Form 8-K Western Gas Partners LP For: Jun 10

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June 10, 2016 4:36 PM EDT

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): June 10, 2016

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)



Delaware	001-34046	26-1075808
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(IRS Employer Identification No.)

1201 Lake Robbins Drive

The Woodlands, Texas 77380-1046

(Address of principal executive offices) (Zip Code)

(832) 636-6000

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

On March 16, 2016, Western Gas Partners, LP (the “Partnership”) filed a Current Report on Form 8-K (the “Initial Report”) regarding, among other things, the closing of its acquisition on March 14, 2016, of a 100% interest in Springfield Pipeline LLC (“Springfield”) from Anadarko Petroleum Corporation (“Anadarko”). The $750.0 million in consideration paid by the Partnership consisted of $712.5 million in cash and 1,253,761 common units of the Partnership. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system.

On May 26, 2016, the Partnership filed a Current Report on Form 8-K/A (the “Amendment”) amending and supplementing the Initial Report to include the audited financial statements of Springfield, the unaudited pro forma financial statements of the Partnership required by Items 9.01(a) and 9.01(b) of Form 8-K and certain exhibits under Item 9.01(d) of Form 8-K. No other modifications to the Initial Report were made by the Amendment.

Due to Anadarko’s control of the Partnership through its ownership and control of Western Gas Equity Partners, LP, a Delaware master limited partnership formed by Anadarko in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership, the acquisition of Springfield is considered a transfer of net assets between entities under common control. As such, the Partnership is required to recast its financial statements to include the activities of Springfield as of the date of common control. Exhibits 12.1, 99.1, 99.2, and 99.3 included in this Current Report on Form 8-K give retroactive effect to the acquisition of Springfield as if the Partnership owned Springfield for all periods presented.

The Partnership’s Form 10-K for the year ended December 31, 2015 (the “2015 Form 10-K”), as filed with the U.S. Securities and Exchange Commission on February 25, 2016, is hereby recast by this Current Report on Form 8-K as follows:


•	the Computation of Ratio of Earnings to Fixed Charges of the Partnership included herein on Exhibit 12.1 supersedes Exhibit 12.1 filed under Part IV, Item 15 of the 2015 Form 10-K;


•	the Selected Financial and Operating Data of the Partnership included herein on Exhibit 99.1 supersedes Part II, Item 6 of the 2015 Form 10-K;


•	the Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Partnership included herein on Exhibit 99.2 supersedes Part II, Item 7 of the 2015 Form 10-K; and

•

the Financial Statements and Supplementary Data of the Partnership included herein on Exhibit 99.3 supersedes Part II, Item 8 of the 2015 Form 10-K, except for the Report of Management, Management’s Assessment of Internal Control over Financial Reporting and the Report of Independent Registered Public Accounting Firm with regard to internal control over financial reporting, included at pages 113, 114 and 115 of the 2015 Form 10-K, respectively, which are not impacted by this Current Report on Form 8-K.

There have been no revisions or updates to any other sections of the 2015 Form 10-K other than the revisions noted above. This Current Report on Form 8-K does not reflect events occurring after the filing of the 2015 Form 10-K or modify or update any related disclosures. This Current Report on Form 8-K should be read in conjunction with the 2015 Form 10-K, and any references herein to Items 6, 7 and 8 under Part II of the 2015 Form 10-K refer to Exhibits 99.1, 99.2, and 99.3, respectively. As of the date of this Current Report on Form 8-K, future references to the Partnership’s historical financial statements should be made to this Current Report as well as future quarterly and annual reports on Forms 10-Q and Form 10-K, respectively.

Item 9.01 Financial Statements and Exhibits.



(d)	Exhibits

	12.1*	Computation of Ratio of Earnings to Fixed Charges.

	23.1*	Consent of KPMG LLP.

	99.1*	Selected Financial and Operating Data.

	99.2*	Management’s Discussion and Analysis of Financial Condition and Results of Operations.

	99.3*	Financial Statements and Supplementary Data.

	101.INS*	XBRL Instance Document.

	101.SCH*	XBRL Schema Document.

	101.CAL*	XBRL Calculation Linkbase Document.

	101.LAB*	XBRL Label Linkbase Document.

	101.PRE*	XBRL Presentation Linkbase Document.

	101.DEF*	XBRL Definition Linkbase Document.



*	Filed herewith

SIGNATURE

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



		WESTERN GAS PARTNERS, LP

		By:	Western Gas Holdings, LLC, its general partner


Dated:	June 10, 2016	By:	/s/ Benjamin M. Fink
			Benjamin M. Fink Senior Vice President, Chief Financial Officer and Treasurer

EXHIBIT INDEX



Exhibit Number	Exhibit Title

12.1*	Computation of Ratio of Earnings to Fixed Charges.

23.1*	Consent of KPMG LLP.

99.1*	Selected Financial and Operating Data.

99.2*	Management’s Discussion and Analysis of Financial Condition and Results of Operations.

99.3*	Financial Statements and Supplementary Data.

101.INS*	XBRL Instance Document.

101.SCH*	XBRL Schema Document.

101.CAL*	XBRL Calculation Linkbase Document.

101.LAB*	XBRL Label Linkbase Document.

101.PRE*	XBRL Presentation Linkbase Document.

101.DEF*	XBRL Definition Linkbase Document.



*	Filed herewith

EXHIBIT 12.1

WESTERN GAS PARTNERS, LP

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES



	Year Ended December 31,
thousands	2015		2014		2013		2012		2011
Earnings:
Income before income taxes	$	59,739	$	495,729	$	292,559	$	203,379	$	257,508
Add:
Fixed charges	123,680		87,892		64,806		48,871		31,689
Distributions from equity investees	98,298		81,022		22,136		20,660		15,999
Amortization of capitalized interest	2,375		2,095		934		485		294
Less:
Equity income, net	71,251		57,836		22,948		16,042		11,261
Capitalized interest	8,318		9,832		11,945		6,196		420
Net income before taxes attributable to noncontrolling interests	10,101		14,025		10,816		14,890		14,103
Earnings	$	194,422	$	585,045	$	334,726	$	236,267	$	279,706
Fixed charges:
Interest expense, including capitalized interest	$	122,190	$	86,598	$	63,742	$	48,256	$	31,221
Interest component of rent expense	1,490		1,294		1,064		615		468
Fixed charges	$	123,680	$	87,892	$	64,806	$	48,871	$	31,689
Ratio of earnings to fixed charges	1.6x		6.7x		5.2x		4.8x		8.8x

These ratios were computed by dividing earnings by fixed charges. For this purpose, earnings include pre-tax income, plus fixed charges to the extent they affect current year earnings, amortization of capitalized interest and distributed income of equity investees, then subtracting equity income, noncontrolling interests in pre-tax income from subsidiaries that did not incur fixed charges, and interest capitalized during the year. Fixed charges include interest expensed and capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and estimates of interest within rental expenses.

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP)

We consent to the incorporation by reference in the registration statements (No. 333‑193828) on Form S-3, (No. 333‑198436) on Form S-3, and (No. 333‑151317) on Form S-8 of Western Gas Partners, LP of our report dated June 10, 2016, with respect to the consolidated balance sheets of Western Gas Partners, LP and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2015, which report appears in the Current Report on Form 8‑K of Western Gas Partners, LP dated June 10, 2016.

/s/ KPMG LLP

Houston, Texas

June 10, 2016

EXHIBIT 99.1

COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refer to Western Gas Partners, LP and its subsidiaries. As generally used within the energy industry and in this Item 6 of Exhibit 99.1 to this Current Report on Form 8-K, the identified terms and definitions have the following meanings:

Affiliates: Subsidiaries of Anadarko, excluding us, and includes 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 interest in the Larry’s Creek, Seely and Warrensville gas gathering systems.

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

Chipeta: Chipeta Processing, LLC.

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

DBM: Delaware Basin Midstream, LLC.

EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see the caption How We Evaluate Our Operations under Item 7 of Exhibit 99.2 to this Current Report on Form 8-K.

Equity investment throughput: Our 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of our 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.

Fort Union: Fort Union Gas Gathering, LLC.

FRP: Front Range Pipeline LLC.

GAAP: Generally accepted accounting principles in the United States.

General partner or GP: Western Gas Holdings, LLC.

Initial assets: The assets and liabilities of Anadarko Gathering Company LLC, Pinnacle Gas Treating LLC and MIGC LLC, which Anadarko contributed to us concurrently with the closing of our IPO in May 2008.

IPO: Initial public offering.

MBbls/d: One thousand barrels per day.

MGR: Mountain Gas Resources, LLC.

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 interest in the Liberty and Rome gas gathering systems.

OTTCO: Overland Trail Transmission, LLC.

Rendezvous: Rendezvous Gas Services, LLC.

Springfield: Springfield Pipeline LLC.

Springfield gas gathering system: Springfield's 50.1% interest in the Springfield gas gathering system, which consists of gas gathering lines located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.

Springfield oil gathering system: Springfield's 50.1% interest in the Springfield oil gathering system, which consists of oil gathering lines 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.

TEG: Texas Express Gathering LLC.

TEP: Texas Express Pipeline LLC.

WGP: Western Gas Equity Partners, LP.

White Cliffs: White Cliffs Pipeline, LLC.

Item 6. Selected Financial and Operating Data

The following Summary Financial Information table shows our selected financial and operating data, which are derived from our consolidated financial statements for the periods and as of the dates indicated.

The term “Partnership assets” refers to the assets owned, including the Springfield system, and interests accounted for under the equity method by us as of December 31, 2015 (see Note 9—Equity Investments in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Because Anadarko controls us through its ownership and control of WGP, which owns the entire interest in our general partner, each of our acquisitions of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Further, after an acquisition of Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of such Partnership assets from the date of common control. For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of Partnership assets from Anadarko, including the Springfield system, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the Partnership assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership assets prior to our acquisitions from Anadarko as being “our” historical financial results.

Acquisitions. The following table presents the acquisitions completed by the Partnership since its inception, excluding the acquisition of Springfield in March 2016 (see below):



	Acquisition Date	Percentage Acquired		Affiliate or Third-party Acquisition
Initial assets ⁽¹⁾	05/14/2008	100	%	Anadarko
Powder River assets ⁽²⁾	12/19/2008	Various ⁽²⁾		Anadarko
Chipeta	07/01/2009	51	%	Anadarko
Granger	01/29/2010	100	%	Anadarko
Wattenberg	08/02/2010	100	%	Anadarko
White Cliffs⁽³⁾	09/28/2010	10	%	Various ⁽³⁾
Platte Valley	02/28/2011	100	%	Third party
Bison	07/08/2011	100	%	Anadarko
MGR	01/13/2012	100	%	Anadarko
Chipeta ⁽⁴⁾	08/01/2012	24	%	Anadarko
Non-Operated Marcellus Interest	03/01/2013	33.75	%	Anadarko
Anadarko-Operated Marcellus Interest	03/08/2013	33.75	%	Third party
Mont Belvieu JV	06/05/2013	25	%	Third party
OTTCO	09/03/2013	100	%	Third party
TEFR Interests ⁽⁵⁾	03/03/2014	Various ⁽⁵⁾		Anadarko
DBM	11/25/2014	100	%	Third party
DBJV system	03/02/2015	50	%	Anadarko


⁽¹⁾	Concurrently with the closing of our IPO, Anadarko contributed the initial assets to us.


⁽²⁾	Acquired the Powder River assets, which included (i) the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% membership interest in Fort Union.


⁽³⁾	Acquired a 10% interest in White Cliffs, which consisted of a 9.6% third-party interest and a 0.4% interest from Anadarko.


⁽⁴⁾	Acquired Anadarko’s then-remaining 24% membership interest in Chipeta, receiving distributions related to the additional interest effective July 1, 2012.


⁽⁵⁾	Acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP.

In March 2016, the Partnership acquired Anadarko’s 100% interest in Springfield. See Note 14—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K. Our consolidated financial statements include the combined financial results and operations for: (i) affiliate transactions for all periods presented, including Springfield, and (ii) third-party transactions since the acquisition date.

Divestitures. In July 2015, the Dew and Pinnacle systems in East Texas were sold to a third party.

The information in the following table should be read together with the information in the captions How We Evaluate Our Operations, Items Affecting the Comparability of Our Financial Results, Results of Operations, and Key Performance Metrics under Item 7 of Exhibit 99.2 to this Current Report on Form 8-K:



thousands except per-unit data, throughput, Adjusted gross margin per Mcf and Adjusted gross margin per Bbl	Summary Financial Information
	2015⁽¹⁾			2014 ⁽¹⁾			2013⁽¹⁾			2012 ⁽¹⁾			2011 ⁽¹⁾
Statement of Income Data (for the year ended):
Total revenues	$	1,752,072		$	1,533,377		$	1,200,060		$	998,031		$	932,255
Operating income (loss)	157,330			554,731			325,619			228,226			271,011
Net income (loss)	14,207			456,668			288,244			170,532			218,207
Net income attributable to noncontrolling interest	10,101			14,025			10,816			14,890			14,103
Net income (loss) attributable to Western Gas Partners, LP	4,106			442,643			277,428			155,642			204,104
General partner interest in net income (loss) ⁽²⁾	180,996			120,980			69,633			28,089			8,599
Limited partners’ interest in net income (loss) ⁽²⁾	(256,276		)	256,509			200,866			78,863			131,560
Net income (loss) per common unit (basic) ⁽²⁾	(1.95		)	2.13			1.83			0.84			1.64
Net income (loss) per common unit (diluted) ⁽²⁾	(1.95		)	2.12			1.83			0.84			1.64
Net income (loss) per subordinated unit (basic and diluted) ⁽²⁾	—			—			—			—			1.28
Distributions per unit	3.050			2.650			2.280			1.960			1.655
Balance Sheet Data (at year end):
Total assets	$	7,317,903		$	7,563,954		$	5,338,772		$	4,482,197		$	3,340,941
Total long-term liabilities	3,164,387			2,713,413			1,669,777			1,383,129			923,688
Total equity and partners’ capital	3,918,028			4,568,462			3,422,675			2,865,352			2,255,111
Cash Flow Data (for the year ended):
Net cash flows provided by (used in):
Operating activities	$	785,645		$	694,495		$	601,335		$	409,448		$	336,657
Investing activities	(500,277		)	(2,740,175		)	(1,858,912		)	(1,633,408		)	(569,732		)
Financing activities	(254,389		)	2,011,970			938,324			1,417,380			432,541
Capital expenditures	(637,503		)	(804,822		)	(851,771		)	(913,834		)	(266,402		)
Throughput (MMcf/d except throughput measured in barrels):
Total throughput for natural gas assets	4,300			3,984			3,611			3,211			2,865
Throughput attributable to noncontrolling interest for natural gas assets	142			165			168			228			242
Total throughput attributable to Western Gas Partners, LP for natural gas assets ⁽³⁾	4,158			3,819			3,443			2,983			2,623
Throughput (MBbls/d) for crude/NGL assets⁽⁴⁾	186			154			62			44			33
Key Performance Metrics (for the year ended):
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets^{(5) (6)}	$	1,119,555		$	993,397		$	775,040		$	615,177		$	572,976
Adjusted gross margin for crude/NGL assets^{(5) (7)}	131,492			103,102			31,664			20,776			4,051
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets⁽⁸⁾	0.74			0.71			0.62			0.56			0.60
Adjusted gross margin per Bbl for crude/NGL assets⁽⁹⁾	1.93			1.84			1.40			1.29			0.34
Adjusted EBITDA attributable to Western Gas Partners, LP⁽⁵⁾	907,568			782,900			539,401			428,986			398,516
Distributable cash flow⁽⁵⁾	781,383			661,133			455,238			355,559			352,505

⁽¹⁾

Financial information for the year ended December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information for the years ended December 31, 2014, 2013, 2012 and 2011, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽²⁾

Net income (loss) earned on and subsequent to the date of our acquisitions of Partnership assets is allocated to the general partner and the limited partners, including any subordinated and Class C unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. For periods prior to our acquisition of the Partnership assets, all income is attributed to Anadarko. All subordinated units were converted into common units on August 15, 2011, on a one-for-one basis. For purposes of calculating net income (loss) per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.


⁽³⁾	Includes affiliate, third-party and equity investment throughput, excluding the noncontrolling interest owners’ proportionate share of throughput.


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

⁽⁵⁾

Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. For definitions and reconciliations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see the caption How We Evaluate Our Operations under Item 7 of Exhibit 99.2 to this Current Report on Form 8-K.


⁽⁶⁾	Calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product.


⁽⁷⁾	Calculated as total revenues and other for crude/NGL assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude/NGL assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests, which are measured in barrels.


⁽⁸⁾	Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined above) divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.


⁽⁹⁾	Average for period. Calculated as Adjusted gross margin for crude/NGL assets (as defined above), divided by total throughput (MBbls/d) for crude/NGL assets.

EXHIBIT 99.2

COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refer to Western Gas Partners, LP and its subsidiaries. As generally used within the energy industry and in this Item 7 of Exhibit 99.2 to this Current Report on Form 8-K, the identified terms and definitions have the following meanings:

Affiliates: Subsidiaries of Anadarko, excluding us, and includes 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 interest in the Larry’s Creek, Seely and Warrensville gas gathering systems.

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 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: The 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.

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

Dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see the caption How We Evaluate Our Operations in this Item 7 of Exhibit 99.2 to this Current Report on Form 8-K.

Fort Union: Fort Union Gas Gathering, LLC.

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

FRP: Front Range Pipeline LLC.

GAAP: Generally accepted accounting principles in the United States.

General partner or GP: Western Gas Holdings, LLC.

IDRs: Incentive distribution rights.

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.

MBbls/d: One thousand barrels per day.

MGR: Mountain Gas Resources, LLC.

MGR assets: The Red Desert complex, the Granger straddle plant and the 22% interest in Rendezvous.

MIGC: MIGC, LLC.

MLP: Master limited partnership.

MMBtu: One million British thermal units.

MMcf/d: One million cubic feet per day.

Mont Belvieu JV: Enterprise EF78 LLC.

Non-Operated Marcellus Interest: Our interest in the Liberty and Rome gas gathering systems.

Nuevo: Nuevo Midstream, LLC.

NYSE: New York Stock Exchange.

NYMEX: New York Mercantile Exchange.

OTTCO: Overland Trail Transmission, LLC.

RCF: The senior unsecured revolving credit facility.

Receipt point: The point where volumes are received by or into a gathering system, processing facility or transportation pipeline.

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 gas gathering system: Springfield’s 50.1% interest in the Springfield gas gathering system, which consists of gas gathering lines located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.

Springfield oil gathering system: Springfield’s 50.1% interest in the Springfield oil gathering system, which consists of oil gathering lines 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.

TEG: Texas Express Gathering LLC.

TEP: Texas Express Pipeline LLC.

Wellhead: The point at which the hydrocarbons and water exit the ground.

WGP: Western Gas Equity Partners, LP.

WGRI: Western Gas Resources, Inc.

White Cliffs: White Cliffs Pipeline, LLC.

2018 Notes: 2.600% Senior Notes due 2018.

2021 Notes: 5.375% Senior Notes due 2021.

2022 Notes: 4.000% Senior Notes due 2022.

2025 Notes: 3.950% Senior Notes due 2025.

2044 Notes: 5.450% Senior Notes due 2044.

$125.0 million COP: The registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units.

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

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our consolidated financial statements and notes to consolidated financial statements, which are included under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K, and the information set forth in Risk Factors under Part I, Item 1A of our 2015 Form 10-K.

The term “Partnership assets” refers to the assets owned, including the Springfield system, and interests accounted for under the equity method (see Note 9—Equity Investments in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K) by us as of December 31, 2015. Because Anadarko controls us through its ownership and control of WGP, which owns the entire interest in our general partner, each of our acquisitions of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Further, after an acquisition of Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of such Partnership assets from the date of common control. For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko, including the Springfield system, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the Partnership assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership assets prior to our acquisitions from Anadarko as being “our” historical financial results.

EXECUTIVE SUMMARY

We are a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream energy assets. We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), North-central Pennsylvania and Texas, and are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. See Note 14—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for information regarding certain material events occurring subsequent to December 31, 2015.

As of December 31, 2015, our 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	12	7	—	3
Natural gas processing plants/trains ⁽¹⁾	18	5	—	2
NGL pipelines	2	—	—	3
Natural gas pipelines	4	—	—	—
Oil pipelines	—	1	—	1


⁽¹⁾	On December 3, 2015, an incident occurred at our DBM complex. See below and General Trends and Outlook within this Item 7.

In addition to the acquisition of Springfield in March 2016 (see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K), significant financial and operational events during the year ended December 31, 2015, included the following:

•

On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex, damaging the liquid handling facilities and amine treating units at the complex inlet. There was no damage to Trains IV and V, which were under construction at the time of the incident; however, Trains II and III sustained some damage. See General Trends and Outlook within this Item 7 for additional information.


•	We completed the acquisition of DBJV from Anadarko. See Acquisitions and Divestitures under Part I, Items 1 and 2 of our 2015 Form 10-K for additional information.


•	In July 2015, we closed on the sale of our Dew and Pinnacle systems, which resulted in net proceeds of $145.6 million, after closing adjustments, and a net gain on divestiture of $77.3 million.


•	We completed the offering of $500.0 million aggregate principal amount of 2025 Notes in June 2015. Net proceeds were used to repay a portion of the amount outstanding under our RCF. See Liquidity and Capital Resources within this Item 7 for additional information.


•	In June 2015, we completed the construction and commenced operations of Lancaster Train II, a 300 MMcf/d processing plant located within the DJ Basin complex in Northeast Colorado.


•	We issued 873,525 common units to the public under our $500.0 million COP, generating net proceeds of $57.4 million. Net proceeds were used for general partnership purposes, including funding capital expenditures. See Equity Offerings under Part I, Items 1 and 2 of our 2015 Form 10-K for additional information.


•	We raised our distribution to $0.800 per unit for the fourth quarter of 2015, representing a 3% increase over the distribution for the third quarter of 2015 and a 14% increase over the distribution for the fourth quarter of 2014.


•	Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 4,158 MMcf/d for the year ended December 31, 2015, representing a 9% increase compared to the year ended December 31, 2014.


•	Throughput for crude/NGL assets totaled 186 MBbls/d for the year ended December 31, 2015, representing a 21% increase compared to the year ended December 31, 2014.


•	Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $0.74 per Mcf for the year ended December 31, 2015, representing a 4% increase compared to the year ended December 31, 2014.


•	Adjusted gross margin for crude/NGL assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.93 per Bbl for the year ended December 31, 2015, representing a 5% increase compared to the year ended December 31, 2014.

OUR OPERATIONS

Our results are driven primarily by the volumes of oil, natural gas and NGLs we gather, process, treat or transport through our systems. For the year ended December 31, 2015, 70% of our total revenues and 52% of our throughput (excluding equity investment throughput and throughput measured in barrels) were attributable to transactions with Anadarko. We also recognized capital contributions from Anadarko of $18.4 million related to the above-market component of our commodity price swap agreements with Anadarko (see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). We receive significant dedications from our largest customer, Anadarko. With respect to our Wattenberg, Haley, Helper, Clawson and Hugoton gathering systems, Anadarko has made dedications to us that will continue to expand as long as additional wells are connected to these gathering systems.

In our gathering operations, we contract with producers and customers to gather natural gas or oil from individual wells located near our gathering systems. We connect wells to gathering lines through which volumes may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end users. We also treat a significant portion of the volumes that we gather so that it will satisfy required specifications for pipeline transportation.

For the year ended December 31, 2015, 92% of our gross margin and equity income was attributable to fee-based contracts, under which a fixed fee is received based on the volume or thermal content of the natural gas and on the volume of oil or NGLs we gather, process, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements.

For the year ended December 31, 2015, 8% of our gross margin, including gross margin attributable to condensate sales, was attributable to percent-of-proceeds and keep-whole contracts, pursuant to which we have commodity price exposure. A majority of the commodity price risk associated with our percent-of-proceeds and keep-whole contracts is hedged under commodity price swap agreements with Anadarko, with such agreements set to expire on December 31, 2016. For the year ended December 31, 2015, 98% of our gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements. See Risk Factors under Part I, Item 1A of our 2015 Form 10-K and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

We also have indirect exposure to commodity price risk in that persistent low natural gas prices have caused and may continue to cause our current or potential customers to delay drilling or shut in production in certain areas, which would reduce the volumes of natural gas available for our systems. We also bear a limited degree of commodity price risk through settlement of natural gas imbalances. Read Item 7A under Part II of our 2015 Form 10-K.

As a result of our acquisitions from Anadarko and third parties, our results of operations, financial position and cash flows may vary significantly for 2015, 2014 and 2013 as compared to future periods. See the caption Items Affecting the Comparability of Our Financial Results, set forth below in this Item 7.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput, (2) operating and maintenance expenses, (3) general and administrative expenses, (4) Adjusted gross margin (as defined below), (5) Adjusted EBITDA (as defined below) and (6) Distributable cash flow (as defined below).

Throughput. Throughput is an essential operating variable we use in assessing our ability to generate revenues. In order to maintain or increase throughput on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors. During the year ended December 31, 2015, excluding the Springfield system, we added 199 receipt points to our systems.

Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of such costs on the profitability of our assets and to evaluate the overall efficiency of our operations. Operating and maintenance expenses include, among other things, field labor, insurance, repair and maintenance, equipment rentals, contract services, utility costs and services provided to us or on our behalf. For periods commencing on the date of and subsequent to our acquisition of the Partnership assets, certain of these expenses are incurred under and governed by our services and secondment agreement with Anadarko.

General and administrative expenses. To help ensure the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses through comparison to prior periods, to the annual budget approved by our general partner’s Board of Directors, as well as to general and administrative expenses incurred by similar midstream companies. Pursuant to the omnibus agreement, Anadarko and the general partner perform centralized corporate functions for us. General and administrative expenses for periods prior to our acquisition of the Partnership assets 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. For periods subsequent to our acquisition of the Partnership assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, allocations and reimbursements of general and administrative expenses are determined by Anadarko in its reasonable discretion, in accordance with our partnership and omnibus agreements. Amounts required to be reimbursed to Anadarko under the omnibus agreement also include those expenses attributable to our status as a publicly traded partnership, such as the following:


•	expenses associated with annual and quarterly reporting;


•	tax return and Schedule K-1 preparation and distribution expenses;


•	expenses associated with listing on the NYSE; and


•	independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.

See further detail in Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Non-GAAP financial measures

Adjusted gross margin attributable to Western Gas Partners, LP. We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues and other, less reimbursements for electricity-related expenses recorded as revenue and cost of product, plus distributions from equity investees and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. We believe Adjusted gross margin is an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in our industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds and keep-whole processing contracts, (ii) costs associated with the valuation of our gas imbalances, and (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties. These expenses are subject to variability, although a majority of our exposure to commodity price risk attributable to purchases and sales of natural gas, condensate and NGLs is mitigated through our commodity price swap agreements with Anadarko. For a discussion of commodity price swap agreements, see Risk Factors under Part I, Item 1A of our 2015 Form 10-K and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets and Adjusted gross margin per Bbl for crude/NGL assets. See Key Performance Metrics within this Item 7.

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


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


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


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

Distributable cash flow. We define “Distributable cash flow” as Adjusted EBITDA, plus interest income and the net settlement amounts from the sale and/or purchase of natural gas, drip condensate and NGLs under our commodity price swap agreements to the extent such amounts are not recognized as Adjusted EBITDA, less net cash paid for interest expense (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures and income taxes. We compare Distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the Coverage ratio of distributable cash flow to planned cash distributions. We believe Distributable cash flow is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships.

While Distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period. Furthermore, to the extent Distributable cash flow includes realized amounts recorded as capital contributions from Anadarko attributable to activity under our commodity price swap agreements, Distributable cash flow is not a reflection of our ability to generate cash from operations.

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

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

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



	Year Ended December 31,
thousands	2015		2014			2013
Reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to Operating income (loss)
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets	$	1,119,555	$	993,397		$	775,040
Adjusted gross margin for crude/NGL assets	131,492		103,102			31,664
Adjusted gross margin attributable to Western Gas Partners, LP	1,251,047		1,096,499			806,704
Adjusted gross margin attributable to noncontrolling interest	16,779		20,183			17,416
Gain (loss) on divestiture and other, net ⁽¹⁾	57,024		(9		)	—
Equity income, net	71,251		57,836			22,948
Reimbursed electricity-related charges recorded as revenues	54,175		39,338			20,450
Less:
Distributions from equity investees	98,298		81,022			22,136
Operation and maintenance	331,972		293,710			235,971
General and administrative	41,319		38,561			34,766
Property and other taxes	33,288		28,889			26,243
Depreciation and amortization	272,611		211,809			172,863
Impairments	515,458		5,125			49,920
Operating income (loss)	$	157,330	$	554,731		$	325,619


⁽¹⁾	See Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.



	Year Ended December 31,
thousands	2015			2014			2013
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net income (loss) attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	907,568		$	782,900		$	539,401
Less:
Distributions from equity investees	98,298			81,022			22,136
Non-cash equity-based compensation expense	4,402			4,095			3,575
Interest expense	113,872			76,766			51,797
Income tax expense	45,532			39,061			6,524
Depreciation and amortization ⁽¹⁾	270,004			209,240			170,322
Impairments	515,458			5,125			49,920
Other expense ⁽¹⁾	1,290			—			175
Add:
Gain (loss) on divestiture and other, net ⁽²⁾	57,024			(9		)	—
Equity income, net	71,251			57,836			22,948
Interest income – affiliates	16,900			16,900			16,900
Other income ^{(1) (3)}	219			325			419
Income tax benefit	—			—			2,209
Net income (loss) attributable to Western Gas Partners, LP	$	4,106		$	442,643		$	277,428
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	907,568		$	782,900		$	539,401
Adjusted EBITDA attributable to noncontrolling interest	12,699			16,583			13,348
Interest income (expense), net	(96,972		)	(59,866		)	(34,897		)
Uncontributed cash-based compensation awards	(214		)	(175		)	(54		)
Accretion and amortization of long-term obligations, net	17,698			2,736			2,449
Current income tax benefit (expense)	(34,186		)	(379		)	61,931
Other income (expense), net ⁽³⁾	(619		)	336			253
Distributions from equity investments in excess of cumulative earnings	(16,244		)	(18,055		)	(4,438		)
Changes in operating working capital:
Accounts receivable, net	(4,371		)	1,399			(8,929		)
Accounts and imbalance payables and accrued liabilities, net	1,006			(34,980		)	34,319
Other	(720		)	3,996			(2,048		)
Net cash provided by operating activities	$	785,645		$	694,495		$	601,335
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	785,645		$	694,495		$	601,335
Net cash used in investing activities	(500,277		)	(2,740,175		)	(1,858,912		)
Net cash provided by (used in) financing activities	(254,389		)	2,011,970			938,324


⁽¹⁾	Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex. For the year ended December 31, 2015, other expense also includes $0.4 million of lower of cost or market inventory adjustments at our DBM complex.


⁽²⁾	See Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.


⁽³⁾	Excludes income of zero, $0.5 million and $1.6 million for the years ended December 31, 2015, 2014 and 2013, respectively, related to a component of a gas processing agreement accounted for as a capital lease.



	Year Ended December 31,
thousands except Coverage ratio	2015				2014			2013
Reconciliation of Distributable cash flow to Net income (loss) attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	781,383			$	661,133		$	455,238
Less:
Distributions from equity investees	98,298				81,022			22,136
Non-cash equity-based compensation expense	4,402				4,095			3,575
Interest expense, net (non-cash settled) ⁽¹⁾	14,400				—			—
Income tax (benefit) expense	45,532				39,061			4,315
Depreciation and amortization ⁽²⁾	270,004				209,240			170,322
Impairments	515,458				5,125			49,920
Above-market component of swap extensions with Anadarko ⁽³⁾	18,449				—			—
Other expense ⁽²⁾	1,290				—			175
Add:
Gain (loss) on divestiture and other, net ⁽⁴⁾	57,024				(9		)	—
Equity income, net	71,251				57,836			22,948
Cash paid for maintenance capital expenditures⁽²⁾	53,882				52,159			36,769
Capitalized interest ⁽⁵⁾	8,318				9,832			11,945
Cash paid for (reimbursement of) income taxes	(138		)		(90		)	552
Other income ^{(2) (6)}	219				325			419
Net income (loss) attributable to Western Gas Partners, LP	$	4,106			$	442,643		$	277,428
Distributions declared ⁽⁷⁾
Limited partners	$	392,077
General partner	179,610
Total	$	571,687
Coverage ratio	1.37			x


⁽¹⁾	Includes accretion expense related to the Deferred purchase price obligation - Anadarko. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.


⁽²⁾	Includes our 75% share of depreciation and amortization; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex. For the year ended December 31, 2015, other expense also includes $0.4 million of lower of cost or market inventory adjustments at our DBM complex.


⁽³⁾	See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.


⁽⁴⁾	See Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.


⁽⁵⁾	For the year ended December 31, 2013, includes capitalized interest of $1.4 million for the construction of the Mont Belvieu JV fractionation trains, reflected as a component of the equity investment balance.


⁽⁶⁾	Excludes income of zero, $0.5 million and $1.6 million for the years ended December 31, 2015, 2014 and 2013, respectively, related to a component of a gas processing agreement accounted for as a capital lease.


⁽⁷⁾	Reflects cash distributions of $3.050 per unit declared for the year ended December 31, 2015.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Gathering and processing agreements. The gathering agreements of our initial assets, the Non-Operated Marcellus Interest systems and the Springfield system allow for rate resets that target a return on invested capital in those assets over the life of the agreement. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Commodity price swap agreements. We have 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. On December 31, 2014, our commodity price swap agreements for the Hilight and Newcastle systems and the Granger complex expired without renewal.

On June 25, 2015, we extended our 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. 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. Revenues or costs attributable to volumes settled during the respective extension period, at the applicable market price, 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. See Risk Factors under Part I, Item 1A of our 2015 Form 10-K and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for further information.

Income taxes. Income we have earned on and subsequent to the date of the acquisition of the Partnership assets is subject only to Texas margin tax because we are a non-taxable entity for U.S. federal income tax purposes.

With respect to assets acquired from Anadarko, we record Anadarko’s historic current and deferred income taxes for the periods prior to our ownership of the assets. For periods subsequent to our acquisitions from Anadarko, we are not subject to tax except for the Texas margin tax and, accordingly, do not record current and deferred federal income taxes related to such assets.

Acquisitions and divestitures. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for additional information.

•

DBM acquisition. In November 2014, we acquired Nuevo Midstream, LLC from a third party. Following the acquisition, we changed the name of Nuevo to Delaware Basin Midstream, LLC. We financed the acquisition with the issuance of $750.0 million of Class C units to a subsidiary of Anadarko, borrowings under our RCF and cash on hand, including the proceeds from the November 2014 equity offering. These assets have been recorded in our consolidated financial statements at their estimated fair values on the acquisition date under the acquisition method of accounting. Results of operations attributable to the DBM acquisition were included in our consolidated statement of income beginning on the acquisition date in the fourth quarter of 2014.

•

DBJV acquisition. In March 2015, we acquired Anadarko’s interest in DBJV. We will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. We currently estimate the future payment will be $282.8 million, the net present value of which was $174.3 million as of the acquisition date. 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 was $14.4 million for the year ended December 31, 2015, and zero for each of the years ended December 31, 2014 and 2013, and has been recorded as a charge to interest expense.


•	Dew and Pinnacle divestiture. In July 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 (loss) on divestiture and other, net in the consolidated statements of income.

DBM complex. On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. For the year ended December 31, 2015, the Partnership has recorded $20.3 million of losses in Gain (loss) 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. See General Trends and Outlook below for additional information.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from expected results. See Note 14—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for information regarding certain material events occurring subsequent to December 31, 2015.

Impact of crude oil, natural gas and NGL prices. Crude oil, natural gas and NGL prices can fluctuate significantly, which affects our customers’ activity levels, and thus our throughput, revenues, distributable cash flow and capital spending plans. For example, NYMEX West Texas Intermediate crude oil daily settlement prices ranged from a high of $107.26 per barrel in June 2014 to a low of $26.21 per barrel in February 2016. Daily settlement prices for NYMEX Henry Hub natural gas ranged from a high of $6.15 per MMBtu to a low of $1.76 per MMBtu during in December 2015. The duration and magnitude of the recent decline in crude oil prices cannot be predicted. This decline in crude oil prices will likely result in most, if not all, of our customers, including Anadarko, significantly reducing capital expenditures in 2016 as compared to recent years.

Furthermore, over the last five years, the relatively low natural gas price environment has led to lower levels of drilling activity in dry-gas basins served by certain of our assets. Several of our customers, including Anadarko, have reduced activity levels in those areas, shifting capital toward liquid-rich opportunities that offer higher margins and superior economics. This trend has resulted in fewer new well connections and, in some cases, temporary curtailments of production in those areas. To the extent opportunities are available, we will continue to connect new wells to our systems to mitigate the impact of natural production declines in order to maintain throughput on our systems. However, our success in connecting new wells to our systems is dependent on the activities of natural gas producers and shippers.

Many of our customers, including Anadarko, have a variety of investment opportunities and the financial strength and operational flexibility to move capital spending from areas focused on near-term production growth to longer-dated projects. We will continue to evaluate the crude oil and natural gas price environments and adjust capital spending plans as prices fluctuate while maintaining the appropriate liquidity and financial flexibility.

During 2015, we recognized significant impairments at our Red Desert complex and Hilight system, primarily as a result of a reduction in future cash flows caused by the low commodity price environment noted above and the resulting reduced producer drilling activity and related throughput. It is reasonably possible that prolonged low or further declines in commodity prices could result in additional impairments.

Liquidity and access to capital markets. We require periodic access to capital in order to fund acquisitions and expansion projects. Under the terms of our partnership agreement, we are required to distribute all of our available cash to our unitholders, which makes us dependent upon raising capital to fund growth projects. Historically, MLPs have accessed the debt and equity capital markets to raise money for new growth projects and acquisitions. Market turbulence has from time to time either raised the cost of capital markets financing or, in some cases, temporarily made such financing unavailable. If we are unable either to access the capital markets or find alternative sources of capital, our growth strategy may be more challenging to execute.

Our sources of liquidity as of December 31, 2015, included cash and cash equivalents, cash flows generated from operations, interest income on our $260.0 million note receivable from Anadarko, $893.6 million in available borrowing capacity under our RCF, and issuances of additional equity or debt securities. As of December 31, 2015, our long-term debt was rated “BBB-” with a stable outlook by Standard and Poor’s (“S&P”), “BBB-” with a stable outlook by Fitch Ratings (“Fitch”), and “Baa3” with a stable outlook by Moody’s. In February 2016, Moody’s downgraded Anadarko’s senior unsecured ratings from Baa2 to Ba1, with a negative outlook, and downgraded our senior unsecured ratings from Baa3 to Ba1, with a negative outlook. Also in February 2016, S&P affirmed our and Anadarko’s ratings, but changed Anadarko’s outlook from stable to negative. As of the date of filing our 2015 Form 10-K, Fitch had not announced a change in our credit rating; however, we cannot be assured that our credit rating will not be downgraded further. The Moody’s downgrade and any further downgrades in our credit ratings will adversely affect our ability to raise debt in the public debt markets, which could negatively impact our cost of capital and ability to effectively execute aspects of our strategy.

Changes in regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and an increasing number of complex federal, state, tribal, local and other laws and regulations such as production restrictions, permitting delays, limitations on hydraulic fracturing and environmental protection regulations. We and our customers must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. For example, regulation of hydraulic fracturing is currently primarily conducted at the state level through permitting and other compliance requirements. If proposed federal legislation is adopted, it could establish an additional level of regulation and permitting. Any changes in statutory regulations or delays in the issuance of required permits may impact both the throughput on and profitability of our systems.

Impact of inflation. Although inflation in the United States has been relatively low in recent years, the U.S. economy could experience a significant inflationary effect from, among other things, the governmental stimulus plans enacted since 2008. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates. Interest rates were at or near historic lows at certain times during 2015. In December 2015, the Federal Open Market Committee raised the target range for the federal funds rate from zero to between 1/4 to 1/2 percent, and signaled that further increases are likely over the medium term. Such increases in the federal funds rate will ultimately result in an increase in our financing costs. Additionally, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and an associated implied distribution yield. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, reduce debt or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors would face similar circumstances.

Acquisition opportunities. As of December 31, 2015, Anadarko’s total domestic midstream asset portfolio, including the Springfield system and excluding the assets we own, consisted of 19 gathering systems, 3,632 miles of pipeline, 10 processing and/or treating facilities and 3 oil pipelines. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time.

As of December 31, 2015, WGP held a 34.6% limited partner interest in us, and through its ownership of our general partner, WGP indirectly held a 1.8% general partner interest in us, and 100% of our IDRs. As of December 31, 2015, other subsidiaries of Anadarko separately held an aggregate 8.5% limited partner interest in us, consisting of common and Class C units. Given Anadarko’s significant interests in us, we believe Anadarko will continue to be motivated to promote and support the successful execution of our business plan and to pursue projects that help to enhance the value of our business. However, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to participate in such transactions. Should Anadarko choose to pursue additional midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. We may also pursue certain asset acquisitions from third parties to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s or third-party production. However, if we do not make additional acquisitions from Anadarko or third parties on economically acceptable terms, our future growth will be limited, and the acquisitions we make could reduce, rather than increase, our cash flows generated from operations on a per-unit basis.

DBM complex. On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. There were no serious injuries and 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 but is expected to be returned to service by the end of 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and is expected to be able to accept limited deliveries of gas in April 2016, and it is expected to return to full service by the end of the second quarter of 2016, along with new liquid handling and amine treating facilities. There was no damage to Trains IV and V, which were under construction at the time of the incident, and they are expected to be completed by the previously announced in-service dates. We have a property damage insurance policy designed to cover costs to repair or rebuild damaged assets (less a $1 million deductible), and business interruption insurance designed to cover lost earnings after January 2, 2016. Insurance claims are in process under both of these policies. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

RESULTS OF OPERATIONS

OPERATING RESULTS

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



	Year Ended December 31,
thousands	2015			2014			2013
Gathering, processing and transportation	$	1,128,838		$	894,034		$	641,085
Natural gas, natural gas liquids and drip condensate sales	617,949			625,905			548,508
Other	5,285			13,438			10,467
Total revenues and other ⁽¹⁾	1,752,072			1,533,377			1,200,060
Equity income, net	71,251			57,836			22,948
Total operating expenses ⁽¹⁾	1,723,017			1,036,473			897,389
Gain (loss) on divestiture and other, net	57,024			(9		)	—
Operating income (loss)	157,330			554,731			325,619
Interest income – affiliates	16,900			16,900			16,900
Interest expense	(113,872		)	(76,766		)	(51,797		)
Other income (expense), net	(619		)	864			1,837
Income (loss) before income taxes	59,739			495,729			292,559
Income tax (benefit) expense	45,532			39,061			4,315
Net income (loss)	14,207			456,668			288,244
Net income attributable to noncontrolling interest	10,101			14,025			10,816
Net income (loss) attributable to Western Gas Partners, LP	$	4,106		$	442,643		$	277,428
Key performance metrics ⁽²⁾
Adjusted gross margin attributable to Western Gas Partners, LP	$	1,251,047		$	1,096,499		$	806,704
Adjusted EBITDA attributable to Western Gas Partners, LP	907,568			782,900			539,401
Distributable cash flow	781,383			661,133			455,238

⁽¹⁾

Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue, drip condensate and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽²⁾

Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption How We Evaluate Our Operations–Non-GAAP financial measures within this Item 7. For reconciliations of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations–Reconciliation to GAAP Measures within this Item 7.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2015” refer to the comparison of the year ended December 31, 2015, to the year ended December 31, 2014, and any increases or decreases “for the year ended December 31, 2014” refer to the comparison of the year ended December 31, 2014, to the year ended December 31, 2013.

Throughput



	Year Ended December 31,
	2015	2014	Inc/ (Dec)		2013	Inc/ (Dec)
Throughput for natural gas assets (MMcf/d)
Gathering, treating and transportation ⁽¹⁾	1,791	1,888	(5	)%	1,647	15	%
Processing ⁽¹⁾	2,331	1,925	21	%	1,758	9	%
Equity investment ⁽²⁾	178	171	4	%	206	(17	)%
Total throughput for natural gas assets	4,300	3,984	8	%	3,611	10	%
Throughput attributable to noncontrolling interest for natural gas assets	142	165	(14	)%	168	(2	)%
Total throughput attributable to Western Gas Partners, LP for natural gas assets	4,158	3,819	9	%	3,443	11	%
Throughput for crude/NGL assets (MBbls/d)
Gathering, treating and transportation	69	64	8	%	45	42	%
Equity investment ⁽³⁾	117	90	30	%	17	NM
Total throughput for crude/NGL assets	186	154	21	%	62	148	%

NM-Not meaningful

⁽¹⁾

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


⁽²⁾	Represents our 14.81% share of average Fort Union and our 22% share of average Rendezvous throughput.


⁽³⁾	Represents our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput, and our 33.33% share of average FRP throughput.

Natural gas assets

Gathering, treating and transportation throughput decreased by 97 MMcf/d for the year ended December 31, 2015, primarily due to the sale of the Dew and Pinnacle systems in July 2015, production declines in the areas around the Anadarko-Operated Marcellus Interest systems, the Bison facility and the Non-Operated Marcellus Interest systems. These decreases were partially offset by higher volumes at the Springfield gas gathering system and at the DBJV system due to increased production.

Gathering, treating and transportation throughput increased by 241 MMcf/d for the year ended December 31, 2014, due to increased throughput on the Non-Operated Marcellus Interest systems as a result of additional well connections, additional throughput on the Anadarko-Operated Marcellus Interest systems after the March 2013 acquisition and higher volumes at the Springfield gas gathering and DBJV systems, partially offset by throughput decreases at the Bison facility due to a period of reduced flow resulting from planned maintenance activity and decreases at the Dew and Pinnacle systems resulting from natural production declines in those areas.

Processing throughput increased by 406 MMcf/d for the year ended December 31, 2015, primarily due to increased production in the area around the DJ Basin complex and the acquisition of DBM in November 2014, partially offset by decreased throughput at the Chipeta complex due to decreased drilling activity in the Uinta Basin.

Processing throughput increased by 167 MMcf/d for the year ended December 31, 2014, primarily due to the start-up of the Brasada complex in June 2013, increased volumes processed at a plant included in the MGR acquisition (the “Granger straddle plant”) and the acquisition of DBM in November 2014.

Equity investment throughput increased by 7 MMcf/d for the year ended December 31, 2015, primarily due to increased throughput at the Rendezvous system, offset by lower throughput at the Fort Union system due to production declines in the area. Equity investment throughput decreased by 35 MMcf/d for the year ended December 31, 2014, primarily due to lower throughput at the Fort Union system due to production declines in the area and volumes being diverted to the third-party Bison pipeline.

Crude/NGL assets

Gathering, treating and transportation throughput increased by 5 MBbls/d for the year ended December 31, 2015, primarily due to increased throughput at the Springfield oil gathering system. Equity investment throughput increased by 27 MBbls/d for the year ended December 31, 2015, due to an increase in volumes from FRP and TEP, and the third quarter 2014 in-service date of a White Cliffs pipeline expansion.

Gathering, treating and transportation throughput increased by 19 MBbls/d for the year ended December 31, 2014, primarily due to increased throughput at the Springfield oil gathering system. Equity investment throughput increased by 73 MBbls/d for the year ended December 31, 2014, primarily due to the start-up of (i) the Mont Belvieu JV fractionation trains, TEP and TEG in the fourth quarter of 2013, and (ii) FRP in March 2014.

Gathering, Processing and Transportation Revenues



	Year Ended December 31,
thousands except percentages	2015		2014		Inc/ (Dec)		2013		Inc/ (Dec)
Gathering, processing and transportation revenues	$	1,128,838	$	894,034	26	%	$	641,085	39	%

Revenues from gathering, processing and transportation increased by $234.8 million for the year ended December 31, 2015, primarily due to increases of (i) $181.1 million at the DJ Basin complex resulting from increased throughput, a higher gathering fee, and the introduction of a condensate handling fee in the first quarter of 2015, (ii) $49.6 million due to the acquisition of DBM in November 2014, (iii) $41.8 million at the Springfield system due to increased throughput, and (iv) $10.0 million at the Brasada complex due to increased throughput and a higher processing fee, as well as revenues from treating services beginning in the first quarter of 2015. These increases were partially offset by decreases of (i) $21.3 million at the Non-Operated Marcellus Interest systems due to a decrease in average gathering rate and throughput, (ii) $13.6 million due to the sale of the Dew and Pinnacle systems in July 2015, and (iii) $10.8 million at the Chipeta complex due to decreased throughput.

Revenues from gathering, processing and transportation increased by $252.9 million for the year ended December 31, 2014, primarily due to increases of (i) $78.8 million resulting from increased throughput at the DJ Basin complex and the start-up of Lancaster Train I in April 2014, (ii) $38.8 million at the Springfield system due to increased throughput, (iii) $35.1 million due to the start-up of the Brasada complex in June 2013, (iv) $30.4 million due to increased throughput at the DBJV system, (v) $28.8 million due to higher throughput on the Non-Operated Marcellus Interest systems, partially offset by a lower average gathering rate, (vi) $12.4 million due to higher throughput and average gathering rate on the Anadarko-Operated Marcellus Interest systems, acquired in March 2013, (vii) $12.0 million due to increased throughput at Train III at the Chipeta complex, as well as the retroactive application of a fee increase in the third quarter of 2014 that was applicable upon Train III being placed into service, (viii) $6.3 million due to new third-party gathering agreements at the Hilight system, and (ix) $3.7 million due to the acquisition of the DBM complex in November 2014.

Natural Gas, Natural Gas Liquids and Drip Condensate Sales



	Year Ended December 31,
thousands except percentages and per-unit amounts	2015		2014		Inc/ (Dec)		2013		Inc/ (Dec)
Natural gas sales ⁽¹⁾	$	242,826	$	167,814	45	%	$	120,917	39	%
Natural gas liquids sales ⁽¹⁾	338,770		418,186		(19	)%	391,619		7	%
Drip condensate sales ⁽¹⁾	36,353		39,905		(9	)%	35,972		11	%
Total	$	617,949	$	625,905	(1	)%	$	548,508	14	%
Average price per unit ⁽¹⁾:
Natural gas (per Mcf)	$	3.28	$	4.16	(21	)%	$	4.54	(8	)%
Natural gas liquids (per Bbl)	21.23		43.58		(51	)%	47.69		(9	)%
Drip condensate (per Bbl)	45.38		80.68		(44	)%	78.91		2	%


⁽¹⁾	Excludes amounts considered above market with respect to our swap extensions at the DJ Basin complex beginning July 1, 2015 and at the Hugoton system beginning October 1, 2015. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

For the year ended December 31, 2015, average natural gas, NGL and drip condensate prices included the effects of commodity price swap agreements attributable to sales for the Hugoton system, the MGR assets and the DJ Basin complex. Beginning July 1, 2015, for the DJ Basin complex and October 1, 2015, for the Hugoton system, average natural gas, NGL and drip condensate prices exclude amounts considered above market that are recorded as capital contributions in the statement of equity and partners’ capital. For the year ended December 31, 2014, average natural gas, NGL and drip condensate prices included the effects of commodity price swap agreements attributable to sales for the Hilight, Hugoton and Newcastle systems, the DJ Basin and Granger complexes, and the MGR assets. On December 31, 2014, our commodity price swap agreements for the Hilight and Newcastle systems and the Granger complex (excluding the Granger straddle plant) expired without renewal. See Risk Factors under Part I, Item 1A of our 2015 Form 10-K and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

The growth in natural gas sales for the year ended December 31, 2015, was primarily due to increases of (i) $76.4 million due to the acquisition of DBM in November 2014 and (ii) $25.6 million at the DJ Basin complex due to an increase in volumes sold. These increases were partially offset by decreases of $24.7 million at the Hilight system and Granger complex due to a decrease in average price as a result of the expiration of swap agreements in December 2014.

The growth in natural gas sales for the year ended December 31, 2014, was primarily due to increases of (i) $22.0 million at the DJ Basin complex due to an increase in both volumes sold and average swap price, (ii) $15.9 million at the Hilight system due to an increase in volumes sold, partially offset by a decrease in average swap price, (iii) $4.2 million at the Granger complex due to an increase in volumes sold as a result of new plant purchase contracts effective in September 2014, and (iv) $2.2 million at the MGR assets due to an increase in volumes sold.

The decline in NGLs sales for the year ended December 31, 2015, was primarily due to decreases of (i) $113.1 million at the Granger complex and the Hilight system due to a decrease in average price as a result of the expiration of swap agreements in December 2014, (ii) $19.5 million at the Chipeta complex due to a decrease in average price, (iii) $16.1 million at the DJ Basin complex due to a decrease in volumes sold and the partial equity treatment of our above-market swap extensions beginning July 1, 2015 (see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K), and (iv) $10.0 million at the MGR assets due to a decrease in volumes sold. These decreases were partially offset by an increase of $82.5 million due to the acquisition of DBM in November 2014.

The growth in NGLs sales for the year ended December 31, 2014, was primarily due to increases of (i) $21.2 million at the DJ Basin complex due to an increase in volumes sold, partially offset by a decrease in average swap price, (ii) $10.5 million at the Hilight system due to higher volumes processed and sold, partially offset by a decrease in average swap price, and (iii) $8.0 million at the Chipeta complex due to an increase in volumes sold, partially offset by a decrease in average price. These increases were partially offset by a $14.0 million decrease at the MGR assets due to a decrease in volumes sold.

The decline in drip condensate sales for the year ended December 31, 2015, was primarily due to decreases of (i) $1.8 million at the DBJV system due to a decrease in volumes sold and (ii) $1.4 million at the DJ Basin complex due to the partial equity treatment of our above-market swap extensions beginning July 1, 2015 (see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K).

The increase in drip condensate sales for the year ended December 31, 2014, was primarily due to an increase of $6.0 million at the DJ Basin complex from an increase in volumes sold and average swap price, partially offset by a decrease of $1.4 million at the Hugoton system due to a decrease in volumes sold.

Equity Income, Net



	Year Ended December 31,
thousands except percentages	2015		2014		Inc/ (Dec)		2013		Inc/ (Dec)
Equity income, net	$	71,251	$	57,836	23	%	$	22,948	152	%

For the year ended December 31, 2015, equity income, net increased by $13.4 million, primarily due to a full year of equity income recognized from the TEFR Interests in 2015 and the third quarter 2014 in-service date of a White Cliffs pipeline expansion. These increases were partially offset by our 14.81% share of an impairment loss determined by the managing partner of Fort Union, and a decrease in equity income from the Mont Belvieu JV. For the year ended December 31, 2014, equity income, net increased by $34.9 million, primarily driven by the start-up of (i) the Mont Belvieu JV fractionation trains in the fourth quarter of 2013, (ii) TEG and TEP in the fourth quarter of 2013 and (iii) FRP in March 2014.

Cost of Product and Operation and Maintenance Expenses



	Year Ended December 31,
thousands except percentages	2015		2014		Inc/ (Dec)		2013		Inc/ (Dec)
NGL purchases ⁽¹⁾	$	249,397	$	228,107	9	%	$	191,760	19	%
Residue purchases ⁽¹⁾	252,585		187,626		35	%	156,799		20	%
Other ⁽¹⁾	26,387		42,646		(38	)%	29,067		47	%
Cost of product	528,369		458,379		15	%	377,626		21	%
Operation and maintenance	331,972		293,710		13	%	235,971		24	%
Total cost of product and operation and maintenance expenses	$	860,341	$	752,089	14	%	$	613,597	23	%


⁽¹⁾	Excludes amounts considered above market with respect to our swap extensions at the DJ Basin complex beginning July 1, 2015, and at the Hugoton system beginning October 1, 2015. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Cost of product expense for the year ended December 31, 2015, included the effects of commodity price swap agreements attributable to purchases for the Hugoton system, the MGR assets and the DJ Basin complex. Beginning July 1, 2015, for the DJ Basin complex and October 1, 2015, for the Hugoton system, average natural gas, NGL and drip condensate prices exclude amounts considered above market that are recorded as capital contributions in the statement of equity and partners’ capital. Cost of product expense for the years ended December 31, 2014 and 2013, included the effects of commodity price swap agreements attributable to purchases for the Hilight, Hugoton and Newcastle systems, the DJ Basin and Granger complexes and the MGR assets. On December 31, 2014, our commodity price swap agreements for the Hilight and Newcastle systems and the Granger complex (excluding the Granger straddle plant) expired without renewal. See Risk Factors under Part I, Item 1A of our 2015 Form 10-K and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

The increase in NGL purchases for the year ended December 31, 2015, was primarily due to an increase of $80.2 million due to the acquisition of the DBM complex in November 2014, partially offset by decreases of (i) $46.0 million at the Hilight system and Granger complex due to decreases in average prices as a result of the expiration of swap agreements in December 2014 and (ii) $14.8 million at the Chipeta complex due to a decrease in average price.

The increase in residue purchases for the year ended December 31, 2015, was primarily due to increases of (i) $75.7 million due to the acquisition of DBM in November 2014 and (ii) $37.2 million at the DJ Basin complex due to an increase in volume. These increases were partially offset by decreases of (i) $40.0 million at the Granger complex and the Hilight system due to decreases in average prices as a result of the expiration of swap agreements in December 2014 and (ii) $4.4 million at the Granger straddle plant due to a decrease in volume.

The decrease in other items for the year ended December 31, 2015, was primarily due to changes in imbalance positions at the DJ Basin complex.

The increase in operation and maintenance expense for the year ended December 31, 2015, was primarily due to an increase of $41.1 million due to the acquisition of DBM in November 2014, partially offset by a decrease of $6.9 million due to the divestiture of the Dew and Pinnacle systems in July 2015.

The increase in NGL purchases for the year ended December 31, 2014, was primarily due to increases of (i) $36.7 million at the DJ Basin and Chipeta complexes and the Hilight system due to increases in volumes and (ii) $6.2 million due to the acquisition of DBM in November 2014, these increases were partially offset by a decrease of $7.4 million at the Red Desert complex due to a decrease in volume.

The increase in residue purchases for the year ended December 31, 2014, was primarily due to an increase of $29.5 million at the Hilight system, the DJ Basin and Chipeta complexes and the Granger straddle plant due to increases in volumes.

The increase in other items for the year ended December 31, 2014, was primarily due to changes in imbalance positions at the DJ Basin complex.

The increase in operation and maintenance expense for the year ended December 31, 2014, was primarily due to increases of (i) $13.8 million for plant repairs and maintenance primarily at the Hilight and Springfield systems, and the DJ Basin and Brasada complexes, (ii) $28.4 million in utilities, contract labor and consulting, water and treating costs at the DJ Basin, Brasada and Chipeta complexes and the DBJV system, (iii) $4.4 million increase in property, facility and overhead expense attributable to the Non-Operated Marcellus Interest systems and (iv) $1.8 million increase in equipment rental expense primarily attributable to the Springfield system.

General and Administrative, Depreciation and Amortization, Impairments and Other Expenses



	Year Ended December 31,
thousands except percentages	2015		2014		Inc/ (Dec)		2013		Inc/ (Dec)
General and administrative	$	41,319	$	38,561	7	%	$	34,766	11	%
Property and other taxes	33,288		28,889		15	%	26,243		10	%
Depreciation and amortization	272,611		211,809		29	%	172,863		23	%
Impairments	515,458		5,125		NM		49,920		(90	)%
Total general and administrative, depreciation and amortization, impairments and other expenses	$	862,676	$	284,384	NM		$	283,792	—	%

NM-Not meaningful

General and administrative expenses increased by $2.8 million for the year ended December 31, 2015, primarily due to increases of (i) $1.3 million in personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement, (ii) $0.9 million in pre-acquisition management services fees for expenses incurred by Anadarko related to Springfield, (iii) $0.5 million in consulting and audit fees and (iv) $0.3 million in non-cash compensation expenses.

General and administrative expenses increased by $3.8 million for the year ended December 31, 2014, primarily due to increases of (i) $3.2 million in personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement, (ii) an increase of $0.5 million in non-cash compensation expenses and (iii) $0.5 million in consulting and audit fees. These increases were partially offset by a $1.1 million decrease in pre-acquisition management services fees for expenses incurred by Anadarko related to Springfield.

Property and other taxes increased by $4.4 million for the year ended December 31, 2015, primarily due to ad valorem tax increases of $3.7 million at the DJ Basin complex and $2.5 million due to the acquisition of DBM in November 2014, partially offset by a decrease of $2.3 million due to the divestiture of the Dew and Pinnacle systems in July 2015.

Property and other taxes increased by $2.6 million for the year ended December 31, 2014, primarily due to ad valorem tax increases of $2.6 million associated with capital additions at the Chipeta complex and Springfield system, the completion of the Brasada complex in June 2013, the start-up of Train I at the Lancaster plant in April 2014 and the acquisition of the DBM complex in November 2014. These increases were offset by a decrease of $0.3 million in accrued ad valorem taxes at the Hugoton system.

Depreciation and amortization increased by $60.8 million for the year ended December 31, 2015, primarily due to depreciation expense increases of (i) $42.9 million due to the acquisition of DBM in November 2014, (ii) $20.8 million associated with the completion of numerous compression projects and the start-up of Lancaster Train I in April 2014 at the DJ Basin complex and (iii) $10.4 million at the Hilight, DBJV, Haley and Springfield systems. These increases were partially offset by decreases of (i) $7.1 million due to the divestiture of the Dew and Pinnacle systems in July 2015 and (ii) $9.8 million due to the impact of the impairment at the Red Desert complex during 2015.

Depreciation and amortization increased by $38.9 million for the year ended December 31, 2014, primarily attributable to increases of (i) $16.5 million associated with the start-up of Train I at the Lancaster plant in April 2014 and compression expansion capital projects at the DJ Basin complex, (ii) $4.6 million due to the acquisition of the DBM complex in November 2014, (iii) $3.9 million due to the completion of the Brasada complex in June 2013, (iv) $3.8 million at the Non-Operated Marcellus Interest systems due to additional capital projects, (v) $2.1 million related to the September 2013 acquisition of OTTCO, and (vi) $5.5 million at the Hilight and Springfield systems and the Anadarko-Operated Marcellus Interest systems related to capital projects.

Impairment expense increased by $510.3 million for the year ended December 31, 2015, 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, impairment expense increased by $9.2 million primarily due to (i) the abandonment of compressors at the MIGC system and DJ Basin complex and (ii) the cancellation of projects at the Non-Operated Marcellus Interest systems, Anadarko-Operated Marcellus Interest systems, the DBJV system and the DJ Basin, Brasada and Red Desert 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. See Risk Factors under Part I, Item 1A of our 2015 Form 10-K.

Impairment expense decreased by $44.8 million for the year ended December 31, 2014, primarily due to an impairment of $48.7 million at the Springfield system recognized during the year ended December 31, 2013, primarily related to a gathering system that was impaired to its estimated fair value of $14.4 million prior to the disposition of such gathering system by Springfield in 2014, using the income approach and Level 3 fair value inputs. This impairment was triggered by a reduction in estimated future cash flows caused by downward reserve revisions by producers based on lease expirations and the decision to suspend a drilling program in the area. This decrease was offset by increases of (i) $1.0 million in the first quarter of 2014 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, with no comparative activity in the prior period and (ii) $0.8 million due to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems in 2014.

Interest Income – Affiliates and Interest Expense



	Year Ended December 31,
thousands except percentages	2015			2014			Inc/ (Dec)		2013			Inc/ (Dec)
Note receivable – Anadarko	$	16,900		$	16,900		—	%	$	16,900		—	%
Interest income – affiliates	$	16,900		$	16,900		—	%	$	16,900		—	%
Third parties
Long-term debt	$	(102,058	)	$	(81,495	)	25	%	$	(59,293	)	37	%
Amortization of debt issuance costs and commitment fees	(5,734		)	(5,103		)	12	%	(4,449		)	15	%
Capitalized interest	8,318			9,832			(15	)%	11,945			(18	)%
Affiliates
Deferred purchase price obligation – Anadarko ⁽¹⁾	(14,398		)	—			—	%	—			—	%
Interest expense	$	(113,872	)	$	(76,766	)	48	%	$	(51,797	)	48	%


⁽¹⁾	See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for a discussion of the accretion and present value of the Deferred purchase price obligation - Anadarko.

Interest expense increased by $37.1 million for the year ended December 31, 2015, primarily due to (i) $14.4 million in accretion recorded to interest expense for the Deferred purchase price obligation - Anadarko, (ii) $11.4 million in interest incurred on the 2025 Notes issued in June 2015, (iii) $4.8 million of interest incurred on the 2044 Notes issued in March 2014, (iv) additional interest incurred on the RCF of $3.9 million as a result of higher average borrowings outstanding, and (v) $0.6 million of interest incurred on the additional 2018 Notes issued in March 2014. Capitalized interest decreased by $1.5 million for the year ended December 31, 2015, primarily due to the completion of Lancaster Train I in April 2014 and Lancaster Train II in June 2015 (both within the DJ Basin complex). This decrease was partially offset by an increase due to the construction of Trains IV and V at the DBM complex (acquired in November 2014). See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Interest expense increased by $25.0 million for the year ended December 31, 2014, primarily due to interest expense incurred on the 2044 Notes of $17.0 million, as well as additional interest incurred on the 2018 Notes of $6.1 million. Amortization of debt issuance costs and commitment fees increased by $0.7 million for the year ended December 31, 2014, primarily due to higher commitment fees driven by the amendment and restatement of the RCF from $800.0 million to $1.2 billion in February 2014. Capitalized interest decreased by $2.1 million for the year ended December 31, 2014, primarily due to the completion of the Brasada complex in June 2013, partially offset by an increase in capitalized interest for the construction of Lancaster Train II (within the DJ Basin complex). See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Income Tax (Benefit) Expense



	Year Ended December 31,
thousands except percentages	2015			2014			Inc/ (Dec)		2013			Inc/ (Dec)
Income (loss) before income taxes	$	59,739		$	495,729		(88	)%	$	292,559		69	%
Income tax (benefit) expense	45,532			39,061			17	%	4,315			NM
Effective tax rate	76		%	8		%			1		%

NM-Not meaningful

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

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. We are required to include the impact of the law change on our deferred state income taxes in the period enacted. The adjustment, a reduction in deferred state income taxes in the amount of $2.2 million, was recorded in June 2015 and is included in the income tax (benefit) expense for the year ended December 31, 2015.

Income attributable to (i) the Springfield system prior to and including February 2016, (ii) the DBJV system prior to and including February 2015, (iii) the TEFR Interests prior to and including February 2014 and (iv) the Non-Operated Marcellus Interest systems prior to and including February 2013, was subject to federal and state income tax. Income earned on the Springfield system, the DBJV system, the TEFR Interests and the Non-Operated Marcellus Interest systems for periods subsequent to February 2016, February 2015, February 2014 and February 2013, respectively, was only subject to Texas margin tax on income apportionable to Texas.

KEY PERFORMANCE METRICS



	Year Ended December 31,
thousands except percentages and per-unit amounts	2015		2014		Inc/ (Dec)		2013		Inc/ (Dec)
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets ⁽¹⁾	$	1,119,555	$	993,397	13	%	$	775,040	28	%
Adjusted gross margin for crude/NGL assets ⁽²⁾	131,492		103,102		28	%	31,664		NM
Adjusted gross margin attributable to Western Gas Partners, LP⁽³⁾	1,251,047		1,096,499		14	%	806,704		36	%
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets ⁽⁴⁾	0.74		0.71		4	%	0.62		15	%
Adjusted gross margin per Bbl for crude/NGL assets ⁽⁵⁾	1.93		1.84		5	%	1.40		31	%
Adjusted EBITDA attributable to Western Gas Partners, LP ⁽³⁾	907,568		782,900		16	%	539,401		45	%
Distributable cash flow ⁽³⁾	781,383		661,133		18	%	455,238		45	%

NM-Not meaningful

⁽¹⁾

Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure under How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.

⁽²⁾

Adjusted gross margin for crude/NGL assets is calculated as total revenues and other for crude/NGL assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude/NGL assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude/NGL assets to its most comparable GAAP measure under How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.


⁽³⁾	For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.


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


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

Adjusted gross margin. Adjusted gross margin increased by $154.5 million for the year ended December 31, 2015, primarily due to the start-up of Lancaster Train I in April 2014 and Lancaster Train II in June 2015 (both part of the DJ Basin complex), the acquisition of DBM in November 2014 and higher volumes at the Springfield gas gathering system. This increase was partially offset by margin decreases at the Granger complex due to lower average pricing, at the Non-Operated Marcellus Interest systems due to a decrease in the average gathering rate and at the Chipeta complex due to lower volumes, as well as the sale of the Dew and Pinnacle systems in July 2015.

Adjusted gross margin increased by $289.8 million for the year ended December 31, 2014, primarily due to higher margins at the DJ Basin complex (including the start-up of Lancaster Train I in April 2014), the start-up of the Mont Belvieu JV fractionation trains in the fourth quarter of 2013, higher volumes at the Springfield gas gathering system, the start-up of the Brasada complex in June 2013, higher margins at the Non-Operated Marcellus Interest and DBJV systems, the acquisition of the Anadarko-Operated Marcellus Interest in March 2013, the start-up of TEG and TEP in the fourth quarter of 2013, and the start-up of FRP in March 2014.

Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets increased by $0.03 for the year ended December 31, 2015, primarily due to the start-up of Lancaster Train I in April 2014 and Lancaster Train II in June 2015 (both within the DJ Basin complex), the acquisition of DBM in November 2014 and higher volumes at the Springfield gas gathering system.

Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets increased by $0.09 for the year ended December 31, 2014, primarily due to the consolidation of several systems into the DJ Basin complex beginning in 2014, as well as the start-up of Lancaster Train I in April 2014, and higher margins at the Chipeta complex and the Non-Operated Marcellus Interest and Springfield gas gathering systems.

Adjusted gross margin per Bbl for crude/NGL assets increased by $0.09 for the year ended December 31, 2015, due to higher volumes at the Springfield oil gathering system. Adjusted gross margin per Bbl for crude/NGL assets increased by $0.44 for the year ended December 31, 2014, due to higher volumes at the Springfield oil gathering system and distributions received from the Mont Belvieu JV and the TEFR Interests.

Adjusted EBITDA. Adjusted EBITDA increased by $124.7 million for the year ended December 31, 2015, primarily due to a $218.7 million increase in total revenues and other, a $17.3 million increase in distributions from equity investees and a $3.9 million decrease in net income attributable to noncontrolling interest. These amounts were partially offset by a $69.5 million increase in cost of product (net of lower of cost or market inventory adjustments), a $38.3 million increase in operation and maintenance expenses, a $4.4 million increase in property and other tax expense, and a $2.5 million increase in general and administrative expenses excluding non-cash equity-based compensation expense.

Adjusted EBITDA increased by $243.5 million for the year ended December 31, 2014, primarily due to a $333.3 million increase in total revenues and other and a $58.9 million increase in distributions from equity investees. These amounts were offset by an $80.8 million increase in cost of product, a $57.7 million increase in operation and maintenance expenses, a $3.3 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, a $3.2 million increase in net income attributable to noncontrolling interest, and a $2.6 million increase in property and other tax expense.

Distributable cash flow. Distributable cash flow increased by $120.3 million for the year ended December 31, 2015, primarily due to a $124.7 million increase in Adjusted EBITDA and $18.4 million in the above-market component of the swap extensions with Anadarko, where such amount related to the above-market component of swaps did not exist prior to the extensions executed on July 1, 2015. These amounts were partially offset by a $21.2 million increase in net cash paid for interest expense and a $1.7 million increase in cash paid for maintenance capital expenditures.

Distributable cash flow increased by $205.9 million for the year ended December 31, 2014, primarily due to a $243.5 million increase in Adjusted EBITDA, offset by a $22.9 million increase in net cash paid for interest expense and a $15.4 million increase in cash paid for maintenance capital expenditures.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owner. Our sources of liquidity as of December 31, 2015, included cash and cash equivalents, cash flows generated from operations, interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under our RCF, and issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements and other factors, including the extension of commodity price swap agreements, and will be determined by the Board of Directors of our general partner on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. On January 21, 2016, the Board of Directors of our general partner declared a cash distribution to our unitholders of $0.800 per unit, or $152.6 million in aggregate, including incentive distributions, but excluding distributions on Class C units. The cash distribution was paid on February 11, 2016, to unitholders of record at the close of business on February 1, 2016. In connection with the closing of the DBM acquisition in November 2014, we issued Class C units that will receive distributions in the form of additional Class C units until the end of 2017, unless earlier converted (see Note 3—Partnership Distributions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). The Class C unit distribution, if paid in cash, would have been $9.1 million for the fourth quarter of 2015.

Management continuously monitors our leverage position and coordinates our capital expenditure program, quarterly distributions and acquisition strategy with our expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance outstanding debt balances with longer term notes. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statements. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part I, Item 1A of our 2015 Form 10-K.

Working capital. As of December 31, 2015, we had $63.7 million of working capital, which we define as the amount by which current assets exceed current liabilities. Working capital is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable and factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for maintenance and expansion activity. As of December 31, 2015, we had $893.6 million available for borrowing under our RCF. See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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

•

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


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

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



	Year Ended December 31,
thousands	2015		2014		2013
Acquisitions	$	14,417	$	1,902,520	$	716,985

Expansion capital expenditures	$	583,282	$	752,207	$	814,922
Maintenance capital expenditures	54,221		52,615		36,849
Total capital expenditures ^{(1) (2)}	$	637,503	$	804,822	$	851,771

Capital incurred ^{(2) (3)}	$	566,045	$	833,872	$	828,383

⁽¹⁾

Maintenance capital expenditures for the years ended December 31, 2015, 2014 and 2013, are presented net of $0.5 million, $0.2 million and $0.6 million, respectively, of contributions in aid of construction costs from affiliates. Capital expenditures for the year ended December 31, 2015, included $35.7 million of pre-acquisition capital expenditures for the Springfield system, and for the years ended December 31, 2014 and 2013, included $132.0 million and $205.9 million, respectively, of pre-acquisition capital expenditures for the Springfield and DBJV systems.


⁽²⁾	Includes the noncontrolling interest owner’s share of Chipeta’s capital expenditures for all periods presented. For the years ended December 31, 2015, 2014 and 2013, included $8.3 million, $9.8 million and $10.6 million, respectively, of capitalized interest.


⁽³⁾	Capital incurred for the year ended December 31, 2015, included $32.4 million of pre-acquisition capital incurred for the Springfield system, and for the years ended December 31, 2014 and 2013, included $138.5 million and $200.1 million, respectively, of pre-acquisition capital incurred for the Springfield and DBJV systems.

Acquisitions during 2015 included equipment purchases from Anadarko and the post-closing purchase price adjustments related to the DBM acquisition. Acquisitions during 2014 included DBM and the TEFR Interests. Acquisitions during 2013 included OTTCO, the Mont Belvieu JV, the Anadarko-Operated Marcellus Interest and the Non-Operated Marcellus Interest. See Note 2—Acquisitions and Divestitures and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Capital expenditures, excluding acquisitions, decreased by $167.3 million for the year ended December 31, 2015. Expansion capital expenditures decreased by $168.9 million (including a $1.5 million decrease in capitalized interest) for the year ended December 31, 2015, primarily due to a decrease of $200.4 million at the DJ Basin complex related to compression projects in 2014 and less activity in 2015 at the Lancaster plant. In addition, there were decreases of $47.9 million at the Springfield system, $39.9 million at the Hilight system, $14.2 million at the Non-Operated Marcellus Interest systems, $13.9 million at the Anadarko-Operated Marcellus Interest systems, $12.6 million at the Brasada complex and $11.1 million at the Red Desert complex. These decreases were partially offset by an increase of $163.5 million due to the acquisition of DBM in November 2014 and $12.1 million at the DBJV system.

Capital expenditures, excluding acquisitions, decreased by $46.9 million for the year ended December 31, 2014. Expansion capital expenditures decreased by $62.7 million (including a $0.8 million decrease in capitalized interest) for the year ended December 31, 2014, primarily due to a $104.1 million decrease at the Brasada complex due to construction being completed in June 2013, an $89.7 million decrease at the Springfield system, a $68.6 million decrease at the Non-Operated Marcellus Interest systems and a $2.3 million decrease at the Red Desert complex. These decreases were partially offset by an increase of $111.0 million at the DJ Basin complex, related to compression projects and well connections, as well as the continued construction of Lancaster Train II. In addition, there was an increase of $21.7 million at the Haley system, $21.6 million at the Hilight system, $15.8 million at the DBJV system, $13.3 million at the DBM complex, $11.9 million at the Anadarko-Operated Marcellus Interest systems and $6.2 million at the Chipeta complex. Maintenance capital expenditures increased by $15.8 million, primarily as a result of increased expenditures of $4.7 million at the DJ Basin complex, $5.7 million at the Non-Operated Marcellus Interest systems, $2.2 million at the Red Desert complex, $1.9 million at the Springfield system and $1.6 million at the Anadarko-Operated Marcellus Interest systems.

We estimate our total capital expenditures for the year ended December 31, 2016, including our 75% share of Chipeta’s capital expenditures and excluding acquisitions, to be between $450 million and $490 million and our maintenance capital expenditures to be between 7% and 10% of Adjusted EBITDA. Expected 2016 projects include the continued construction of Trains IV, V and VI and the extension of the Ramsey Residue Line at our DBM complex. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us, which are dependent, in part, on the drilling activities of Anadarko and third-party producers. We expect to fund future capital expenditures from cash flows generated from our operations, interest income from our note receivable from Anadarko, borrowings under our RCF, the issuance of additional partnership units or debt offerings.

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



	Year Ended December 31,
thousands	2015			2014			2013
Net cash provided by (used in):
Operating activities	$	785,645		$	694,495		$	601,335
Investing activities	(500,277		)	(2,740,175		)	(1,858,912		)
Financing activities	(254,389		)	2,011,970			938,324
Net increase (decrease) in cash and cash equivalents	$	30,979		$	(33,710	)	$	(319,253	)

Operating Activities. Net cash provided by operating activities during the years ended December 31, 2015 and 2014, increased primarily due to the impact of changes in working capital items. The increase for the year ended December 31, 2014, was driven primarily by changes in accounts payable balances due to the acquisition of DBM and timing of payments made to third-parties.

Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2015, included the following:


•	$637.5 million of capital expenditures, net of $0.5 million of contributions in aid of construction costs from affiliates, primarily related to the construction of Lancaster Train II (within the DJ Basin complex), plant construction at the DBM complex and expansion at the DBJV system;


•	$10.9 million of cash paid for equipment purchases from Anadarko;


•	$11.4 million of cash contributed to equity investments, primarily related to expansion projects at White Cliffs, TEP and FRP;


•	$3.5 million of cash paid for post-closing purchase price adjustments related to the DBM acquisition;


•	$145.6 million of net proceeds from the sale of the Dew and Pinnacle systems in East Texas; and


•	$16.2 million of distributions from equity investments in excess of cumulative earnings.

Net cash used in investing activities for the year ended December 31, 2014, included the following:


•	$1.5 billion of cash paid for the acquisition of DBM, net of $30.6 million of cash acquired;


•	$804.8 million of capital expenditures, net of $0.2 million of contributions in aid of construction costs from affiliates, primarily related to the construction of Lancaster Trains I and II, as well as compression expansion projects, all within the DJ Basin complex;


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


•	$42.0 million of cash paid related to the construction of the Front Range Pipeline, which was completed in March 2014;


•	$22.9 million of cash paid for equipment purchases from Anadarko;


•	$10.5 million of cash paid for White Cliffs expansion projects;


•	$6.6 million of cash paid related to the construction of the Texas Express Pipeline, which was completed in November 2013;


•	$18.1 million of distributions from equity investments in excess of cumulative earnings; and


•	$13.0 million of net proceeds, after closing adjustments, from the sale of a gathering system to a third party in September of 2014.

Net cash used in investing activities for the year ended December 31, 2013, included the following:


•	$851.8 million of capital expenditures, net of $0.6 million of contributions in aid of construction costs from affiliates;


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


•	$236.9 million of capital contributions to TEG, TEP and FRP for construction costs;


•	$134.6 million of cash paid for the Anadarko-Operated Marcellus Interest acquisition;


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


•	$38.7 million of capital contributions to the Mont Belvieu JV to fund our share of construction costs for the fractionation trains completed in the fourth quarter of 2013;


•	$27.5 million of cash paid for the OTTCO acquisition;


•	$19.1 million of cash paid for a White Cliffs expansion project;


•	$11.2 million of cash paid for equipment purchases from Anadarko; and


•	$4.4 million of distributions from equity investments in excess of cumulative earnings.

Financing Activities. Net cash used in financing activities for the year ended December 31, 2015, included the following:


•	$610.0 million of repayments of outstanding borrowings under our RCF;


•	$545.1 million of distributions paid to our unitholders;


•	$49.8 million of net distributions to Anadarko representing intercompany transactions attributable to the acquisitions of Springfield and DBJV;


•	$12.2 million of distributions paid to the noncontrolling interest owner of Chipeta;


•	$489.6 million of net proceeds from the 2025 Notes offering in June 2015, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under our RCF;


•	$400.0 million of borrowings to fund capital expenditures and for general partnership purposes;


•	$57.4 million of net proceeds from sales of common units under the $500.0 million COP (as discussed in Registered Securities within this Item 7). Net proceeds were used for general partnership purposes, including funding capital expenditures; and


•	$18.4 million of capital contribution from Anadarko related to the above-market component of swap extensions (see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K).

Net cash provided by financing activities for the year ended December 31, 2014, included the following:


•	$750.0 million of proceeds from the issuance of Class C units to a subsidiary of Anadarko, all of which was used to fund a portion of the acquisition of DBM;


•	$603.0 million of net proceeds from our November 2014 equity offering, including net proceeds from a capital contribution by our general partner, part of which was used to fund a portion of the acquisition of DBM;


•	$475.0 million of borrowings to fund a portion of the acquisition of DBM;


•	$389.5 million of net proceeds from the 2044 Notes offering in March 2014, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under our RCF;


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


•	$335.0 million of borrowings to fund capital expenditures and general partnership purposes;


•	$100.0 million of net proceeds from the offering of additional 2018 Notes in March 2014, after underwriting discounts, original issue premium and offering costs, part of which was used to repay a portion of the outstanding borrowings under our RCF;


•	$83.2 million of net proceeds from sales of common units under the $125.0 million COP, including net proceeds from capital contributions by our general partner;


•	$18.1 million of net proceeds related to the partial exercise of the underwriters’ over-allotment option granted in connection with our December 2013 equity offering;


•	$650.0 million of repayments of outstanding borrowings under our RCF;


•	$408.6 million of distributions paid to our unitholders;


•	$16.4 million of net distributions to Anadarko representing intercompany transactions attributable to the acquisitions of Springfield, DBJV and the TEFR Interests; and


•	$15.1 million of distributions paid to the noncontrolling interest owner of Chipeta.

Net cash provided by financing activities for the year ended December 31, 2013, included the following:


•	$424.7 million of net proceeds from our May 2013 equity offering, including net proceeds from a capital contribution by our general partner, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;


•	$299.0 million of borrowings to fund capital expenditures;


•	$273.7 million of net proceeds from our December 2013 equity offering, including net proceeds from a capital contribution by our general partner, $215.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;


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


•	$247.6 million of net proceeds from our 2018 Notes offering in August 2013, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our outstanding borrowings under our RCF;


•	$265.5 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisitions of Springfield, the TEFR Interests and the Non-Operated Marcellus Interest;


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


•	$41.8 million of net proceeds from sales of common units under the $125.0 million COP, including net proceeds from capital contributions by our general partner;


•	$27.5 million of borrowings to fund the OTTCO acquisition;


•	$2.2 million of contributions from the noncontrolling interest owners of Chipeta;


•	$710.0 million of repayments of outstanding borrowings under our RCF;


•	$299.1 million of distributions paid to our unitholders; and


•	$13.1 million of distributions paid to the noncontrolling interest owner of Chipeta.

Debt and credit facility. At December 31, 2015, our debt consisted of $500.0 million aggregate principal amount of the 2021 Notes, $670.0 million aggregate principal amount of the 2022 Notes, $350.0 million aggregate principal amount of the 2018 Notes, $400.0 million aggregate principal amount of the 2044 Notes, $500.0 million aggregate principal amount of the 2025 Notes, and $300.0 million of borrowings outstanding under our RCF. As of December 31, 2015, the carrying value of our outstanding debt was $2.7 billion. See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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 our 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 our 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 our RCF and for general partnership purposes.

At December 31, 2015, we were in compliance with all covenants under the indentures governing our outstanding notes.

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 LIBOR, plus applicable margins ranging from 0.975% to 1.45%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, in each case plus applicable margins currently ranging from zero to 0.45%, based upon our senior unsecured debt rating. We are required to pay a quarterly facility fee currently ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), based upon our senior unsecured debt rating. As of December 31, 2015, we 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 interest rate on the RCF was 1.73%, the facility fee rate was 0.20% and we were in compliance with all covenants under the RCF. See Note 14—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

The RCF continues to contain certain covenants that limit, among other things, our ability, and that of certain of our subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of our business, enter into certain affiliate transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions. At December 31, 2015, we were in compliance with all remaining covenants under the RCF.

The 2021 Notes, 2022 Notes, 2018 Notes, 2044 Notes, 2025 Notes and obligations under the RCF are recourse to our general partner. Our general partner is indemnified by a wholly owned subsidiary of Anadarko, WGRI against any claims made against our general partner under the 2022 Notes, 2021 Notes and/or the RCF.

In connection with the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests, our general partner and other wholly owned subsidiaries of Anadarko entered into indemnification agreements, whereby such subsidiaries agreed to indemnify our general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests. These indemnification agreements apply to the 2044 Notes, 2018 Notes and/or RCF borrowings outstanding related to the aforementioned acquisitions.

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

Deferred purchase price obligation - Anadarko. The consideration to be paid 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 our share in the Net Earnings (see definition below) of the DBJV system for the calendar years 2018 and 2019, less (b) our 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 our 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. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Registered securities. We may issue an indeterminate amount of common units and various debt securities under our effective shelf registration statements on file with the SEC. We issue common units under the $500.0 million COP, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of December 31, 2015, we had the capacity to issue additional common units under the $500.0 million COP of up to an aggregate sales price of $441.8 million. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for a discussion of trades completed under the $500.0 million COP.

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

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

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we are exposed to credit risk on the note receivable from Anadarko. We are also party to agreements with Anadarko under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits and income taxes with respect to the assets acquired from Anadarko. Finally, we have entered into various commodity price swap agreements with Anadarko in order to reduce our exposure to a majority of the commodity price risk inherent in our percent-of-proceeds and keep-whole contracts, and are subject to performance risk thereunder. See Risk Factors under Part I, Item 1A of our 2015 Form 10-K and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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

CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual cash obligations as of December 31, 2015. The table below excludes amounts classified as current liabilities on the consolidated balance sheets, other than the current portions of the categories listed within the table. It is expected that the majority of the excluded current liabilities will be paid in cash in 2016.



	Obligations by Period
thousands	2016		2017		2018		2019		2020		Thereafter		Total
Long-term debt
Principal	$	—	$	—	$	350,000	$	300,000	$	—	$	2,070,000	$	2,720,000
Interest	108,052		108,052		104,604		95,948		95,225		657,898		1,169,779
Asset retirement obligations	3,677		1,729		—		370		—		124,855		130,631
Capital expenditures	45,045		—		—		—		—		—		45,045
Credit facility fees	2,400		2,400		2,400		375		—		—		7,575
Environmental obligations	1,136		708		333		278		123		—		2,578
Operating leases	9,076		7,756		733		624		122		—		18,311
Deferred purchase price obligation - Anadarko	—		—		—		—		282,807		—		282,807
Total	$	169,386	$	120,645	$	458,070	$	397,595	$	378,277	$	2,852,753	$	4,376,726

Debt and credit facility fees. For additional information on credit facility fees required under our RCF, see Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties and equipment. Revisions to estimated asset retirement obligations can result from revisions to estimated inflation rates and discount rates, changes in retirement costs and the estimated timing of settlement. For additional information, see Note 11—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Capital expenditures. Included in this amount are capital obligations related to our expansion projects. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual obligations made in advance of the actual expenditures. See Note 13—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Environmental obligations. We are subject to various environmental-remediation obligations arising from federal, state and local laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We regularly monitor the remediation and reclamation process and the liabilities recorded and believe that the amounts reflected in our recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations. For additional information on environmental obligations, see Note 13—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Operating leases. Anadarko, on our behalf, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting our operations, for which it charges us rent. The amounts above represent existing contractual operating lease obligations that may be assigned or otherwise charged to us pursuant to the reimbursement provisions of the omnibus agreement. See Note 13—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Deferred purchase price obligation - Anadarko. We acquired Anadarko’s interest in DBJV in March 2015. We will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. We currently estimate the future payment will be $282.8 million. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

For additional information on contracts, obligations and arrangements we enter into from time to time, see Note 5—Transactions with Affiliates and Note 13—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements in accordance with GAAP requires our management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and affect the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of property, plant and equipment, asset retirement obligations, litigation, environmental liabilities, income taxes and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with the Audit Committee of our general partner. For additional information concerning our accounting policies, see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Depreciation. Depreciation expense is generally computed using the straight-line method over the estimated useful life of the assets. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, depreciation estimates are reviewed to determine if any changes in the underlying assumptions are necessary. The weighted-average life of our long-lived assets is 24 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by $29.0 million, which would result in a corresponding reduction in our operating income (loss).

Impairments of tangible assets. 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 Partnership assets acquired by us from Anadarko are initially recorded at Anadarko’s historic carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. Property, plant and equipment balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.

In assessing long-lived assets for impairments, our management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. Since a significant portion of our revenues arises from gathering, processing and transporting the natural gas production from Anadarko-operated properties, significant downward revisions in reserve estimates or changes in future development plans by Anadarko, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability. Such assessment requires application of judgment regarding the use and ultimate disposition of the asset, long-range revenue and expense estimates, global and regional economic conditions, including commodity prices and drilling activity by our customers, as well as other factors affecting estimated future net cash flows. The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. See Note 7—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for a description of impairments recorded during the years ended December 31, 2015, 2014 and 2013.

Impairments of 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, our 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, our allocated goodwill balance does not represent, and in some cases is significantly different from, the difference between the consideration paid by us for acquisitions from Anadarko and the fair value of such net assets on their respective acquisition dates.

We evaluate whether goodwill has been impaired annually as of October 1, unless facts and circumstances make it necessary to test more frequently. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. Management has determined that we have one operating segment and two reporting units: (i) gathering and processing and (ii) transportation. The carrying value of goodwill as of December 31, 2015, was $414.4 million for the gathering and processing reporting unit and $4.8 million for the transportation reporting unit. In connection with the November 2014 DBM acquisition, we recorded $284.7 million of goodwill. We also allocated $5.1 million of goodwill to our divestiture of the Dew and Pinnacle systems upon sale in July 2015. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

The first step in assessing whether an impairment of goodwill is necessary is a qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is less than its carrying amount, including goodwill. If we conclude it is more likely than not that the fair value of the reporting unit exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary. If the qualitative assessment indicates the fair value of the reporting unit may be less than its carrying amount, we would compare the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill, and determine whether an impairment is necessary.

When evaluating whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, we assess relevant events and circumstances, including the following:


•	significant changes in our unit price;


•	changes in commodity prices;


•	changes in operating and capital costs;


•	impairments recognized;


•	acquisitions and disposals of assets;


•	changes in throughput; and


•	changes in trading multiples for our peers.

In this manner, estimating the fair value of our reporting units was not necessary based on the qualitative evaluation as of October 1, 2015. Given declines in our unit price and declines in commodity markets through the end of 2015, we also evaluated whether it was more likely than not that the fair value of a reporting unit had declined below its carrying amount at December 31, 2015, and concluded that estimating fair value of our reporting units was not necessary at that time either. However, fair-value estimates of our reporting units may be required for goodwill impairment testing in the future, and if the carrying amount of a reporting unit exceeds its fair value, goodwill is written down to the implied fair value through a charge to operating expense based on a hypothetical purchase price allocation.

Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of reporting units for purposes of performing the goodwill impairment test, when necessary. Management uses information available to make these fair-value estimates, including market multiples of EBITDA. Specifically, our management estimates fair value by applying an estimated multiple to projected EBITDA. Management considered observable transactions in the market, as well as trading multiples for peers, to determine an appropriate multiple to apply against our projected EBITDA. A lower fair-value estimate in the future for any of our reporting units could result in a goodwill impairment. Factors that could trigger a lower fair-value estimate include sustained price declines, throughput declines, cost increases, regulatory or political environment changes, and other changes in market conditions such as decreased prices in market-based transactions for similar assets. Based on our most recent goodwill impairment test, we concluded, based on a qualitative assessment, that it is more likely than not that the fair value of each reporting unit exceeded the carrying value of the reporting unit. Therefore, no goodwill impairment was indicated, and no goodwill impairment has been recognized in our consolidated financial statements.

Impairments of intangible assets. Our intangible asset balance as of December 31, 2015 and 2014, primarily represents the fair value, net of amortization, of (i) contracts we assumed 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 we assumed in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years. See Note 2—Acquisitions and Divestitures and Note 8—Goodwill and Intangibles in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Management assesses intangible assets for impairment together with the related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. 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. No intangible asset impairment has been recognized in connection with these assets.

Fair value. Management estimates fair value in performing impairment tests for long-lived assets and goodwill as well as for the initial measurement of asset retirement obligations and the initial recognition of environmental obligations assumed in third-party acquisitions. When our management 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, management utilizes the cost, income, or market multiples valuation approach depending on the quality of information available to support management’s assumptions. The income approach uses management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment, since the results are based on expected future events or conditions, such as sales prices, estimates of future throughput, capital and operating costs and the timing thereof, economic and regulatory climates and other factors. A multiple approach uses management’s best assumptions regarding expectations of projected EBITDA and multiple of that EBITDA that a buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than operating leases and standby letters of credit. The information pertaining to operating leases and our standby letters of credit required for this item is provided under Note 13—Commitments and Contingencies and Note 12—Debt and Interest Expense, respectively, included in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

RECENT ACCOUNTING DEVELOPMENTS

See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

EXHIBIT 99.3

Item 8. Financial Statements and Supplementary Data

WESTERN GAS PARTNERS, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm	2

Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013	3

Consolidated Balance Sheets as of December 31, 2015 and 2014	4

Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2015, 2014 and 2013	5

Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	6

Notes to Consolidated Financial Statements	7

Note 1. Summary of Significant Accounting Policies	7

Note 2. Acquisitions and Divestitures	16

Note 3. Partnership Distributions	20

Note 4. Equity and Partners’ Capital	22

Note 5. Transactions with Affiliates	25

Note 6. Income Taxes	30

Note 7. Property, Plant and Equipment	31

Note 8. Goodwill and Intangibles	32

Note 9. Equity Investments	33

Note 10. Components of Working Capital	35

Note 11. Asset Retirement Obligations	36

Note 12. Debt and Interest Expense	36

Note 13. Commitments and Contingencies	39

Note 14. Subsequent Events	40

Supplemental Quarterly Information	41

WESTERN GAS PARTNERS, LP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders

Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):

We have audited the accompanying consolidated balance sheets of Western Gas Partners, LP (the Partnership) and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Western Gas Partners, LP and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

June 10, 2016

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME



	Year Ended December 31,
thousands except per-unit amounts	2015 ⁽¹⁾			2014 ⁽¹⁾			2013 ⁽¹⁾
Revenues and other – affiliates
Gathering, processing and transportation	$	772,361		$	615,907		$	449,272
Natural gas, natural gas liquids and drip condensate sales	447,106			582,989			502,219
Other	1,172			5,078			6,421
Total revenues and other – affiliates	1,220,639			1,203,974			957,912
Revenues and other – third parties
Gathering, processing and transportation	356,477			278,127			191,813
Natural gas, natural gas liquids and drip condensate sales	170,843			42,916			46,289
Other	4,113			8,360			4,046
Total revenues and other – third parties	531,433			329,403			242,148
Total revenues and other	1,752,072			1,533,377			1,200,060
Equity income, net ⁽²⁾	71,251			57,836			22,948
Operating expenses
Cost of product ⁽³⁾	528,369			458,379			377,626
Operation and maintenance ⁽³⁾	331,972			293,710			235,971
General and administrative ⁽³⁾	41,319			38,561			34,766
Property and other taxes	33,288			28,889			26,243
Depreciation and amortization	272,611			211,809			172,863
Impairments	515,458			5,125			49,920
Total operating expenses	1,723,017			1,036,473			897,389
Gain (loss) on divestiture and other, net ⁽⁴⁾	57,024			(9		)	—
Operating income (loss)	157,330			554,731			325,619
Interest income – affiliates	16,900			16,900			16,900
Interest expense ⁽⁵⁾	(113,872		)	(76,766		)	(51,797		)
Other income (expense), net	(619		)	864			1,837
Income (loss) before income taxes	59,739			495,729			292,559
Income tax (benefit) expense	45,532			39,061			4,315
Net income (loss)	14,207			456,668			288,244
Net income attributable to noncontrolling interest	10,101			14,025			10,816
Net income (loss) attributable to Western Gas Partners, LP	$	4,106		$	442,643		$	277,428
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Gas Partners, LP	$	4,106		$	442,643		$	277,428
Pre-acquisition net (income) loss allocated to Anadarko	(79,386		)	(65,154		)	(6,929		)
General partner interest in net (income) loss ⁽⁶⁾	(180,996		)	(120,980		)	(69,633		)
Limited partners’ interest in net income (loss) ⁽⁶⁾	(256,276		)	256,509			200,866
Net income (loss) per common unit – basic ⁽⁷⁾	$	(1.95	)	$	2.13		$	1.83
Net income (loss) per common unit – diluted ⁽⁷⁾	(1.95		)	2.12			1.83


⁽¹⁾	Financial information for the year ended December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information for the years ended December 31, 2014 and 2013, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.


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

⁽³⁾

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $167.4 million, $127.9 million and $136.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Operation and maintenance includes charges from Anadarko of $77.1 million, $71.4 million and $67.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. General and administrative includes charges from Anadarko of $33.9 million, $31.3 million and $28.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 5.


⁽⁴⁾	Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1.


⁽⁵⁾	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.


⁽⁶⁾	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.


⁽⁷⁾	See Note 4 for the calculation of net income (loss) per common unit.

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS



	December 31,
thousands except number of units	2015 ⁽¹⁾		2014 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	98,033	$	67,054
Accounts receivable, net ⁽²⁾	193,329		122,767
Other current assets ⁽³⁾	7,855		10,053
Total current assets	299,217		199,874
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	6,556,778		6,248,577
Less accumulated depreciation	1,697,999		1,110,722
Net property, plant and equipment	4,858,779		5,137,855
Goodwill	419,186		418,587
Other intangible assets	832,127		884,857
Equity investments	618,887		634,492
Other assets	29,707		28,289
Total assets	$	7,317,903	$	7,563,954
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables ⁽⁴⁾	$	98,661	$	89,916
Accrued ad valorem taxes	17,808		15,043
Accrued liabilities	119,019		177,120
Total current liabilities	235,488		282,079
Long-term debt	2,707,357		2,422,954
Deferred income taxes	139,704		169,915
Asset retirement obligations and other	128,652		120,544
Deferred purchase price obligation – Anadarko ⁽⁵⁾	188,674		—
Total long-term liabilities	3,164,387		2,713,413
Total liabilities	3,399,875		2,995,492
Equity and partners’ capital
Common units (128,576,965 and 127,695,130 units issued and outstanding at December 31, 2015 and 2014, respectively)	2,588,991		3,119,714
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
General partner units (2,583,068 units issued and outstanding at December 31, 2015 and 2014)	120,164		105,725
Net investment by Anadarko	430,598		556,596
Total partners’ capital	3,850,644		4,498,992
Noncontrolling interest	67,384		69,470
Total equity and partners’ capital	3,918,028		4,568,462
Total liabilities, equity and partners’ capital	$	7,317,903	$	7,563,954


⁽¹⁾	Financial information as of December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information as of December 31, 2014, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.


⁽²⁾	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.


⁽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.


⁽⁵⁾	See Note 2.

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL



	Partners’ Capital
thousands	Net Investment by Anadarko			Common Units			Class C Units			General Partner Units			Noncontrolling Interest			Total
Balance at December 31, 2012 ⁽¹⁾	$	784,876		$	1,957,066		$	—		$	52,752		$	70,658		$	2,865,352
Net income (loss)	6,929			200,866			—			69,633			10,816			288,244
Issuance of common and general partner units, net of offering expenses	—			724,811			—			15,775			—			740,586
Contributions from noncontrolling interest owner	—			—			—			—			2,247			2,247
Distributions to noncontrolling interest owner	—			—			—			—			(13,127		)	(13,127		)
Distributions to unitholders	—			(239,157		)	—			(59,944		)	—			(299,101		)
Acquisitions from affiliates	(255,635		)	(209,865		)	—			—			—			(465,500		)
Contributions of equity-based compensation from Anadarko ⁽²⁾	—			2,865			—			58			—			2,923
Net pre-acquisition contributions from (distributions to) Anadarko ⁽³⁾	260,031			—			—			—			—			260,031
Net distributions to Anadarko of other assets	—			(5,738		)	—			(117		)	—			(5,855		)
Elimination of net deferred tax liabilities	46,530			—			—			—			—			46,530
Other	—			345			—			—			—			345
Balance at December 31, 2013 ⁽¹⁾	$	842,731		$	2,431,193		$	—		$	78,157		$	70,594		$	3,422,675
Net income (loss)	65,154			254,737			1,772			120,980			14,025			456,668
Issuance of common and general partner units, net of offering expenses	—			691,417			—			13,311			—			704,728
Issuance of Class C units	—			—			750,000			—			—			750,000
Beneficial conversion feature of Class C units	—			34,815			(34,815		)	—			—			—
Distributions to noncontrolling interest owner	—			—			—			—			(15,149		)	(15,149		)
Distributions to unitholders	—			(302,049		)	—			(106,572		)	—			(408,621		)
Acquisitions from affiliates	(372,784		)	16,534			—			—			—			(356,250		)
Contributions of equity-based compensation from Anadarko ⁽²⁾	—			3,104			—			63			—			3,167
Net pre-acquisition contributions from (distributions to) Anadarko ⁽³⁾	(16,692		)	—			—			—			—			(16,692		)
Net distributions to Anadarko of other assets	—			(10,492		)	—			(214		)	—			(10,706		)
Elimination of net deferred tax liabilities	38,160			—			—			—			—			38,160
Other	27			455			—			—			—			482
Balance at December 31, 2014 ⁽¹⁾	$	556,596		$	3,119,714		$	716,957		$	105,725		$	69,470		$	4,568,462
Net income (loss)	79,386			(238,166		)	(18,110		)	180,996			10,101			14,207
Above-market component of swap extensions with Anadarko ⁽⁴⁾	—			18,449			—			—			—			18,449
Issuance of common units, net of offering expenses	—			57,353			—			—			—			57,353
Amortization of beneficial conversion feature of Class C units	—			(12,044		)	12,044			—			—			—
Distributions to noncontrolling interest owner	—			—			—			—			(12,187		)	(12,187		)
Distributions to unitholders	—			(378,602		)	—			(166,541		)	—			(545,143		)
Acquisitions from affiliates	(197,562		)	23,286			—			—			—			(174,276		)
Contributions of equity-based compensation from Anadarko ⁽²⁾	—			3,480			—			71			—			3,551
Net pre-acquisition contributions from (distributions to) Anadarko	(49,801		)	—			—			—			—			(49,801		)
Net distributions to Anadarko of other assets	—			(4,547		)	—			(85		)	—			(4,632		)
Elimination of net deferred tax liabilities	41,844			—			—			—			—			41,844
Other	135			68			—			(2		)	—			201
Balance at December 31, 2015 ⁽¹⁾	$	430,598		$	2,588,991		$	710,891		$	120,164		$	67,384		$	3,918,028


⁽¹⁾	Financial information as of December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information as of December 31, 2014, 2013 and 2012, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.


⁽²⁾	Associated with the Anadarko Incentive Plans as defined and described in Note 1 and Note 5.


⁽³⁾	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.


⁽⁴⁾	See Note 5.

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
thousands	2015⁽¹⁾			2014 ⁽¹⁾			2013⁽¹⁾
Cash flows from operating activities
Net income (loss)	$	14,207		$	456,668		$	288,244
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	272,611			211,809			172,863
Impairments	515,458			5,125			49,920
Non-cash equity-based compensation expense	4,188			3,920			3,521
Deferred income taxes	11,346			38,682			66,246
Accretion and amortization of long-term obligations, net	17,698			2,736			2,449
Equity income, net ⁽²⁾	(71,251		)	(57,836		)	(22,948		)
Distributions from equity investment earnings ⁽²⁾	82,054			62,967			17,698
(Gain) loss on divestiture and other, net ⁽³⁾	(57,024		)	9			—
Lower of cost or market inventory adjustments	443			—			—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(4,371		)	1,399			(8,929		)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net	1,006			(34,980		)	34,319
Change in other items, net	(720		)	3,996			(2,048		)
Net cash provided by operating activities	785,645			694,495			601,335
Cash flows from investing activities
Capital expenditures	(637,964		)	(805,005		)	(852,388		)
Contributions in aid of construction costs from affiliates	461			183			617
Acquisitions from affiliates	(10,903		)	(379,193		)	(476,711		)
Acquisitions from third parties	(3,514		)	(1,523,327		)	(240,274		)
Investments in equity affiliates	(11,442		)	(64,278		)	(294,693		)
Distributions from equity investments in excess of cumulative earnings ⁽²⁾	16,244			18,055			4,438
Proceeds from the sale of assets to affiliates	925			402			85
Proceeds from the sale of assets to third parties	145,916			12,988			14
Net cash used in investing activities	(500,277		)	(2,740,175		)	(1,858,912		)
Cash flows from financing activities
Borrowings, net of debt issuance costs	889,606			1,646,878			957,503
Repayments of debt	(610,000		)	(650,000		)	(710,000		)
Increase (decrease) in outstanding checks	(2,666		)	765			(5,543		)
Proceeds from the issuance of common and general partner units, net of offering expenses	57,353			704,489			740,825
Proceeds from the issuance of Class C units	—			750,000			—
Distributions to unitholders⁽⁴⁾	(545,143		)	(408,621		)	(299,101		)
Contributions from noncontrolling interest owner	—			—			2,247
Distributions to noncontrolling interest owner	(12,187		)	(15,149		)	(13,127		)
Net contributions from Anadarko	(49,801		)	(16,392		)	265,520
Above-market component of swap extensions with Anadarko ⁽⁴⁾	18,449			—			—
Net cash provided by (used in) financing activities	(254,389		)	2,011,970			938,324
Net increase (decrease) in cash and cash equivalents	30,979			(33,710		)	(319,253		)
Cash and cash equivalents at beginning of period	67,054			100,764			420,017
Cash and cash equivalents at end of period	$	98,033		$	67,054		$	100,764
Supplemental disclosures
Acquisition of DBJV from Anadarko	$	174,276		$	—		$	—
Net distributions to (contributions from) Anadarko of other assets	4,632			10,706			5,855
Interest paid, net of capitalized interest	94,720			67,648			47,098
Taxes paid (reimbursements received)	—			(90		)	552
Capital lease asset transfer ⁽⁵⁾	—			4,833			—


⁽¹⁾	Financial information for the year ended December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information for the years ended December 31, 2014 and 2013, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.


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


⁽³⁾	Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1.


⁽⁴⁾	See Note 5.


⁽⁵⁾	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.

See accompanying Notes to Consolidated Financial Statements.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, including the Springfield system, and investments accounted for under the equity method (see Basis of presentation and Presentation of Partnership assets below) consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems	12	4	5	2
Treating facilities	12	7	—	3
Natural gas processing plants/trains⁽¹⁾	18	5	—	2
NGL pipelines	2	—	—	3
Natural gas pipelines	4	—	—	—
Oil pipelines	—	1	—	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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 share of the assets, liabilities, revenues and expenses attributable to the following systems: (i) 33.75% interests attributable to the Non-Operated Marcellus Interest systems and Anadarko-Operated Marcellus Interest systems, (ii) 50% interests attributable to the Newcastle system and the DBJV system (see Note 2) and (iii) 50.1% interest attributable to the Springfield system (as defined in 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: (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, including the Springfield system (as defined in Note 2), 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 (loss) 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 in the consolidated statements of income.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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.

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.

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Acquired		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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. ACQUISITIONS AND DIVESTITURES (CONTINUED)

Springfield acquisition. 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 system.” The Springfield oil and gas gathering systems are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The acquisition closed on March 14, 2016. See Note 14.

DBJV and Springfield acquisitions. Because the acquisitions of DBJV and Springfield were transfers 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 8-K to include the results attributable to the DBJV and Springfield systems as if the Partnership owned DBJV and Springfield for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of DBJV and 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 DBJV and Springfield during the periods reported.

The following table presents the impact of the DBJV and Springfield systems 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, 2015
thousands	Partnership Historical			DBJV System ⁽¹⁾		Springfield			Springfield Eliminations			Combined
Revenues and other	$	1,561,372		$	—	$	190,766		$	(66	)	$	1,752,072
Equity income, net	71,251			—		—			—			71,251
Net income (loss)	(63,437		)	—		77,644			—			14,207

	Year Ended December 31, 2014
thousands	Partnership Historical ⁽²⁾			DBJV System		Springfield			Springfield Eliminations			Combined
Revenues and other	$	1,320,756		$	62,112	$	150,576		$	(67	)	$	1,533,377
Equity income, net	57,836			—		—			—			57,836
Net income (loss)	390,558			17,309		48,801			—			456,668

	Year Ended December 31, 2013
thousands	Partnership Historical ⁽²⁾			DBJV System		Springfield			Springfield Eliminations			Combined
Revenues and other	$	1,052,937		$	32,545	$	114,647		$	(69	)	$	1,200,060
Equity income, net	22,948			—		—			—			22,948
Net income (loss)	285,443			4,096		(1,295		)	—			288,244


⁽¹⁾	The financial results for the DBJV system for the year ended December 31, 2015 are reflected in the Partnership’s historical financial statements as filed in the Partnership’s 2015 Form 10-K with the SEC on February 25, 2016.


⁽²⁾	See Adjustments to previously issued financial statements in Note 1.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. ACQUISITIONS AND DIVESTITURES (CONTINUED)

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 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. ACQUISITIONS AND DIVESTITURES (CONTINUED)

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	$	1,656,644	$	1,277,327
Net income (loss)	398,530		242,183
Net income (loss) attributable to Western Gas Partners, LP	384,505		231,367
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 (loss) 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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Distribution
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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	$	4,106		$	442,643		$	277,428
Pre-acquisition net (income) loss allocated to Anadarko	(79,386		)	(65,154		)	(6,929		)
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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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) attributable to natural gas production owned or controlled by Anadarko was 53%, 56% and 60% for the years ended December 31, 2015, 2014 and 2013, respectively. The Partnership’s processing throughput (excluding equity investment throughput) 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. The Partnership’s gathering, treating and transportation throughput (excluding equity investment throughput) attributable to crude/NGL production owned or controlled by Anadarko was 100% for each of the years ended December 31, 2015, 2014 and 2013.

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	$	10,903	$	22,943	$	11,211	$	925		$	402	$	85
Net carrying value	6,318		12,210		5,309		972			375		38
Partners’ capital adjustment	$	4,585	$	10,733	$	5,902	$	(47	)	$	27	$	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⁾	$	1,220,639	$	1,203,974	$	957,912
Equity income, net ⁽¹⁾	71,251		57,836		22,948
Cost of product ⁽¹⁾	167,354		127,930		136,696
Operation and maintenance ⁽²⁾	77,061		71,386		67,308
General and administrative ⁽³⁾	33,903		31,308		28,369
Operating expenses	278,318		230,624		232,373
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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)	$	32,422	$	(114	)	$	(62,104	)
State income tax expense (benefit)	1,764		493			173
Total current income tax expense (benefit)	34,186		379			(61,931		)
Deferred income tax expense (benefit)
Federal income tax expense (benefit)	10,251		35,361			66,390
State income tax expense (benefit)	1,095		3,321			(144		)
Total deferred income tax expense (benefit)	11,346		38,682			66,246
Total income tax expense (benefit)	$	45,532	$	39,061		$	4,315

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	$	59,739		$	495,729		$	292,559
Statutory tax rate	—		%	—		%	—		%
Tax computed at statutory rate	$	—		$	—		$	—
Adjustments resulting from:
Federal taxes on income attributable to Partnership assets pre-acquisition	42,823			35,716			4,822
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)	298			864			852
Texas margin tax expense (benefit) ⁽¹⁾	2,411			2,481			(1,359		)
Income tax expense (benefit)	$	45,532		$	39,061		$	4,315
Effective tax rate	76		%	8		%	1		%


⁽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	$	(138,159	)	$	(168,998	)
Credit carryforwards	512			526
Other intangible assets	(2,070		)	(1,450		)
Other	13			7
Net long-term deferred income tax liabilities	$	(139,704	)	$	(169,915	)

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	$	3,744	$	3,437
Gathering systems	3 to 47 years	6,061,004		5,559,369
Pipelines and equipment	15 to 45 years	136,290		151,107
Assets under construction	n/a	329,887		512,269
Other	3 to 40 years	25,853		22,395
Total property, plant and equipment		6,556,778		6,248,577
Accumulated depreciation		1,697,999		1,110,722
Net property, plant and equipment		$	4,858,779	$	5,137,855

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 $515.5 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 $14.4 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 $5.1 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 $49.9 million impairment, primarily due to an impairment of $48.7 million at the Springfield system related to a gathering system that was impaired to its estimated fair value of $14.4 million prior to the disposition of such gathering system by Springfield in 2014, using the income approach and Level 3 fair value inputs. This impairment was triggered by a reduction in estimated future cash flows caused by downward reserve revisions by producers based on lease expirations and the decision to suspend a drilling program in the area. Also during this period, the Partnership recognized impairments related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems.

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Union ⁽¹⁾			White Cliffs ⁽²⁾			Rendezvous ⁽³⁾			Mont Belvieu JV ⁽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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:



	December 31,
thousands	2015		2014
Trade receivables, net	$	143,557	$	119,170
Other receivables, net	49,772		3,597
Total accounts receivable, net	$	193,329	$	122,767

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	$	61,454	$	132,911
Accrued plant purchases	16,425		14,023
Accrued interest expense	26,194		24,741
Short-term asset retirement obligations	3,677		1,497
Short-term remediation and reclamation obligations	1,136		475
Income taxes payable	770		207
Other	9,363		3,266
Total accrued liabilities	$	119,019	$	177,120

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	$	119,855		$	82,563
Liabilities incurred	9,490			14,469
Liabilities settled	(7,905		)	(4,941		)
Accretion expense	6,381			5,122
Revisions in estimated liabilities	2,810			22,642
Carrying amount of asset retirement obligations at end of year	$	130,631		$	119,855

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; as well as changes in cost estimates associated with the abandonment of pipe and equipment skids, and compressors at the Springfield system.

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

At December 31, 2015, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $34.1 million, $25.9 million and $22.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	$	9,076
2017	7,756
2018	733
2019	624
2020	122
Thereafter	—
Total	$	18,311

14. SUBSEQUENT EVENTS

On March 14, 2016, the Partnership acquired Anadarko’s 100% interest in Springfield (see Note 2). The Partnership financed the acquisition of Springfield 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 included an over-allotment feature that resulted in the issuance of an additional $252.6 million in aggregate amount of such convertible preferred units in April 2016, the net proceeds from which were used to pay down RCF borrowings. Total net proceeds from the issuance of the convertible preferred units, including the units issued in connection with the over-allotment option, were $687.5 million. Additionally, the convertible preferred units will 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 funded its WES unit purchase by drawing on a secured revolving credit facility that closed on the closing date of the Springfield acquisition.

WESTERN GAS PARTNERS, LP

SUPPLEMENTAL QUARTERLY INFORMATION

(UNAUDITED)

The following table presents a summary of the Partnership’s operating results by quarter for the years ended December 31, 2015 and 2014. The Partnership’s operating results reflect the operations of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies) from the dates of common control, unless otherwise noted. See Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures.



thousands except per-unit amounts	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
2015
Total revenues and other	$	437,006		$	465,993	$	432,515	$	416,558
Equity income, net	18,220			18,941		21,976		12,114
Gain (loss) on divestiture and other, net	(6		)	—		77,254		(20,224		)
Operating income (loss) ⁽¹⁾	(122,333		)	170,713		226,432		(117,482		)
Net income (loss) ⁽¹⁾	(153,267		)	135,159		186,325		(154,010		)
Net income (loss) attributable to Western Gas Partners, LP ⁽¹⁾	(156,493		)	132,343		184,137		(155,881		)
Net income (loss) per common unit – basic and diluted ^{(1) (2)}	(1.61		)	0.46		0.79		(1.60		)
2014
Total revenues and other	$	334,197		$	393,273	$	399,126	$	406,781
Equity income, net	9,251			13,008		19,063		16,514
Operating income (loss)	121,520			138,276		154,587		140,348
Net income (loss)	104,821			113,318		126,546		111,983
Net income (loss) attributable to Western Gas Partners, LP	101,129			109,869		122,682		108,963
Net income (loss) per common unit – basic and diluted ⁽²⁾	0.54			0.57		0.60		0.42


⁽¹⁾	Includes impairments at the Red Desert complex in the first and fourth quarters of 2015 and at the Hilight system in the fourth quarter of 2015. See Note 7—Property, Plant and Equipment.


⁽²⁾	Represents net income (loss) earned on and subsequent to the acquisition of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies).

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