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.

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.

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.

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.

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.

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.

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.

2

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.

3

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.

4

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.

5

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.

6

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.

7

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.

8

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.

9

	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.

10

	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.

11

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 Divestituresin 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.

12

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.

13

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.

14

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.

15

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.

16

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.

17

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 increasesof (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.

18

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.

19

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.

20

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.

21

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.

22

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.

23

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.

24

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 millionincrease in total revenues and other, a $17.3 millionincrease in distributions from equity investees and a $3.9 milliondecrease in net income attributable to noncontrolling interest. These amounts were partially offset by a $69.5 millionincrease in cost of product (net of lower of cost or market inventory adjustments), a $38.3 millionincrease in operation and maintenance expenses, a $4.4 millionincrease in property and other tax expense, and a $2.5 millionincrease 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 millionincrease in total revenues and other and a $58.9 millionincrease in distributions from equity investees. These amounts were offset by an $80.8 millionincrease in cost of product, a $57.7 millionincrease in operation and maintenance expenses, a $3.3 millionincrease in general and administrative expenses excluding non-cash equity-based compensation expense, a $3.2 millionincrease in net income attributable to noncontrolling interest, and a $2.6 millionincrease 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 millionincrease 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 millionincrease in net cash paid for interest expense and a $1.7 millionincrease 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 millionincrease in Adjusted EBITDA, offset by a $22.9 millionincrease in net cash paid for interest expense and a $15.4 millionincrease 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.

25

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.

26

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 Affiliatesin 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.

27

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

• $637.5 millionof 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;

28

• $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;

29

• $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.

30

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.

31

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.

32

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.

33

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 Divestituresin 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.

34

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.

35

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.

36