to sales: ⁽¹⁾
Natural gas sales	$	719		$	5,774		$	12,962		$	39,100
Natural gas liquids sales	15,939			33,746			56,489			116,475
Total	16,658			39,520			69,451			155,575
Losses on commodity price swap agreements related to purchases ⁽²⁾	(9,248		)	(23,998		)	(45,032		)	(99,897		)
Net gains (losses) on commodity price swap agreements	$	7,410		$	15,522		$	24,419		$	55,678


⁽¹⁾	Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded.


⁽²⁾	Reported in Cost of product in the consolidated statements of operations 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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.

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 operations. 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 nine months ended September 30, 2016, the capital contribution from Anadarko was $34.8 million.

Gathering and processing agreements. The Partnership has significant gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The Partnership’s gathering, treating and transportation throughput (excluding equity investment throughput) attributable to natural gas production owned or controlled by Anadarko was 37% and 38% for the three and nine months ended September 30, 2016, respectively, and 53% and 55% for the three and nine months ended September 30, 2015, respectively. The Partnership’s processing throughput (excluding equity investment throughput) attributable to natural gas production owned or controlled by Anadarko was 51% and 55% for the three and nine months ended September 30, 2016, respectively, and 47% and 51% for the three and nine months ended September 30, 2015, respectively. The Partnership’s gathering, treating and transportation throughput (excluding equity investment throughput) attributable to crude/NGL production owned or controlled by Anadarko was 67% and 64% for the three and nine months ended September 30, 2016, respectively, and 100% for each of the three and nine months ended September 30, 2015. Prior to January 1, 2016, Springfield’s contracts were with a subsidiary of Anadarko who contracted with third parties. Effective January 1, 2016, Springfield’s contracts are with both a subsidiary of Anadarko and third parties directly.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Acquisitions from Anadarko. On March 14, 2016, the Partnership acquired Springfield from Anadarko, and on March 2, 2015, the Partnership acquired DBJV from Anadarko. See Note 2 for further information on these acquisitions.

WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“WES LTIP”) primarily to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized over the vesting period and was $0.1 million and $0.3 million for the three and nine months ended September 30, 2016, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 30, 2015, respectively.

WGP LTIP and Anadarko Incentive Plans. General and administrative expenses included $1.4 million and $3.7 million for the three and nine months ended September 30, 2016, respectively, and $1.0 million and $3.1 million for the three and nine months ended September 30, 2015, 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 Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WGP LTIP”) and the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (referred to collectively as the “Anadarko Incentive Plans”). Of this amount, $3.1 million is reflected as a contribution to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the nine months ended September 30, 2016.

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



	Nine Months Ended September 30,
	2016			2015			2016			2015
thousands	Purchases						Sales
Cash consideration	$	3,965		$	10,369		$	623		$	700
Net carrying value	(3,366		)	(5,785		)	(605		)	(366		)
Partners’ capital adjustment	$	599		$	4,584		$	18		$	334

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes material affiliate transactions. See Note 2 for discussion of affiliate acquisitions and related funding.



	Three Months Ended September 30,					Nine Months Ended September 30,
thousands	2016			2015		2016			2015
Revenues and other ⁽¹⁾	$	325,312		$	294,849	$	900,301		$	923,188
Equity income, net – affiliates ⁽¹⁾	20,294			21,976		56,801			59,137
Cost of product ⁽¹⁾	21,254			35,656		67,979			132,613
Operation and maintenance ⁽²⁾	15,052			19,394		50,688			56,065
General and administrative ⁽³⁾	9,453			8,496		27,574			24,691
Operating expenses	45,759			63,546		146,241			213,369
Interest income ⁽⁴⁾	4,225			4,225		12,675			12,675
Interest expense ⁽⁵⁾	(1,173		)	4,310		(12,097		)	9,920
Proceeds from the issuance of common units, net of offering expenses ⁽⁶⁾	—			—		25,000			—
Distributions to unitholders ⁽⁷⁾	97,648			80,845		282,326			228,893
Above-market component of swap extensions with Anadarko	18,417			7,916		34,782			7,916


⁽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 three and nine months ended September 30, 2016, includes accretion revisions to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 9).


⁽⁶⁾	Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 2).


⁽⁷⁾	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 operations.

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(UNAUDITED)

6. PROPERTY, PLANT AND EQUIPMENT

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



thousands	Estimated Useful Life	September 30, 2016		December 31, 2015
Land	n/a	$	4,000	$	3,744
Gathering systems	3 to 47 years	6,471,338		6,061,004
Pipelines and equipment	15 to 45 years	135,504		136,290
Assets under construction	n/a	272,169		329,887
Other	3 to 40 years	29,895		25,853
Total property, plant and equipment		6,912,906		6,556,778
Accumulated depreciation		1,882,012		1,697,999
Net property, plant and equipment		$	5,030,894	$	4,858,779

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.

As of September 30, 2016, net property, plant and equipment includes impairments of $11.3 million, including an impairment of $6.1 million at the Newcastle system. This asset was impaired to its estimated fair value of $3.1 million, using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows caused by the low commodity price environment. Also during this period, the Partnership recognized impairments of $5.2 million, primarily related to the abandonment of compressors at the MIGC system and cancellation of projects at the DBJV and Anadarko-Operated Marcellus Interest systems. See Note 2 for a discussion of the Partnership’s assets held for sale as of September 30, 2016.

7. EQUITY INVESTMENTS

The following table presents the activity in the Partnership’s equity investments for the nine months ended September 30, 2016:



	Equity Investments
thousands	Fort Union			White Cliffs			Rendezvous			Mont Belvieu JV			TEG			TEP			FRP			Total
Balance at December 31, 2015	$	17,122		$	50,439		$	50,913		$	117,089		$	16,283		$	194,803		$	172,238		$	618,887
Investment earnings (loss), net of amortization	(308		)	10,474			1,413			18,245			529			12,239			14,209			56,801
Contributions	—			441			—			—			—			(580		)	—			(139		)
Distributions	(787		)	(10,038		)	(2,573		)	(18,274		)	(546		)	(12,427		)	(15,026		)	(59,671		)
Distributions in excess of cumulative earnings ⁽¹⁾	(3,354		)	(3,393		)	(1,541		)	(3,963		)	(266		)	(3,720		)	(355		)	(16,592		)
Balance at September 30, 2016	$	12,673		$	47,923		$	48,212		$	113,097		$	16,000		$	190,315		$	171,066		$	599,286


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

During the nine months ended September 30, 2016, an impairment loss was recognized by the managing partner of Fort Union. The Partnership’s 14.81% share of the impairment loss was $3.0 million, which was recorded in Equity income, net – affiliates in the consolidated statements of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8. COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:



thousands	September 30, 2016		December 31, 2015
Trade receivables, net	$	184,331	$	143,557
Other receivables, net	29,819		49,772
Total accounts receivable, net	$	214,150	$	193,329

A summary of other current assets is as follows:



thousands	September 30, 2016		December 31, 2015
Natural gas liquids inventory	$	5,086	$	2,403
Imbalance receivables	1,514		2,122
Prepaid insurance	2,617		2,296
Other	—		1,034
Total other current assets	$	9,217	$	7,855

A summary of accrued liabilities is as follows:



thousands	September 30, 2016		December 31, 2015
Accrued capital expenditures	$	49,328	$	61,454
Accrued plant purchases	31,849		16,425
Accrued interest expense	28,532		26,194
Short-term asset retirement obligations	2,182		3,677
Short-term remediation and reclamation obligations	1,136