COMMONLY USED TERMS AND DEFINITIONS

EXHIBIT 99.2

Western Gas Equity Partners, LP (“WGP”) is a Delaware master limited partnership formed by Anadarko Petroleum Corporation to own three types of partnership interests in Western Gas Partners, LP and its subsidiaries (“XXX”). For purposes of this Form 10-K, “WGP,” “we,” “us,” “our,” “Western Gas Equity Partners,” or like terms refers to Western Gas Equity Partners, LP in its individual capacity or to Western Gas Equity Partners, LP and its subsidiaries, including the general partner of XXX, Western Gas Holdings, LLC, and XXX, as the context requires. 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 WGP GP.

Anadarko-Operated Marcellus Interest: WES’s interest in the Larry’s Creek, Xxxxx 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, Xxxxxxx and Xxxxxx 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 Xxxxxx, Loving and Xxxxxxxxx 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 XXX Evaluates Its Operations in this Item 7 of Exhibit 99.2 to this Current Report on Form 8-K.

Equity investment throughput: WES’s 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of WES’s 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput.

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.

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 XXX concurrently with the closing of WES’s 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 Xxxxxxx 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: WES’s 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.

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

Red Desert complex: The Xxxxxxx 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 Xxxx 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 Xxxx 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.

XXX: Western Gas Partners, LP.

XXX GP: Western Gas Holdings, LLC, the general partner of XXX.

XXX RCF: WES’s senior unsecured revolving credit facility.

WGP: Western Gas Equity Partners, LP.

WGP GP: Western Gas Equity Holdings, LLC, the general partner of WGP.

WGP LTIP: Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.

WGP WCF: The WGP working capital facility.

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

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

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 the consolidated financial statements and notes to consolidated financial statements, in which XXX is fully consolidated, 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 “XXX assets” refers to the assets indirectly 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 through our partnership interests in XXX as of December 31, 2015. Because Anadarko controls XXX through its ownership and control of us, and because we own the entire interest in XXX GP, each of WES’s acquisitions of XXX assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, XXX assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by XXX (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 XXX assets from Anadarko, we (by virtue of our consolidation of XXX) and XXX may be required to recast our financial statements to include the activities of such XXX assets from the date of common control. For those periods requiring recast, the consolidated financial statements for periods prior to the acquisition of XXX 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 XXX had owned the XXX assets during the periods reported. For ease of reference, we refer to the historical financial results of the XXX assets prior to the acquisitions from Anadarko as being “our” historical financial results.

EXECUTIVE SUMMARY

We were formed by Anadarko in September 2012 by converting WGR Holdings, LLC into an MLP and changing its name to Western Gas Equity Partners, LP. We closed our IPO in December 2012 and own XXX GP and a significant limited partner interest in XXX, a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream energy assets. Our consolidated financial statements include the consolidated financial results of XXX due to our 100% ownership interest in XXX GP and XXX GP’s control of XXX. Our only cash-generating assets consist of our partnership interests in XXX, and we currently have no independent operations. 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.

XXX currently owns or has investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), North-central Pennsylvania and Texas, and is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. As of December 31, 2015, WES’s assets and investments accounted for under the equity method consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems	12	4	5	2
Treating facilities	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 WES’s DBM complex. See below and General Trends and Outlook within this Item 7.

In addition to WES’s 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 raised our distribution to $0.40375 per unit for the fourth quarter of 2015, representing a 6% increase over the distribution for the third quarter of 2015 and a 29% increase over the distribution for the fourth quarter of 2014.


•	XXX 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, XXX closed on the sale of its 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.


•	XXX 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 the XXX RCF. See Liquidity and Capital Resources within this Item 7 for additional information.


•	In June 2015, XXX 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.


•	XXX issued 873,525 common units to the public under its $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.


•	XXX raised its 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 XXX 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 XXX for natural gas assets (as defined under the caption How XXX Evaluates Its 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 XXX Evaluates Its 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.

WES’S OPERATIONS

WES’s results are driven primarily by the volumes of oil, natural gas and NGLs XXX xxxxxxx, processes, treats or transports through its systems. For the year ended December 31, 2015, 70% of total revenues and 52% of throughput (excluding equity investment throughput and throughput measured in barrels) were attributable to transactions with Anadarko. XXX also recognized capital contributions from Anadarko of $18.4 million related to the above-market component of its 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). XXX receives significant dedications from its largest customer, Anadarko. With respect to WES’s Wattenberg, Haley, Helper, Xxxxxxx and Hugoton gathering systems, Anadarko has made dedications to XXX that will continue to expand as long as additional xxxxx are connected to these gathering systems.

In WES’s gathering operations, it contracts with producers and customers to gather natural gas or oil from individual xxxxx located near its gathering systems. XXX connects xxxxx 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. XXX also treats a significant portion of the volumes that it gathers so that it will satisfy required specifications for pipeline transportation.

For the year ended December 31, 2015, 92% of WES’s 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 XXX xxxxxxx, processes, treats or transports. This type of contract provides XXX with a relatively stable revenue stream that is not subject to direct commodity price risk, except to the extent that (i) XXX retains and sells 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 WES’s gross margin, including gross margin attributable to condensate sales, was attributable to percent-of-proceeds and keep-whole contracts, pursuant to which XXX has commodity price exposure. A majority of the commodity price risk associated with its 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 WES’s 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.

XXX also has indirect exposure to commodity price risk in that persistent low natural gas prices have caused and may continue to cause current or potential customers to delay drilling or shut in production in certain areas, which would reduce the volumes of natural gas available for WES’s systems. XXX also bears 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 WES’s 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 Financial Results, set forth below in this Item 7.

HOW XXX EVALUATES ITS OPERATIONS

WES’s management relies on certain financial and operational metrics to analyze its performance. These metrics are significant factors in assessing WES’s 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 XXX uses in assessing its ability to generate revenues. In order to maintain or increase throughput on WES’s gathering and processing systems, XXX must connect additional xxxxx to its systems. WES’s success in maintaining or increasing throughput is impacted by the successful drilling of new xxxxx by producers that are dedicated to WES’s systems, recompletions of existing xxxxx connected to its systems, its ability to secure volumes from new xxxxx drilled on non-dedicated acreage and its ability to attract natural gas volumes currently gathered, processed or treated by its competitors. During the year ended December 31, 2015, excluding the Springfield system, XXX added 199 receipt points to its systems.

Operating and maintenance expenses. XXX monitors operating and maintenance expenses to assess the impact of such costs on the profitability of its assets and to evaluate the overall efficiency of its 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 XXX or on its behalf. For periods commencing on the date of and subsequent to WES’s acquisition of its assets, certain of these expenses are incurred under and governed by WES’s services and secondment agreement with Anadarko.

General and administrative expenses. To help ensure the appropriateness of WES’s general and administrative expenses and maximize its cash available for distribution, XXX monitors such expenses through comparison to prior periods, to the annual budget approved by XXX GP’s Board of Directors, as well as to general and administrative expenses incurred by similar midstream companies. Pursuant to the XXX omnibus agreement, Anadarko and XXX GP perform centralized corporate functions for XXX. General and administrative expenses for periods prior to WES’s acquisition of the XXX 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 XXX assets. For periods subsequent to the acquisition of the XXX 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 WES’s partnership agreement and the XXX omnibus agreement. Amounts required to be reimbursed to Anadarko under WES’s omnibus agreement also include those expenses attributable to its status as a publicly traded partnership, such as the following:


•	expenses associated with annual and quarterly reporting;


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


•	expenses associated with listing on the NYSE; and


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

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

Non-GAAP financial measures

Adjusted gross margin attributable to Western Gas Partners, LP. XXX defines 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. XXX believes Adjusted gross margin is an important performance measure of the core profitability of its operations, as well as its operating performance as compared to that of other companies in the industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to WES’s percent-of-proceeds and keep-whole processing contracts, (ii) costs associated with the valuation of WES’s gas imbalances, and (iii) costs associated with WES’s obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by XXX and sold to third parties. These expenses are subject to variability, although a majority of WES’s exposure to commodity price risk attributable to purchases and sales of natural gas, condensate and NGLs is mitigated through its 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 XXX and its peers, XXX also discloses 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. XXX defines 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. XXX believes that the presentation of Adjusted EBITDA provides information useful to investors in assessing its 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 WES’s management and external users of WES’s consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:


•	WES’s 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 WES’s 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. XXX defines “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. XXX compares Distributable cash flow to the cash distributions XXX expects to pay its unitholders. Using this measure, WES’s management can quickly compute the Coverage ratio of distributable cash flow to planned cash distributions. XXX believes 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 WES’s operating and financial performance and compare it with the performance of other publicly traded partnerships.

While Distributable cash flow is a measure XXX uses to assess its ability to make distributions to its unitholders, it should not be viewed as indicative of the actual amount of cash that XXX has available for distributions or that it plans 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 WES’s commodity price swap agreements, Distributable cash flow is not a reflection of WES’s ability to generate cash from operations.

Reconciliation to GAAP measures. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. The GAAP measure used by XXX 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 XXX most directly comparable to Adjusted EBITDA. The GAAP measure used by XXX most directly comparable to Distributable cash flow is net income (loss) attributable to Western Gas Partners, LP. WES’s 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 WES’s results as reported under GAAP. WES’s definitions of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow may not be comparable to similarly titled measures of other companies in WES’s industry, thereby diminishing their utility.

WES’s 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. XXX believes that investors benefit from having access to the same financial measures that its management uses in evaluating its operating results.

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



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


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



	Year Ended December 31,
thousands	2015			2014			2013
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net income (loss) attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	907,568		$	782,900		$	539,401
Less:
Distributions from equity investees	98,298			81,022			22,136
Non-cash equity-based compensation expense	4,402			4,095			3,575
Interest expense	113,872			76,766			51,797
Income tax expense	45,532			39,061			6,524
Depreciation and amortization ⁽¹⁾	270,004			209,240			170,322
Impairments	515,458			5,125			49,920
Other expense ⁽¹⁾	1,290			—			175
Add:
Gain (loss) on divestiture and other, net ⁽²⁾	57,024			(9		)	—
Equity income, net	71,251			57,836			22,948
Interest income – affiliates	16,900			16,900			16,900
Other income ^{(1) (3)}	219			325			419
Income tax benefit	—			—			2,209
Net income (loss) attributable to Western Gas Partners, LP	$	4,106		$	442,643		$	277,428
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	907,568		$	782,900		$	539,401
Adjusted EBITDA attributable to noncontrolling interest of Western Gas Partners, LP	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 of Western Gas Partners, LP:
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 WES’s 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 WES’s DBM complex.


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


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



	Year Ended December 31,
thousands except Coverage ratio	2015				2014			2013
Reconciliation of Distributable cash flow to Net income (loss) attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	781,383			$	661,133		$	455,238
Less:
Distributions from equity investees	98,298				81,022			22,136
Non-cash equity-based compensation expense	4,402				4,095			3,575
Interest expense, net (non-cash settled) ⁽¹⁾	14,400				—			—
Income tax (benefit) expense	45,532				39,061			4,315
Depreciation and amortization ⁽²⁾	270,004				209,240			170,322
Impairments	515,458				5,125			49,920
Above-market component of swap extensions with Anadarko ⁽³⁾	18,449				—			—
Other expense ⁽²⁾	1,290				—			175
Add:
Gain (loss) on divestiture and other, net ⁽⁴⁾	57,024				(9		)	—
Equity income, net	71,251				57,836			22,948
Cash paid for maintenance capital expenditures ⁽²⁾	53,882				52,159			36,769
Capitalized interest ⁽⁵⁾	8,318				9,832			11,945
Cash paid for (reimbursement of) income taxes	(138		)		(90		)	552
Other income ^{(2) (6)}	219				325			419
Net income (loss) attributable to Western Gas Partners, LP	$	4,106			$	442,643		$	277,428
Distributions declared ⁽⁷⁾
Limited partners of XXX	$	392,077
General partner of XXX	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 WES’s 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 WES’s 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 XXX xxxx distributions of $3.050 per unit declared for the year ended December 31, 2015.

ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS

Our consolidated financial statements include the consolidated financial results of XXX due to our 100% ownership interest in XXX GP and XXX GP’s control of XXX. Our only cash-generating assets consist of our partnership interests in XXX, and we currently have no independent operations. As a result, our results of operations do not differ materially from the results of operations and cash flows of XXX, which are reconciled below.

Income taxes. Prior to our conversion from WGR Holdings, LLC to a limited partnership in September 2012, we were a single-member limited liability company. The separate existence of a limited liability company is disregarded for U.S. federal income tax purposes, resulting in the treatment of WGR Holdings, LLC as a division of Anadarko and its inclusion in Anadarko’s consolidated income tax return for federal and state tax purposes. The income tax expense recorded on the financial statements of WGR Holdings, LLC, and now included in our consolidated financial statements, reflects our income tax expense and liability on a separate-return basis.

The deferred federal and state income taxes included in our consolidated financial statements are primarily attributable to the temporary differences between the financial statement carrying amount of our investment in XXX and our outside tax basis with respect to our partnership interests in XXX. When determining the deferred income tax asset and liability balances attributable to our partnership interests in XXX, we applied an accounting policy that looks through our investment in XXX. The application of such accounting policy resulted in no deferred income taxes being created on the difference between the book and tax basis on the non-tax deductible goodwill portion of our investment in XXX in our consolidated financial statements.

Upon the completion of our IPO in December 2012, we became a publicly traded limited partnership for U.S. federal and state income tax purposes and therefore are not subject to U.S. federal and state income taxes, except for Texas margin tax.

General and administrative expenses. As a separate publicly traded partnership, we incur general and administrative expenses which are separate from, and in addition to, those incurred by XXX. In connection with our IPO in December 2012, we entered into an omnibus agreement with WGP GP and Anadarko that governs the following: (i) our obligation to reimburse Anadarko for expenses incurred or payments made on our behalf in conjunction with Anadarko’s provision of general and administrative services to us, including our public company expenses and general and administrative expenses; (ii) our obligation to pay Anadarko, in quarterly installments, an administrative services fee of $250,000 per year (subject to an annual increase as described in the agreement); and (iii) our obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes on our behalf.

The following table summarizes the amounts we reimbursed to Anadarko, separate from, and in addition to, those reimbursed by XXX:



	Year Ended December 31,
thousands	2015		2014		2013
General and administrative expenses	$	256	$	254	$	271
Public company expenses	1,997		1,986		2,391
Total reimbursement	$	2,253	$	2,240	$	2,662

Noncontrolling interests. The interest in Chipeta held by a third-party member is already reflected as noncontrolling interest in WES’s consolidated financial statements. In addition, the limited partner interests in XXX held by other subsidiaries of Anadarko and the public are reflected as noncontrolling interests in the consolidated financial statements (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 for further information).

The difference between the carrying value of WGP’s investment in XXX and the underlying book value of common units issued by XXX is accounted for as an equity transaction. Thus, if XXX issues common units at a price different than WGP’s per-unit carrying value, any resulting change in the carrying value of WGP’s investment in XXX is reflected as an adjustment to partners’ capital.

Distributions. Our partnership agreement requires that we distribute all of our available cash (as defined in our partnership agreement) within 55 days after the end of each quarter. Our only cash-generating assets are our partnership interests in XXX, consisting of general partner units, common units and incentive distribution rights, on which we expect to receive quarterly distributions from XXX. Our cash flow and resulting ability to make cash distributions are therefore completely dependent upon WES’s ability to make cash distributions with respect to our partnership interests in XXX. Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter.

Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan. Concurrently with the WGP IPO, WGP GP adopted the WGP LTIP. Equity-based compensation expense attributable to grants made under the WGP LTIP impacts cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of WGP common units to the participant. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for further information.

Working capital facility. On November 1, 2012, we entered into the WGP WCF, a $30.0 million working capital facility with Anadarko as the lender. The facility is available exclusively to fund our working capital borrowings. Borrowings under the facility will mature on November 1, 2017, and bear interest at LIBOR plus 1.50%. The interest rate was 1.93% at December 31, 2015.

We are required to reduce all borrowings under the WGP WCF to zero for a period of at least 15 consecutive days during the twelve month period commencing on November 1 of each year. As of December 31, 2015, we had no outstanding borrowings under the WGP WCF and $30.0 million available for borrowing. At December 31, 2015, we were in compliance with all covenants under the WGP WCF.

Reconciliation of net income (loss) attributable to Western Gas Partners, LP to net income (loss) attributable to Western Gas Equity Partners, LP. The differences between net income (loss) attributable to Western Gas Partners, LP and net income (loss) attributable to Western Gas Equity Partners, LP are reconciled as follows:



	Year Ended December 31,
thousands	2015			2014			2013
Net income (loss) attributable to XXX	$	4,106		$	442,643		$	277,428
Incremental income tax expense ⁽¹⁾	—			—			49
Limited partner interests in XXX not held by WGP ⁽²⁾	164,510			(151,443		)	(111,357		)
General and administrative expenses ⁽³⁾	(3,109		)	(3,216		)	(3,712		)
Other income (expense), net	41			74			98
Property and other taxes	(39		)	(34		)	—
Interest expense	(2		)	(3		)	—
Net income (loss) attributable to WGP	$	165,507		$	288,021		$	162,506

⁽¹⁾

The income tax expense recorded in the financial statements of WGR Holdings, LLC, and now reflected in the consolidated financial statements of WGP, reflects our pre-IPO income tax expense and liability on a separate-return basis. Upon the completion of our IPO in December 2012, we became a partnership for U.S. federal and state income tax purposes and therefore are subsequently not subject to U.S. federal and state income taxes, except for Texas margin tax.

⁽²⁾

Represents the portion of net income (loss) allocated to the limited partner interests in XXX not held by WGP. As of December 31, 2015, 2014 and 2013 the publicly held limited partner interest represented a 55.1%, 55.0% and 56.4% interest in XXX, respectively. Other subsidiaries of Anadarko separately held an 8.5%, 8.3% and 0.4% limited partner interest in XXX as of December 31, 2015, 2014 and 2013, respectively. 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.


⁽³⁾	Represents general and administrative expenses incurred by WGP separate from, and in addition to, those incurred by XXX.

Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WGP and XXX are reconciled as follows:



	Year Ended December 31,
thousands	2015			2014			2013
XXX net cash provided by operating activities	$	785,645		$	694,495		$	601,335
Income taxes	—			—			49
General and administrative expenses ⁽¹⁾	(3,109		)	(3,216		)	(3,712		)
Non-cash equity-based compensation expense	257			185			301
Changes in working capital	16			(839		)	(158		)
Other income (expense), net	41			74			98
Property and other taxes	(39		)	(34		)	—
Interest expense	(2		)	(3		)	—
WGP net cash provided by operating activities	$	782,809		$	690,662		$	597,913

XXX net cash provided by (used in) financing activities	$	(254,389	)	$	2,011,970		$	938,324
Proceeds from issuance of XXX common and general partner units, net of offering expenses ⁽²⁾	—			(13,311		)	(15,775		)
Offering expenses from the issuance of WGP common units ⁽³⁾	—			—			(2,367		)
Distributions to WGP unitholders ⁽⁴⁾	(306,477		)	(228,481		)	(137,000		)
Distributions to WGP from XXX ⁽⁵⁾	311,965			232,277			168,395
Net contributions from (distributions to) Anadarko	—			—			(49		)
WGP working capital facility borrowings	—			1,150			—
WGP WCF repayments	(1,150		)	—			—
WGP net cash provided by (used in) financing activities	$	(250,051	)	$	2,003,605		$	951,528


⁽¹⁾	Represents general and administrative expenses incurred by WGP separate from, and in addition to, those incurred by XXX.


⁽²⁾	Represents the difference attributable to elimination upon consolidation of proceeds to XXX from the issuance of WES general partner units in exchange for XXX GP’s proportionate capital contribution.


⁽³⁾	For the year ended December 31, 2013, amount represents additional offering costs billed in conjunction with WGP’s IPO.


⁽⁴⁾	Represents distributions to WGP common unitholders paid under WGP’s partnership agreement. See Note 3—Partnership Distributions and 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.


⁽⁵⁾	Difference attributable to elimination upon consolidation of WES’s distributions on partnership interests owned by WGP. See Note 3—Partnership Distributions and 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.

Western Gas Partners, LP

WES’s 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 WES’s results of operations as compared to the prior periods.

Gathering and processing agreements. The gathering agreements of WES’s 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. XXX has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. On December 31, 2014, WES’s commodity price swap agreements for the Hilight and Newcastle systems and the Xxxxxxx complex expired without renewal.

On June 25, 2015, XXX extended its commodity price swap agreements with Anadarko for the DJ Basin complex from July 1, 2015, through December 31, 2015, and for the Hugoton system from October 1, 2015, through December 31, 2015. 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. XXX will also record a capital contribution from Anadarko in its 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. With respect to assets acquired from Anadarko, XXX records Anadarko’s historic current and deferred income taxes for the periods prior to its ownership of the assets. For periods subsequent to its acquisitions from Anadarko, XXX is not subject to tax except for the Texas margin tax and, accordingly, does not record current and deferred federal income taxes related to such assets.

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

•

DBM acquisition. In November 2014, XXX acquired Nuevo Midstream, LLC from a third party. Following the acquisition, XXX changed the name of Nuevo to Delaware Basin Midstream, LLC. DBM was financed with the issuance of $750.0 million of XXX Class C units to a subsidiary of Anadarko, borrowings under the XXX RCF and cash on hand, including the proceeds from the XXX November 2014 equity offering. These assets have been recorded in the 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 the consolidated statement of income beginning on the acquisition date in the fourth quarter of 2014.

•

DBJV acquisition. In March 2015, XXX acquired Anadarko’s interest in DBJV. XXX will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. XXX currently estimates the future payment will be $282.8 million, the net present value of which was $174.3 million as of the acquisition date. As of December 31, 2015, the net present value of this obligation was $188.7 million and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion expense was $14.4 million for the year ended December 31, 2015, and zero for each of the years ended December 31, 2014 and 2013, and has been recorded as a charge to interest expense.


•	Dew and Pinnacle divestiture. In July 2015, the Dew and Pinnacle systems in East Texas were sold to a third party for net proceeds of $145.6 million, after closing adjustments, resulting in a net gain on sale of $77.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of income.

DBM complex. On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. For the year ended December 31, 2015, $20.3 million of losses have been recorded 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 WES’s 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, WES’s 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 WES’s customers’ activity levels, and thus WES’s 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 Xxxxx 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 WES’s 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 WES’s assets. Several of WES’s 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, XXX will continue to connect new xxxxx to its systems to mitigate the impact of natural production declines in order to maintain throughput on its systems. However, WES’s success in connecting new xxxxx to its systems is dependent on the activities of natural gas producers and shippers.

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

Liquidity and access to capital markets. XXX requires periodic access to capital in order to fund acquisitions and expansion projects. Under the terms of WES’s partnership agreement, it is required to distribute all of its available cash to its unitholders, which makes XXX 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 XXX is unable either to access the capital markets or find alternative sources of capital, WES’s growth strategy may be more challenging to execute.

WES’s sources of liquidity as of December 31, 2015, included cash and cash equivalents, cash flows generated from operations, interest income on its $260.0 million note receivable from Anadarko, $893.6 million in available borrowing capacity under its RCF, and issuances of additional equity or debt securities. As of December 31, 2015, WES’s 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 Xxxxx’x. In February 2016, Xxxxx’x downgraded Anadarko’s senior unsecured ratings from Baa2 to Ba1, with a negative outlook, and downgraded WES’s senior unsecured ratings from Baa3 to Ba1, with a negative outlook. Also in February 2016, S&P affirmed WES’s 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 WES’s credit rating; however, XXX cannot be assured that its credit rating will not be downgraded further. The Xxxxx’x downgrade and any further downgrades in WES’s credit ratings will adversely affect its ability to raise debt in the public debt markets, which could negatively impact its cost of capital and ability to effectively execute aspects of its strategy.

Changes in regulations. WES’s operations and the operations of its 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. XXX and its 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 WES’s 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 WES’s existing agreements, it has 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 WES’s financing costs. Additionally, as with other yield-oriented securities, WES’s unit price is impacted by the level of its 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 WES’s units, and a rising interest rate environment could have an adverse impact on WES’s unit price and its ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, reduce debt or for other purposes. However, WES expects its cost of capital to remain competitive, as its competitors would face similar circumstances.

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

As of December 31, 2015, Anadarko held 191,087,365 of our common units, representing an 87.3% limited partner interest in us. Given Anadarko’s significant limited partner interest in us and indirect economic interests in WES, we believe Anadarko will continue to be motivated to promote and support the successful execution of WES’s business plan and to pursue projects that help to enhance the value of its business. However, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering WES 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 WES. WES may also pursue certain asset acquisitions from third parties to the extent such acquisitions complement its or Anadarko’s existing asset base or allow WES to capture operational efficiencies from Anadarko’s or third-party production. However, if WES does not make additional acquisitions from Anadarko or third parties on economically acceptable terms, its future growth will be limited, and the acquisitions WES makes could reduce, rather than increase, 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. WES has a property damage insurance policy designed to cover costs to repair or rebuild damaged assets (less a $1 million deductible), and business interruption insurance designed to cover lost earnings after January 2, 2016. Insurance claims are in process under both of these policies. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of WES’s 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 ⁽²⁾	$	4,106		$	442,643		$	277,428
Key performance metrics ⁽³⁾
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 by WES from services provided to its affiliates, as well as from the sale of residue, drip condensate and NGLs to its affiliates. Operating expenses include amounts charged by WES affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on WES’s 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⁾	For reconciliations to comparable consolidated results of WGP, see Items Affecting the Comparability of Financial Results within this Item 7.

⁽³⁾

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 WES Evaluates Its 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 WES Evaluates Its Operations–Reconciliation to GAAP Measures within this Item 7.

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

Throughput



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

NM-Not meaningful

⁽¹⁾

The combination of WES’s 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 WES’s 14.81% share of average Fort Union and 22% share of average Rendezvous throughput.


⁽³⁾	Represents WES’s 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEG and TEP throughput, and 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 “Xxxxxxx straddle plant”) and the acquisition of DBM in November 2014.

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

Crude/NGL assets

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

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

Gathering, Processing and Transportation Revenues



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

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

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

Natural Gas, Natural Gas Liquids and Drip Condensate Sales



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


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

For the year ended December 31, 2015, average natural gas, NGL and drip condensate prices included the effects of commodity price swap agreements attributable to sales for the Hugoton system, the MGR assets and the DJ Basin complex. Beginning July 1, 2015, for the DJ Basin complex and October 1, 2015, for the Hugoton system, average natural gas, NGL and drip condensate prices exclude amounts considered above market that are recorded as capital contributions in the statement of equity and partners’ capital. For the year ended December 31, 2014, average natural gas, NGL and drip condensate prices included the effects of commodity price swap agreements attributable to sales for the Hilight, Hugoton and Newcastle systems, the DJ Basin and Xxxxxxx complexes, and the MGR assets. On December 31, 2014, WES’s commodity price swap agreements for the Hilight and Newcastle systems and the Xxxxxxx complex (excluding the Xxxxxxx 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 Xxxxxxx 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 Xxxxxxx 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 Xxxxxxx 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 WES’s 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 WES’s above-market swap extensions beginning July 1, 2015 (see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K).

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

Equity Income, Net



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

For the year ended December 31, 2015, equity income, net increased by $13.4 million, primarily due to a full year of equity income recognized from the TEFR Interests in 2015 and the third quarter 2014 in-service date of a White Cliffs pipeline expansion. These increases were partially offset by WES’s 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 WES’s 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 Xxxxxxx complexes and the MGR assets. On December 31, 2014, WES’s commodity price swap agreements for the Hilight and Newcastle systems and the Xxxxxxx complex (excluding the Xxxxxxx 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 Xxxxxxx 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 Xxxxxxx 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 Xxxxxxx straddle plant due to a decrease in volume.

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

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

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

The increase in residue purchases for the year ended December 31, 2014, was primarily due to an increase of $29.5 million at the Hilight system, the DJ Basin and Chipeta complexes and the Xxxxxxx 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 WES reimbursed Anadarko pursuant to the WES 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 WES reimbursed Anadarko pursuant to the WES omnibus agreement, (ii) an increase of $0.5 million in non-cash compensation expenses and (iii) $0.5 million in consulting and audit fees. These increases were partially offset by a $1.1 million decrease in pre-acquisition management services fees for expenses incurred by Anadarko related to Springfield.

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

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

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

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

Impairment expense increased by $510.3 million for the year ended December 31, 2015, primarily due to impairments of $280.2 million at the Red Desert complex and $220.9 million at the Hilight system. Using the income approach and Level 3 fair value inputs, the Red Desert complex was impaired to its estimated salvage value of $6.3 million and the Hilight system was impaired to its estimated fair value of $28.8 million. These impairments were triggered by a reduction in estimated future cash flows caused by the low commodity price environment and resulting reduced producer drilling activity and related throughput. Also during this period, impairment expense increased by $9.2 million primarily due to (i) the abandonment of compressors at the MIGC system and DJ Basin complex and (ii) the cancellation of projects at the Non-Operated Marcellus Interest systems, Anadarko-Operated Marcellus Interest systems, the DBJV system and the DJ Basin, Brasada and Red Desert complexes. Prolonged low or further declines in commodity prices and changes to producers’ drilling plans in response to lower prices could result in additional impairments in future periods. See Risk Factors under Part I, Item 1A of our 2015 Form 10-K.

Impairment expense decreased by $44.8 million for the year ended December 31, 2014, primarily due to an impairment of $48.7 million at the Springfield system recognized during the year ended December 31, 2013, primarily related to a gathering system that was impaired to its estimated fair value of $14.4 million prior to the disposition of such gathering system by Springfield in 2014, using the income approach and Level 3 fair value inputs. This impairment was triggered by a reduction in estimated future cash flows caused by downward reserve revisions by producers based on lease expirations and the decision to suspend a drilling program in the area. This decrease was offset by increases of (i) $1.0 million in the first quarter of 2014 related to a non-operational plant in the Powder River Basin that was impaired to its estimated salvage value of $2.4 million, using the income approach and Level 3 fair value inputs, with no comparative activity in the prior period and (ii) $0.8 million due to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems in 2014.

Interest Income – Affiliates and Interest Expense



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


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

Interest expense increased by $37.1 million for the year ended December 31, 2015, primarily due to (i) $14.4 million in accretion recorded to interest expense for the Deferred purchase price obligation - Anadarko, (ii) $11.4 million in interest incurred on the 2025 Notes issued in June 2015, (iii) $4.8 million of interest incurred on the 2044 Notes issued in March 2014, (iv) additional interest incurred on the XXX 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 XXX 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

XXX is not a taxable entity for U.S. federal income tax purposes. However, WES’s income apportionable to Texas is subject to Texas margin tax. For the periods presented, the 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 the XXX assets acquired from Anadarko, and WES’s share of Texas margin tax.

Texas House Xxxx 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25%. The law became effective January 1, 2016. XXX is required to include the impact of the law change on its deferred state income taxes in the period enacted. The adjustment, a reduction in deferred state income taxes in the amount of $2.2 million, was recorded in June 2015 and is included in the income tax (benefit) expense for the year ended December 31, 2015.

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

KEY PERFORMANCE METRICS



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

NM-Not meaningful

⁽¹⁾

Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from WES’s 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 XXX Evaluates Its 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 WES’s 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 XXX Evaluates Its 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 XXX Evaluates Its 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 Xxxxxxx complex due to lower average pricing, at the Non-Operated Marcellus Interest systems due to a decrease in the average gathering rate and at the Chipeta complex due to lower volumes, as well as the sale of the Dew and Pinnacle systems in July 2015.

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

XXX has made cash distributions to its unitholders each quarter since its IPO and has increased its quarterly distribution each quarter since the second quarter of 2009. On January 21, 2016, the Board of Directors of XXX GP declared a cash distribution to XXX unitholders of $0.800 per unit, or $152.6 million in aggregate, including incentive distributions, but excluding distributions on XXX Class C units. The cash distribution was paid on February 11, 2016, to XXX unitholders of record at the close of business on February 1, 2016. In connection with the closing of the DBM acquisition in November 2014, XXX 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.

WES’s management continuously monitors its leverage position and coordinates its capital expenditure program, quarterly distributions and acquisition strategy with its expected cash flows and projected debt-repayment schedule. WES’s management 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, XXX has the ability to sell securities under its shelf registration statements. WES’s ability to generate cash flows is subject to a number of factors, some of which are beyond its control. Read Risk Factors under Part I, Item 1A of our 2015 Form 10-K.

Working capital. As of December 31, 2015, XXX had $63.7 million of working capital, which it defines as the amount by which current assets exceed current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. 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, WES’s customers, and the level and timing of its spending for maintenance and expansion activity. As of December 31, 2015, XXX had $893.6 million available for borrowing under the XXX RCF. In addition, we have $30.0 million available for borrowing under the WGP WCF. 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. WES’s business is capital intensive, requiring significant investment to maintain and improve existing facilities or develop new midstream infrastructure. XXX categorizes 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 WES’s 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 WES’s 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. WES’s capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:



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

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

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

⁽¹⁾

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


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


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

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

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

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

XXX estimates its total capital expenditures for the year ended December 31, 2016, including its 75% share of Chipeta’s capital expenditures and excluding acquisitions, to be between $450 million and $490 million and its 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 Xxxxxx Residue Line at WES’s DBM complex. WES’s future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to it, which are dependent, in part, on the drilling activities of Anadarko and third-party producers. XXX expects to fund future capital expenditures from cash flows generated from operations, interest income from its note receivable from Anadarko, borrowings under the XXX RCF, the issuance of additional XXX units or debt offerings.

WES’s historical cash flow. The following table and discussion present a summary of WES’s 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 WES’s results of operations as compared to the prior periods.

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


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


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


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


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


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


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

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


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


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


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


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


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


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


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


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


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

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


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


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


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


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


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


•	$38.7 million of capital contributions to the Mont Belvieu JV to fund WES’s 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 the XXX RCF;


•	$545.1 million of distributions paid to XXX unitholders;


•	$49.8 million of net distributions to Anadarko representing intercompany transactions attributable to WES’s 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 XXX 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 the XXX RCF;


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


•	$57.4 million of net proceeds from sales of XXX common units under its $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 WES’s 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 the WES November 2014 equity offering, including net proceeds from a capital contribution by WES GP, 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 WES 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 the WES RCF;


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


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


•	$100.0 million of net proceeds from the offering of additional WES 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 the WES RCF;


•	$83.2 million of net proceeds from sales of WES common units under WES’s $125.0 million COP, including net proceeds from capital contributions by WES GP;


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


•	$650.0 million of repayments of outstanding borrowings under the WES RCF;


•	$408.6 million of distributions paid to WES unitholders;


•	$16.4 million of net distributions to Anadarko representing intercompany transactions attributable to WES’s 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 the WES May 2013 equity offering, including net proceeds from a capital contribution by WES GP, $245.0 million of which was used to repay a portion of the outstanding borrowings under the WES RCF;


•	$299.0 million of borrowings to fund capital expenditures;


•	$273.7 million of net proceeds from WES’s December 2013 equity offering, including net proceeds from a capital contribution by WES GP, $215.0 million of which was used to repay a portion of the outstanding borrowings under the WES RCF;


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


•	$247.6 million of net proceeds from the WES 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 the outstanding borrowings under the WES RCF;


•	$265.5 million of net contributions from Anadarko representing intercompany transactions attributable to WES’s 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 WES common units under WES’s $125.0 million COP, including net proceeds from capital contributions by WES GP;


•	$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 the WES RCF;


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


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

Debt and credit facility. At December 31, 2015, WES’s 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 the WES RCF. As of December 31, 2015, the carrying value of WES’s 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.

WES Senior Notes. The 2025 Notes issued in June 2015 were offered at a price to the public of 98.789% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2025 Notes is 4.205%. Interest is paid semi-annually on June 1 and December 1 of each year. Proceeds (net of underwriting discount of $3.3 million, original issue discount and debt issuance costs) were used to repay a portion of the amount outstanding under the WES RCF.

The 2044 Notes issued in March 2014 were offered at a price to the public of 98.443% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2044 Notes is 5.633%. Interest is paid semi-annually on April 1 and October 1 of each year. Proceeds (net of underwriting discount of $3.5 million, original issue discount and debt issuance costs) were used to repay amounts then outstanding under the WES RCF and for general partnership purposes.

The 2018 Notes issued in March 2014 were offered at a price to the public of 100.857% of the face amount. Including the effects of the issuance premium for the March 2014 offering, the issuance discount for the August 2013 offering of 2018 Notes and underwriting discounts, the effective interest rate of the 2018 Notes is 2.743%. Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $0.6 million, original issue premium and debt issuance costs) were used to repay amounts then outstanding under the WES RCF and for general partnership purposes.

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

WES RCF. The $1.2 billion WES 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 WES’s senior unsecured debt rating. WES is required to pay a quarterly facility fee currently ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), based upon WES’s senior unsecured debt rating. As of December 31, 2015, WES had $300.0 million of outstanding borrowings, $6.4 million in outstanding letters of credit and $893.6 million available for borrowing under the WES RCF. At December 31, 2015, the interest rate on the WES RCF was 1.73%, the facility fee rate was 0.20% and WES was in compliance with all covenants under the WES 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 WES RCF continues to contain certain covenants that limit, among other things, WES’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of its business, enter into certain affiliate transactions and use proceeds other than for partnership purposes. The WES 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, WES was in compliance with all remaining covenants under the WES RCF.

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

In connection with the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests, WES GP and other wholly owned subsidiaries of Anadarko entered into indemnification agreements, whereby such subsidiaries agreed to indemnify WES GP for any recourse liability it may have for WES 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 WES RCF borrowings outstanding related to the aforementioned acquisitions.

WES GP, 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 WES GP by an amount equal to any amounts payable to the WES GP 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 by WES 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 WES’s share in the Net Earnings (see definition below) of the DBJV system for the calendar years 2018 and 2019, less (b) WES’s share of all capital expenditures incurred for the DBJV system between March 1, 2015, and February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to the DBJV system on an accrual basis. As of the acquisition date, the estimated future payment obligation (based on management’s estimate of WES’s share of forecasted Net Earnings and capital expenditures for the DBJV system) was $282.8 million, which had a net present value of $174.3 million, using a discount rate of 10%. As of December 31, 2015, the net present value of this obligation was $188.7 million and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion expense for the year ended December 31, 2015 was $14.4 million and zero for each of the years ended December 31, 2014 and 2013, and has been recorded as a charge to interest expense. 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. WES may issue an indeterminate amount of common units and various debt securities under its effective shelf registration statements on file with the SEC. WES issues common units under its $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, WES 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 by WES under its $500.0 million COP.

Credit risk. As stated above, our assets consist solely of ownership interests in WES. Accordingly, we are dependent upon WES’s ability to pay cash distributions to us. WES bears credit risk represented by its exposure to non-payment or non-performance by its 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 WES for services rendered or volumes owed pursuant to gas imbalance agreements. WES examines and monitors the creditworthiness of third-party customers and may establish credit limits for third-party customers. A substantial portion of WES’s throughput, however, comes from producers that have investment-grade ratings.

WES is dependent upon a single producer, Anadarko, for a substantial portion of its volumes, and WES does not maintain a credit limit with respect to Anadarko. Consequently, WES is 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.

WES expects its exposure to concentrated risk of non-payment or non-performance to continue for as long as it remains substantially dependent on Anadarko for its revenues. Additionally, WES is exposed to credit risk on the note receivable from Anadarko. WES is also party to agreements with Anadarko under which Anadarko is required to indemnify WES 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, WES has entered into various commodity price swap agreements with Anadarko in order to reduce its exposure to a majority of the commodity price risk inherent in its percent-of-proceeds and keep-whole contracts, and is 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.

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

CONTRACTUAL OBLIGATIONS

The following is a summary of WES’s 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 the WES 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 WES expansion projects. WES has 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. WGP, through its partnership interests in WES, is 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. WES regularly monitors the remediation and reclamation process and the liabilities recorded and believes that the amounts reflected in its 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 WES’s behalf, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting WES’s operations, for which it charges WES rent. The amounts above represent existing contractual operating lease obligations that may be assigned or otherwise charged to WES pursuant to the reimbursement provisions of the WES omnibus agreement. See Note 13—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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

For additional information on contracts, obligations and arrangements we and WES 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 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. WES’s management considers the following to be its most critical accounting estimates that involve judgment and it discusses the selection and development of these estimates with WES GP’s Audit Committee. For additional information concerning 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 WES’s long-lived assets is 24 years. If the depreciable lives of WES’s assets were reduced by 10%, WES estimates that annual depreciation expense would increase by $29.0 million, which would result in a corresponding reduction in WES’s 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 WES assets acquired by WES 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, WES’s management evaluates changes in its business and economic conditions and their implications for recoverability of the assets’ carrying amounts. Since a significant portion of WES’s 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 WES’s operations, may necessitate assessment of the carrying amount of its 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 WES’s customers, as well as other factors affecting estimated future net cash flows. The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. See Note 7—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for a description of impairments recorded during the years ended December 31, 2015, 2014 and 2013.

Impairments of goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the assets WGP, through its consolidation of WES, has 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, WES’s allocated goodwill balance does not represent, and in some cases is significantly different from, the difference between the consideration WES paid for its acquisitions from Anadarko and the fair value of such net assets on their respective acquisition dates.

WES evaluates 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 WES has 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, WES recorded $284.7 million of goodwill. WES also allocated $5.1 million of goodwill to its 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 WES concludes 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, WES 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, relevant events and circumstances are assessed, including the following:


•	significant changes in WES’s 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 WES’s peers.

In this manner, estimating the fair value of WES’s reporting units was not necessary based on the qualitative evaluation as of October 1, 2015. Given declines in WES’s unit price and declines in commodity markets through the end of 2015, WES 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 WES’s reporting units was not necessary at that time either. However, fair-value estimates of WES’s 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 WES’s reporting units are not available, WES’s 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, WES’s 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 WES’s projected EBITDA. A lower fair-value estimate in the future for any of WES’s 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 WES’s most recent goodwill impairment test, WES concluded, based on a qualitative assessment, that it is more likely than not that the fair value of each reporting unit exceeded the carrying value of the reporting unit. Therefore, no goodwill impairment was indicated, and no goodwill impairment has been recognized in our consolidated financial statements.

Impairments of intangible assets. WES’s intangible asset balance as of December 31, 2015 and 2014, primarily represents the fair value, net of amortization, of (i) contracts WES 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 WES 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 WES’s 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 WES’s business plans and investment decisions.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements. XXX does not have any off-balance sheet arrangements other than operating leases and standby letters of credit. The information pertaining to operating leases and WES’s 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.

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COMMONLY USED TERMS AND DEFINITIONS

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