Exhibit

EX-99.1 2 wesop2018amarecast-ex991.htm EXHIBIT 99.1 WES OP 2018 RECAST Exhibit

EXHIBIT 99.1

On February 28, 2019, in connection with the closing of the Merger (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), (i) Western Gas Partners, LP changed its name to Western Midstream Operating, LP and (ii) Western Gas Equity Partners, LP changed its name to Western Midstream Partners, LP. Exhibit 99.1 of this Current Report on Form 8-K, will refer to the reporting entities by their names as of the original filing date of the Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”), filed with the U.S. Securities and Exchange Commission on February 20, 2019.

The Western Gas Partners, LP (the “Partnership”) 2018 Form 10-K is hereby recast by this Current Report on Form 8-K as follows:


•	the selected Business and Properties sections included herein supersede the corresponding sections in Part I, Items 1 and 2 of the 2018 Form 10-K;


•	the Selected Financial and Operating Data included herein supersedes Part II, Item 6 of the 2018 Form 10-K;


•	the Management’s Discussion and Analysis of Financial Condition and Results of Operations included herein supersedes Part II, Item 7 of the 2018 Form 10-K;


•	the Quantitative and Qualitative Disclosures About Market Risk included herein supersedes Part II, Item 7A of the 2018 Form 10-K; and

•

the Financial Statements and Supplementary Data included herein supersedes Part II, Item 8 of the 2018 Form 10-K, except for the Report of Management, Management’s Assessment of Internal Control over Financial Reporting and the Report of Independent Registered Public Accounting Firm with regard to internal control over financial reporting, included on pages 111 and 112 of the 2018 Form 10-K, which are not impacted by this Current Report on Form 8-K.

There have been no revisions or updates to any other sections of the 2018 Form 10-K other than the revisions noted above. Except for events reported in Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K, the items included in Exhibit 99.1 to this Current Report on Form 8-K do not reflect events occurring after the filing of the 2018 Form 10-K or modify or update any related disclosures. This Current Report on Form 8-K should be read in conjunction with the 2018 Form 10-K, and any references herein to Items 1 and 2 under Part I and Items 6, 7, 7A and 8 under Part II of the 2018 Form 10-K refer to Exhibit 99.1 to this Current Report on Form 8-K. As of the date of this Current Report on Form 8-K, future references to the Partnership’s historical financial statements should be made to this Current Report as well as future quarterly and annual reports on Forms 10-Q and Form 10-K, respectively.

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Item		Page
	PART I

1 and 2.	Business and Properties	8
	General Overview	8
	Our Assets and Areas of Operations	9
	Acquisitions and Divestitures	10
	Strategy	11
	Competitive Strengths	12
	Our Relationship with Anadarko Petroleum Corporation	13
	Industry Overview	14
	Properties	17
	Competition	33

	PART II

6.	Selected Financial and Operating Data	33
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
	Executive Summary	36
	Items Affecting the Comparability of Our Financial Results	38
	Our Operations	40
	How We Evaluate Our Operations	41
	General Trends and Outlook	46
	Equity Offerings	47
	Results of Operations	48
	Operating Results	48
	Key Performance Metrics	57
	Liquidity and Capital Resources	58
	Contractual Obligations	67
	Critical Accounting Estimates	68
	Off-Balance Sheet Arrangements	69
	Recent Accounting Developments	69
7A.	Quantitative and Qualitative Disclosures About Market Risk	70
8.	Financial Statements and Supplementary Data	71

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COMMONLY USED TERMS AND DEFINITIONS

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

Additional DBJV System Interest: Our additional 50% interest in the DBJV system acquired from a third party in March 2017.

AESC: Anadarko Energy Services Company.

Affiliates: Subsidiaries of Anadarko, excluding us, but including equity interests in Fort Union, White Cliffs, Rendezvous, the Mont Belvieu JV, TEP, TEG, FRP, Whitethorn, Cactus II, Saddlehorn, Panola, Mi Vida and Ranch Westex.

AMA: The Anadarko Midstream Assets, which are comprised of the Wattenberg processing plant, Wamsutter pipeline, DJ Basin oil system, DBM oil system, APC water systems, the 20% interest in Saddlehorn, the 15% interest in Panola, the 50% interest in Mi Vida and the 50% interest in Ranch Westex.

AMH: APC Midstream Holdings, LLC.

AMM: Anadarko Marcellus Midstream, L.L.C.

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

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

Bbls/d: Barrels per day.

Board of Directors or Board: The board of directors of our general partner.

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

Cactus II: Cactus II Pipeline LLC.

Chipeta: Chipeta Processing, LLC.

Chipeta LLC agreement: Chipeta’s limited liability company agreement, as amended and restated as of July 23, 2009.

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

COSF: Centralized oil stabilization facility.

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

DBJV: Delaware Basin JV Gathering LLC.

DBJV system: A gathering system and related facilities located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties in West Texas, part of the West Texas complex effective January 1, 2018.

DBM: Delaware Basin Midstream, LLC.

DBM complex: The cryogenic processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico, part of the West Texas complex effective January 1, 2018.

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DBM water systems: The produced water gathering and disposal systems in West Texas, including the APC water systems.

Delivery point: The point where hydrocarbons are delivered by a processor or transporter to a producer, shipper or purchaser, typically the inlet at the interconnection between the gathering or processing system and the facilities of a third-party processor or transporter.

DJ Basin complex: The Platte Valley system, Wattenberg system, Lancaster plant and Wattenberg processing plant.

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 How We Evaluate Our Operations under Part II, Item 7 of Exhibit 99.1 to this Current Report on Form 8-K.

End-use markets: The ultimate users/consumers of transported energy products.

Equity investment throughput: Our 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput, 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP, TEG, Whitethorn and Saddlehorn throughput, 33.33% share of average FRP throughput, 50% share of average Mi Vida and Ranch Westex throughput and 15% share of average Panola throughput.

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

FERC: The Federal Energy Regulatory Commission.

Fort Union: Fort Union Gas Gathering, LLC.

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

FRP: Front Range Pipeline LLC.

GAAP: Generally accepted accounting principles in the United States.

General partner: Western Gas Holdings, LLC.

Gpm: Gallons per minute, when used in the context of amine treating capacity.

Hydraulic fracturing: The injection of fluids into the wellbore to create fractures in rock formations, stimulating the production of oil or gas.

IDRs: Incentive distribution rights.

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

IPO: Initial public offering.

Joule-Thompson (JT): A type of processing plant that uses the Joule-Thompson effect to cool natural gas by expanding the gas from a higher pressure to a lower pressure, which reduces the temperature.

LIBOR: London Interbank Offered Rate.

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

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MBbls/d: Thousand barrels per day.

Merger: The merger of Clarity Merger Sub, LLC, a wholly owned subsidiary of WGP, with and into the Partnership, with the Partnership continuing as the surviving entity and a subsidiary of WGP, which is expected to close in the first quarter of 2019.

Merger Agreement: The Contribution Agreement and Agreement and Plan of Merger, dated November 7, 2018, by and among WGP, the Partnership, Anadarko and certain of their affiliates, pursuant to which the parties thereto agreed to effect the Merger and certain other transactions.

MGR: Mountain Gas Resources, LLC.

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

Mi Vida: Mi Vida JV LLC.

MIGC: MIGC, LLC.

MLP: Master limited partnership.

MMBtu: Million British thermal units.

MMcf: Million cubic feet.

MMcf/d: 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: The 33.75% interest in the Liberty and Rome gas gathering systems and related facilities located in northern Pennsylvania that was transferred to a third party in March 2017 pursuant to the Property Exchange.

NYSE: New York Stock Exchange.

NYMEX: New York Mercantile Exchange.

OTTCO: Overland Trail Transmission, LLC.

Panola: Panola Pipeline Company, LLC.

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

Play: A group of gas or oil fields that contain known or potential commercial amounts of petroleum and/or natural gas.

Produced water: Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.

Property Exchange: Our acquisition of the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, as further described in our Forms 8-K filed with the SEC on February 9, 2017, and March 23, 2017.

Ranch Westex: Ranch Westex JV LLC.

RCF: Our senior unsecured revolving credit facility.

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

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

Refrigeration: A method of processing natural gas by reducing the gas temperature with the use of an external refrigeration system.

Rendezvous: Rendezvous Gas Services, LLC.

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

ROTF: Regional oil treating facility.

Saddlehorn: Saddlehorn Pipeline Company, LLC.

SEC: U.S. Securities and Exchange Commission.

Springfield: Springfield Pipeline LLC.

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

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

Springfield system: The Springfield gas gathering system and Springfield oil gathering system.

Stabilization: The process of separating very light hydrocarbon gases, methane and ethane in particular, from heavier hydrocarbon components. This process reduces the volatility of the liquids during transportation and storage.

Tailgate: The point at which processed natural gas and/or natural gas liquids leave a processing facility for end-use markets.

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.

WES LTIP: With respect to awards granted prior to October 17, 2017, the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “WES 2008 LTIP”), which was adopted by our general partner in connection with our IPO in 2008, and, with respect to awards granted after October 17, 2017, the Western Gas Partners, LP 2017 Long-Term Incentive Plan, which was approved by our common and Class C unitholders on October 17, 2017.

West Texas complex: The DBM complex and DBJV and Haley systems, all of which were combined into a single complex effective January 1, 2018.

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.

WGRI: Western Gas Resources, Inc.

White Cliffs: White Cliffs Pipeline, LLC.

Whitethorn LLC: Whitethorn Pipeline Company LLC.

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364-day Facility: Our 364-day senior unsecured credit agreement.

$500.0 million COP: The continuous offering program that may be undertaken pursuant to the registration statement filed with the SEC in July 2017 for the issuance of up to an aggregate of $500.0 million of our common units.

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PART I

On February 28, 2019, in connection with the closing of the Merger (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), (i) Western Gas Partners, LP changed its name to Western Midstream Operating, LP and (ii) Western Gas Equity Partners, LP changed its name to Western Midstream Partners, LP. Items 1 and 2 of Exhibit 99.1 of this Current Report on Form 8-K, will refer to the reporting entities by their names as of the original filing date of the Form 10-K for the year ended December 31, 2018, filed with the SEC on February 20, 2019.

Items 1 and 2. Business and Properties

GENERAL OVERVIEW

We are a growth-oriented Delaware MLP formed by Anadarko in 2007 to acquire, own, develop and operate midstream assets. We are engaged in the business of gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, NGLs and crude oil; and gathering and disposing of produced water. In addition, in our capacity as a processor of natural gas, we also buy and sell natural gas, NGLs and condensate on behalf of ourselves and as agent for our customers under certain of our contracts. We provide these midstream services for Anadarko, as well as for third-party customers. As of December 31, 2018, our common units were publicly traded on the NYSE under the symbol “WES.”

WGP, a Delaware MLP formed by Anadarko in September 2012, owns our general partner and a significant limited partner interest in us. As of December 31, 2018, WGP’s common units were publicly traded on the NYSE under the symbol “WGP.” WGP GP is a wholly owned subsidiary of Anadarko.

Available information. We electronically file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents with the SEC under the Exchange Act. From time to time, we may also file registration and related statements pertaining to equity or debt offerings.

We provide access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing such materials with the SEC, on our website located at www.westernmidstream.com. The public may also obtain such reports from the SEC’s website at www.sec.gov.

Our Corporate Governance Guidelines, Code of Ethics for our Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics and the charters of the Audit Committee and the Special Committee of our Board of Directors are also available on our website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s corporate secretary at our principal executive office. Our principal executive offices are located at 1201 Lake Robbins Drive, The Woodlands, TX 77380-1046. Our telephone number is 832-636-6000.

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OUR ASSETS AND AREAS OF OPERATION

As of December 31, 2018, our assets and investments, including AMA, consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems ⁽¹⁾	17	2	3	2
Treating facilities	34	3	—	3
Natural gas processing plants/trains	23	3	—	5
NGLs pipelines	2	—	—	4
Natural gas pipelines	5	—	—	—
Oil pipelines	3	1	—	3


⁽¹⁾	Includes the DBM water systems.

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These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. The following table provides information regarding our assets by geographic region, as of and for the year ended December 31, 2018, excluding Mentone Train II at the West Texas complex and the Latham processing plant at the DJ Basin complex, which are currently under construction in West Texas and Colorado, respectively, (see Assets Under Development within these Items 1 and 2):



Area	Asset Type	Miles of Pipeline ⁽¹⁾	Approximate Number of Active Receipt Points ⁽¹⁾	Compression (HP) ^{(1) (2)}	Processing or Treating Capacity (MMcf/d) ⁽¹⁾	Processing, Treating or Disposal Capacity (MBbls/d) ⁽¹⁾	Average Gathering, Processing, Treating and Transportation Throughput (MMcf/d) ⁽³⁾	Average Gathering, Treating, Transportation and Disposal Throughput (MBbls/d) ⁽⁴⁾
Rocky Mountains	Gathering, Processing and Treating	7,210	3,824	553,465	3,540	187	2,254	105
	Transportation	2,147	65	—	—	—	79	47
Texas / New Mexico	Gathering, Processing, Treating and Disposal	3,686	1,273	692,304	1,695	1,144	1,635	459
	Transportation	1,895	24	—	—	—	—	164
North-central Pennsylvania	Gathering	146	59	9,660	—	—	100	—
Total		15,084	5,245	1,255,429	5,235	1,331	4,068	775


⁽¹⁾	All system metrics are presented on a gross basis and include owned, rented and leased compressors at certain facilities. Includes horsepower associated with liquid pump stations. Includes bypass capacity at the DJ Basin and West Texas complexes.


⁽²⁾	Excludes compression horsepower for transportation.


⁽³⁾	Includes 100% of Chipeta throughput, a 50.1% share of Springfield gas gathering throughput, a 22% share of Rendezvous throughput, a 14.81% share of Fort Union throughput, and a 50% share of Mi Vida and Ranch Westex throughput.

⁽⁴⁾

Consists of throughput on the Chipeta NGL pipeline, an NGLs line at the Brasada complex and at the DBM water systems, a 50.1% share of Springfield oil gathering throughput, a 10% share of White Cliffs throughput, a 25% share of Mont Belvieu JV throughput, a 20% share of TEG, TEP, Whitethorn and Saddlehorn throughput, a 33.33% share of FRP throughput and a 15% share of Panola throughput. See Properties below for further descriptions of these systems.

Our operations are organized into a single operating segment that engages in gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, NGLs and crude oil; and gathering and disposing of produced water. We provide these midstream services for Anadarko, as well as for third-party customers in the United States. See Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for disclosure of revenues, profits and total assets for the years ended December 31, 2018, 2017 and 2016.

ACQUISITIONS AND DIVESTITURES

Acquisition of AMA. In February 2019, we acquired AMA from Anadarko. See Note 3—Acquisitions and Divestitures and Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for further information.

Whitethorn LLC acquisition. In June 2018, we acquired a 20% interest in Whitethorn LLC, which owns a crude oil and condensate pipeline that originates in Midland, Texas and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with our investment in Whitethorn, we will share proportionally in the commercial activities. We acquired our 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method.

Cactus II acquisition. In June 2018, we acquired a 15% interest in Cactus II, which will own a crude oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline is under construction and is expected to become operational in late 2019. We acquired our 15% interest from a third party via an initial net investment of $12.1 million, which represented our share of costs incurred up to the date of acquisition. The initial investment was funded with cash on hand and the interest in Cactus II is accounted for under the equity method.

Newcastle system divestiture. In December 2018, the Newcastle system, located in Northeast Wyoming, was sold to a third party for $3.2 million, resulting in a net gain on sale of $0.6 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. We previously held a 50% interest in, and operated, the Newcastle system.

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Presentation of Partnership assets. The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by us, including AMA, as of December 31, 2018 (see Note 10—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K). Because Anadarko controls us through its control of WGP, which owns the entire interest in our general partner, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us. Further, after an acquisition of assets from Anadarko, we are required to recast our financial statements to include the activities of such Partnership assets from the date of common control.

For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko, including AMA, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the Partnership assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership assets prior to our acquisitions from Anadarko as being “our” historical financial results.

STRATEGY

Our primary business objective is to continue to increase our cash distributions per unit over time. To accomplish this objective, we intend to execute the following strategy:

•

Capitalizing on organic growth opportunities. We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ midstream service needs that result from their drilling activity in our areas of operation. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our infrastructure, operating expertise and customer relationships to meet new or increased demand of our services.


•	Increasing third-party volumes to our systems. We continue to actively market our midstream services to, and pursue strategic relationships with, third-party customers with the intention of attracting additional volumes and/or expansion opportunities.


•	Pursuing accretive acquisitions. We expect to continue to pursue accretive acquisitions of midstream assets.


•	Managing commodity price exposure. We intend to continue limiting our direct exposure to commodity price changes and promote cash flow stability by pursuing a contract structure designed to mitigate exposure to a substantial majority of the commodity price uncertainty through the use of fee-based contracts.

•

Maintaining investment grade metrics. We intend to operate at appropriate leverage and distribution coverage levels in line with other partnerships in our sector that maintain investment grade credit ratings. By maintaining investment grade credit metrics, in part through staying within leverage ratios appropriate for investment-grade partnerships, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of fixed-income capital, which would enhance our accretion and overall return.

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COMPETITIVE STRENGTHS

We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective because of the following competitive strengths:

•

Affiliation with Anadarko. We believe Anadarko is motivated to promote and support the successful execution of our business plan and utilize its relationships within the energy industry and the strength of its asset portfolio to pursue projects that help to enhance the value of our business. This includes the ability of Anadarko to secure equity investment opportunities for us in connection with the commitments it makes to other midstream companies. See Our Relationship with Anadarko Petroleum Corporation below.

•

Substantial presence in basins with historically strong producer economics. Certain of our systems are in areas, such as the Delaware and DJ Basins, which have historically seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas serve production where the hydrocarbons contain not only natural gas, but also crude oil, condensate and NGLs.

•

Well-positioned and well-maintained assets. We believe that our asset portfolio, which is located in geographically diverse areas of operation, provides us with opportunities to expand and attract additional volumes to our systems from multiple productive reservoirs. Moreover, our portfolio consists of high-quality, well-maintained assets for which we have implemented modern processing, treating, measurement and operating technologies.

•

Commodity price and volumetric risk mitigation. We believe a substantial majority of our cash flows are protected from direct fluctuations caused by commodity price volatility, as 89% of our wellhead natural gas volumes (excluding equity investments) and 100% of our crude oil and produced water throughput (excluding equity investments) were attributable to fee-based contracts for the year ended December 31, 2018. In addition, we mitigate volumetric risk by entering into contracts with cost of service structures and/or minimum volume commitments. For the year ended December 31, 2018, 62% of our natural gas throughput and 73% of our crude oil, NGLs and produced water throughput were supported by either minimum volume commitments with associated deficiency payments or cost of service commitments.

•

Liquidity to pursue expansion and acquisition opportunities. We believe our operating cash flows, borrowing capacity, long-term relationships and reasonable access to debt and equity capital markets provide us with the liquidity to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. As of December 31, 2018, we had $1.3 billion in available borrowing capacity under the RCF.

•

Consistent track record of accretive acquisitions. Since our IPO in 2008, our management team has successfully executed eleven related-party acquisitions and nine third-party acquisitions, with an aggregate acquisition value of $6.5 billion. Our management team has demonstrated its ability to identify, evaluate, negotiate, consummate and integrate strategic acquisitions and expansion projects, and it intends to use its experience and reputation to continue to grow the Partnership through accretive acquisitions, focusing on opportunities to improve throughput volumes and cash flows.

We believe that we will effectively leverage our competitive strengths to successfully implement our strategy. However, our business involves numerous risks and uncertainties that may prevent us from achieving our primary business objective. For a more complete description of the risks associated with our business, read Risk Factors under Part I, Item 1A of our 2018 Form 10-K.

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OUR RELATIONSHIP WITH ANADARKO PETROLEUM CORPORATION

Our operations and activities are managed by our general partner, which is indirectly controlled by Anadarko through WGP. Anadarko is among the largest independent oil and gas exploration and production companies in the world. Anadarko’s upstream oil and gas business explores for and produces natural gas, crude oil, condensate and NGLs.

We believe that one of our principal strengths is our relationship with Anadarko, and that Anadarko, through its significant indirect economic interest in us, will continue to be motivated to promote and support the successful execution of our business plan and to pursue projects that help to enhance the value of our business.

As of December 31, 2018, WGP held 50,132,046 of our common units, representing a 29.6% limited partner interest in us, and, through its ownership of our general partner, indirectly held 2,583,068 general partner units, representing a 1.5% general partner interest in us, and 100% of our IDRs. As of December 31, 2018, other subsidiaries of Anadarko collectively held 2,011,380 common units and 14,372,665 Class C units, representing an aggregate 9.7% limited partner interest in us. As of December 31, 2018, the public held 100,465,859 common units, representing the remaining 59.2% limited partner interest in us.

For the year ended December 31, 2018, production owned or controlled by Anadarko represented (i) 7% of our natural gas gathering, treating and transportation throughput (excluding equity investment throughput), (ii) 40% of our natural gas processing throughput (excluding equity investment throughput), and (iii) 85% of our crude oil, NGLs and produced water gathering, treating, transportation and disposal throughput (excluding equity investment throughput). In addition, Anadarko supports our operations by providing dedications and/or minimum volume commitments with respect to a substantial portion of its throughput. In executing our growth strategy, which includes acquiring and constructing additional midstream assets, we are able to leverage Anadarko’s significant industry expertise.

During 2018, we had commodity price swap agreements with Anadarko to mitigate exposure to the commodity price risk inherent in our percent-of-proceeds, percent-of-product and keep-whole contracts at the DJ Basin complex and the MGR assets. These commodity price swap agreements expired without renewal on December 31, 2018. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

In connection with our IPO, we entered into an omnibus agreement with Anadarko and our general partner that governs our relationship with Anadarko regarding certain reimbursement and indemnification matters. Although we believe our relationship with Anadarko provides us with a significant advantage in the midstream sector, it is also a source of potential conflicts. For example, neither Anadarko nor WGP is restricted from competing with us. Given Anadarko’s significant indirect economic interest in us through its ownership of WGP, we believe it will be in Anadarko’s best economic interest for it to transfer additional assets to us over time. However, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to participate in such transactions. Should Anadarko choose to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us, nor are we obligated to participate in any such opportunities. We cannot state with any certainty which, if any, opportunities to acquire additional assets from Anadarko may be made available to us or if we will elect, or will have the ability, to pursue any such opportunities. See Risk Factors under Part I, Item 1A and Certain Relationships and Related Transactions, and Director Independence under Part III, Item 13 of our 2018 Form 10-K for more information.

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INDUSTRY OVERVIEW

The midstream industry is the link between the exploration for and production of natural gas, NGLs, and crude oil and the delivery of the resulting hydrocarbon components to end-use markets. Operators within this industry create value at various stages along the midstream value chain by gathering production from producers at the wellhead or production facility, separating the produced hydrocarbons into various components and delivering these components to end-use markets, and where applicable, gathering and disposing of produced water.

The following diagram illustrates the primary groups of assets found along the midstream value chain:

Natural Gas Midstream Services

Midstream companies provide services with respect to natural gas that are generally classified into the categories described below.

•

Gathering. At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads or production facilities in the area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing, if necessary. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.


•	Stabilization. Stabilization is a process that separates the heavier hydrocarbons (which are also valuable commodities) that are sometimes found in natural gas, typically referred to as “liquids-rich” natural gas, from the lighter components by using a distillation process or by reducing the pressure and letting the more volatile components flash.

•

Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.

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•	Treating and dehydration. To the extent that gathered natural gas contains water vapor or contaminants, such as carbon dioxide and hydrogen sulfide, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

•

Processing. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of heavier NGLs and contaminants, such as water and carbon dioxide, sulfur compounds, nitrogen or helium. Natural gas is processed to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas and to separate those hydrocarbon liquids from the gas that have higher value as NGLs. The removal and separation of individual hydrocarbons through processing is possible due to differences in molecular weight, boiling point, vapor pressure and other physical characteristics.


•	Fractionation. Fractionation is the process of applying various levels of higher pressure and lower temperature to separate a stream of NGLs into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.

•

Storage, transportation and marketing. Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located throughout the pipeline network or at major market centers to better accommodate seasonal demand and daily supply-demand shifts. We do not currently offer storage services.

Crude Oil Midstream Services

Midstream companies provide services with respect to crude oil that are generally classified into the categories described below.

•

Gathering. Crude oil gathering assets provide the link between crude oil production gathered at the well site or nearby collection points and crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries. Crude oil gathering assets generally consist of a network of small-diameter pipelines that are connected directly to the well site or central receipt points and deliver into large-diameter trunk lines. To the extent there are not enough volumes to justify construction of or connection to a pipeline system, crude oil can also be trucked from a well site to a central collection point.


•	Stabilization. Crude oil stabilization assets process crude oil to meet vapor pressure specifications. Crude oil delivery points, including crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries, often have specific requirements for vapor pressure and temperature, and for the amount of sediment and water that can be contained in any crude oil delivered to them.

Produced Water Midstream Services

The services provided by us and other midstream companies with respect to produced water are generally classified into the categories described below.


•	Gathering. Produced water often accounts for the largest byproduct stream associated with production of crude oil and natural gas. Produced water gathering assets provide the link between well sites or nearby collection points and disposal facilities.


•	Disposal. As a natural byproduct of crude oil and natural gas production, produced water must be recycled or disposed of in order to maintain production. Produced water disposal systems remove hydrocarbon products and other sediments from the produced water in compliance with applicable regulations and re-inject the produced water utilizing permitted disposal wells.

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Typical Contractual Arrangements

Midstream services, other than transportation, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical contract types, or combinations thereof, are described below:

•

Fee-based. Under fee-based arrangements, the service provider typically receives a fee for each unit of (i) natural gas, NGLs, or crude oil gathered, treated, processed and/or transported, or (ii) produced water gathered and disposed of, at its facilities. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing the service provider’s direct commodity price risk exposure.

•

Percent-of-proceeds, percent-of-value or percent-of-liquids. Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the service provider to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and/or NGLs.

•

Keep-whole. Keep-whole arrangements may be used for processing services. Under these arrangements, a customer provides liquids rich gas volumes to the service provider for processing. The service provider is obligated to return the equivalent gas volumes to the customer subsequent to processing. Due to the use and loss of volumes in processing, the service provider must purchase additional volumes to compensate the customer. In these arrangements, the service provider receives all or a portion of the NGLs produced in consideration for the service provided. These type of arrangements can expose the service provider to high levels of commodity price exposure associated with the volumes purchased to keep the customer whole, as well as for the consideration received.

See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for information regarding recognition of revenue under our contracts.

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PROPERTIES

The following sections describe in more detail the services provided by our assets in our areas of operation as of December 31, 2018.

GATHERING, PROCESSING AND TREATING

Overview - Rocky Mountains - Colorado and Utah



Location	Asset	Type	Processing / Treating Plants	Processing / Treating Capacity (MMcf/d) ⁽¹⁾	Processing / Treating Capacity (MBbls/d)	Compressors	Compression Horsepower	Gathering Systems	Pipeline Miles⁽²⁾
Colorado	DJ Basin complex ⁽³⁾	Gathering, Processing & Treating	12	1,300	32	131	313,537	2	3,215
Colorado	DJ Basin oil system	Gathering & Treating	6	—	155	20	5,645	1	316
Utah	Chipeta ⁽⁴⁾	Processing	3	790	—	12	74,875	—	2
Total			21	2,090	187	163	394,057	3	3,533


⁽¹⁾	Includes 160 MMcf/d of bypass capacity at the DJ Basin complex.


⁽²⁾	Includes 12 miles of transportation related to a crude oil pipeline at the DJ Basin oil system.


⁽³⁾	The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT, which is currently inactive, Wattenberg and Lancaster Trains I and II processing plants and the Wattenberg gathering system.


⁽⁴⁾	We are the managing member of and own a 75% interest in Chipeta, which owns the Chipeta processing complex.

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DJ Basin gathering, treating and processing complex


•	Customers. As of December 31, 2018, throughput at the DJ Basin complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, Anadarko’s production represented 64% of the DJ Basin complex throughput and the two largest third-party customers provided 17% of the throughput.


•	Supply. The DJ Basin complex is primarily supplied by the Wattenberg field. There were 2,122 active receipt points connected to the DJ Basin complex as of December 31, 2018. Anadarko holds interests in approximately 645,000 gross (460,000 net) acres within the DJ Basin and during the year ended December 31, 2018, turned 278 operated wells to sales in the DJ Basin.

•

Delivery points. As of December 31, 2018, the DJ Basin complex had various delivery point interconnections with DCP Midstream LP’s (“DCP”) gathering and processing system for gas not processed within the DJ Basin complex. The DJ Basin complex is connected to the Colorado Interstate Gas Company LLC’s pipeline (“CIG pipeline”) and Xcel Energy’s residue pipelines for natural gas residue takeaway and to Overland Pass Pipeline Company LLC’s pipeline and FRP’s pipeline for NGLs takeaway. In addition, the NGLs fractionator at the Platte Valley plant and associated truck-loading facility provides access to local NGLs markets.

DJ Basin oil gathering system, stabilization facility and storage


•	Customers. As of December 31, 2018, throughput at the DJ Basin oil system was from Anadarko and one third-party customer. For the year ended December 31, 2018, Anadarko’s production represented 97% of the DJ Basin oil system throughput.


•	Supply. The DJ Basin oil system, which is primarily supplied by the Wattenberg field, gathers high vapor pressure crude oil and delivers it to the COSF. The COSF includes two 250,000 barrel crude oil storage tanks and connectivity to local storage owned by SemCrude.


•	Delivery points. The COSF has market access to the White Cliffs pipeline, Saddlehorn pipeline, and rail loading facilities in Tampa, Colorado, as well as local markets.

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Chipeta processing complex


•	Customers. As of December 31, 2018, throughput at the Chipeta complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, Anadarko’s production represented 74% of the Chipeta complex throughput and the largest third-party customer provided 15% of the throughput.

•

Supply. The Chipeta complex is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko holds interests in 244,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Dominion Energy Questar Pipeline, LLC system (“Questar pipeline”) and Three Rivers Gathering, LLC’s system, which is owned by Andeavor Logistics LP (“Andeavor”).

•

Delivery points. The Chipeta plant delivers NGLs to Enterprise Products Partners LP’s (“Enterprise”) Mid-America Pipeline Company pipeline (“MAPL pipeline”), which provides transportation through Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas and ultimately to the NGLs fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has residue gas delivery points through the following pipelines delivering to markets throughout the Rockies and Western United States:


◦	CIG pipeline;


◦	Questar pipeline; and


◦	Wyoming Interstate Company’s pipeline (“WIC pipeline”).

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Overview - Rocky Mountains - Wyoming



Location	Asset	Type	Processing / Treating Plants	Processing / Treating Capacity (MMcf/d)	Compressors	Compression Horsepower	Gathering Systems	Pipeline Miles
Northeast Wyoming	Bison	Treating	3	450	9	14,645	—	—
Northeast Wyoming	Fort Union ⁽¹⁾	Gathering & Treating	3	295	3	5,454	1	315
Northeast Wyoming	Hilight	Gathering & Processing	2	60	34	36,554	1	1,232
Southwest Wyoming	Granger complex ⁽²⁾	Gathering & Processing	4	520	41	44,967	1	738
Southwest Wyoming	Red Desert complex ⁽³⁾	Gathering & Processing	1	125	25	50,303	1	1,054
Southwest Wyoming	Rendezvous ⁽⁴⁾	Gathering	—	—	5	7,485	1	338
Total			13	1,450	117	159,408	5	3,677


⁽¹⁾	We have a 14.81% interest in Fort Union.


⁽²⁾	The Granger complex includes the “Granger straddle plant,” a refrigeration processing plant.


⁽³⁾	The Red Desert complex includes the Red Desert cryogenic processing plant, which is currently inactive, and the Patrick Draw cryogenic processing plant.


⁽⁴⁾	We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.

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Northeast Wyoming

Bison treating facility


•	Customers. Throughput at the Bison treating facility was from two third-party customers as of December 31, 2018. The largest customer provided 75% of the throughput for the year ended December 31, 2018. In connection with Anadarko’s sale of its Powder River Basin coal-bed methane assets in 2015, Anadarko retained its throughput commitment to Bison through 2020.


•	Supply and delivery points. The Bison treating facility treats and compresses gas from coal-bed methane wells in the Powder River Basin of Wyoming. The Bison treating facility is directly connected to Fort Union’s pipeline and the Bison pipeline operated by TransCanada Corporation.

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Fort Union gathering system and treating facility


•	Customers. Moriah Powder River, LLC holds a majority of the firm capacity on the Fort Union system. To the extent capacity on the system is not used by this customer, it is available to third parties under interruptible agreements.


•	Supply. Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes from the Powder River Basin near Gillette, Wyoming that are either produced or gathered by the customer noted above and their affiliates. These volumes are gathered and treated under contracts with minimum volume commitments.


•	Delivery points. The Fort Union system delivers coal-bed methane gas to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:


◦	CIG pipeline;


◦	Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT pipeline”); and


◦	WIC pipeline.

These pipelines serve gas markets in the Rocky Mountains and Midwest regions of the United States.

Hilight gathering system and processing plant


•	Customers. As of December 31, 2018, gas gathered and processed through the Hilight system was from numerous third-party customers. The four largest producers provided 72% of the system throughput for the year ended December 31, 2018.


•	Supply. The Hilight gathering system serves the gas gathering needs of several conventional producing fields in Johnson, Campbell, Natrona and Converse Counties, Wyoming.


•	Delivery points. The Hilight plant delivers residue into our MIGC transmission line (see Transportation within these Items 1 and 2). Hilight is not connected to an active NGLs pipeline, resulting in all fractionated NGLs being sold locally through truck and rail loading facilities.

Southwest Wyoming

Granger gathering and processing complex


•	Customers. As of December 31, 2018, throughput at the Granger complex was from numerous third-party customers. The two largest third-party customers provided 78% of the Granger complex throughput for the year ended December 31, 2018.


•	Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas gathering system had 577 active receipt points as of December 31, 2018.


•	Delivery points. The residue from the Granger complex can be delivered to the following major pipelines:


◦	CIG pipeline;


◦	Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) via a connect with Andeavor’s Rendezvous pipeline (“Rendezvous pipeline”);


◦	Questar pipeline;


◦	Dominion Energy Overthrust Pipeline;


◦	The Williams Companies, Inc.’s Northwest Pipeline (“NWPL”);


◦	our OTTCO pipeline; and


◦	our Mountain Gas Transportation LLC pipeline.

The NGLs have market access to the MAPL pipeline, which terminates at Mont Belvieu, Texas, as well as to local markets.

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Red Desert gathering and processing complex


•	Customers. As of December 31, 2018, throughput at the Red Desert complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, 40% of the Red Desert complex throughput was from the two largest third-party customers and 2% was from Anadarko.


•	Supply. The Red Desert complex gathers, compresses, treats and processes natural gas and fractionates NGLs produced from the eastern portion of the Greater Green River Basin, providing service primarily to the Red Desert and Washakie Basins.


•	Delivery points. Residue from the Red Desert complex is delivered to the CIG and WIC pipelines, while NGLs are delivered to the MAPL pipeline, as well as to truck and rail loading facilities.

Rendezvous gathering system


•	Customers. As of December 31, 2018, throughput on the Rendezvous gathering system was primarily from two shippers that have dedicated acreage to the system.


•	Supply and delivery points. The Rendezvous gathering system provides high pressure gathering service for gas from the Jonah and Pinedale Anticline fields and delivers to our Granger plant, as well as Andeavor’s Blacks Fork gas processing plant, which connects to the Questar pipeline, NWPL and the Kern River pipeline via the Rendezvous pipeline.

Overview - Texas and New Mexico



Location	Asset	Type	Processing / Treating Plants	Processing / Treating Capacity (MMcf/d) ⁽¹⁾	Processing / Treating / Disposal Capacity (MBbls/d)	Compressors / Pumps ⁽²⁾	Compression Horsepower ⁽²⁾	Gathering Systems	Pipeline Miles ⁽³⁾
West Texas / New Mexico	West Texas complex ⁽⁴⁾	Gathering, Processing & Treating	12	1,170	34	246	405,445	3	1,620
West Texas	DBM oil system ⁽⁵⁾	Gathering & Treating	14	—	195	96	16,953	1	523
West Texas	DBM water systems	Gathering & Disposal	—	—	655	93	37,150	5	659
West Texas	Mi Vida ⁽⁶⁾	Processing	1	200	—	4	20,000	—	—
West Texas	Ranch Westex ⁽⁷⁾	Processing	2	125	—	2	10,090	—	6
East Texas	Mont Belvieu JV ⁽⁸⁾	Processing	2	—	170	—	—	—	—
South Texas	Brasada complex	Gathering, Processing & Treating	3	200	15	14	30,450	1	57
South Texas	Springfield system ⁽⁹⁾	Gathering and Treating	3	—	75	107	172,216	2	821
Total			37	1,695	1,144	562	692,304	12	3,686


⁽¹⁾	Includes 70 MMcf/d of bypass capacity at the West Texas complex.


⁽²⁾	Includes owned, rented and leased compressors and compression horsepower.


⁽³⁾	Includes 18 miles of transportation related to the Ramsey Residue Lines at the West Texas complex and 14 miles of transportation related to a crude oil pipeline at the DBM oil system.


⁽⁴⁾	The West Texas complex includes the DBM complex and DBJV and Haley systems. Excludes 2,000 gpm of amine treating capacity.


⁽⁵⁾	The DBM oil system includes three central production facilities and two ROTFs.


⁽⁶⁾	We own a 50% interest in Mi Vida, which owns a processing plant operated by a third party.


⁽⁷⁾	We own a 50% interest in Ranch Westex, which owns a processing plant operated by a third party.


⁽⁸⁾	We own a 25% interest in the Mont Belvieu JV, which owns two NGLs fractionation trains. A third party serves as the operator.


⁽⁹⁾	We own a 50.1% interest in the Springfield system and serve as the operator.

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West Texas gathering, treating and processing complex


•	Customers. As of December 31, 2018, throughput at the West Texas complex was from Anadarko and numerous third-party customers. For the year ended December 31, 2018, Anadarko’s production represented 30% of the West Texas complex throughput and the largest third-party customer provided 11% of the throughput.


•	Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring, Wolfcamp and Penn formations in the Delaware Basin portion of the Permian Basin. Anadarko holds interests in approximately 590,000 gross (240,000 net) acres within the Delaware Basin.

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•

Delivery points. Avalon, Bone Spring and Wolfcamp gas is dehydrated, compressed and delivered to the Ranch Westex and Mi Vida plants (see below) and within the West Texas complex for processing, while lean gas is delivered into Enterprise GC, L.P.’s pipeline for ultimate delivery into Energy Transfer LP’s (“ET”) Oasis pipeline (the “Oasis pipeline”). Residue gas produced at the West Texas complex is delivered to ET’s Red Bluff Express pipeline and the Ramsey Residue Lines, which extend from the complex to the south and to the north, with both lines connecting with Kinder Morgan, Inc.’s interstate pipeline system. NGLs production is delivered into the Sand Hills pipeline, Lone Star NGL LLC’s pipeline (“Lone Star pipeline”) and EPIC Y-Grade Pipeline, LP’s NGL pipeline. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

DBM oil gathering system, treating facilities and storage


•	Customers. As of December 31, 2018, throughput at the DBM oil system was from Anadarko and one third-party producer. For the year ended December 31, 2018, Anadarko’s production represented 90% of the DBM oil system throughput.


•	Supply. The DBM oil system is supplied from production from the Delaware Basin portion of the Permian Basin.


•	Delivery points. Crude oil treated at the DBM oil system and a third-party treating facility is delivered from the system into Plains All American Pipeline.

DBM produced water disposal systems


•	Customers. As of December 31, 2018, throughput at the DBM water systems was from Anadarko and nine third-party producers. Anadarko’s production represented 91% of the throughput for the year ended December 31, 2018.


•	Supply. Supply of produced water for the systems comes from production from the Delaware Basin portion of the Permian Basin.


•	Disposal. The DBM water systems gather and dispose produced water via subsurface injection or offload to third-party service providers. The systems’ injection wells are located in Loving, Reeves, and Ward Counties in Texas.

Mi Vida processing plant


•	Customers. As of December 31, 2018, throughput at the Mi Vida plant was from Anadarko and one third-party customer.


•	Supply and delivery points. The Mi Vida plant receives volumes from the West Texas complex and ET’s gathering system. Residue gas from the Mi Vida plant is delivered into the Oasis pipeline or Transwestern Pipeline Company LLC’s pipeline (“Transwestern pipeline”). NGLs production is delivered into the Lone Star pipeline.

Ranch Westex processing plant


•	Customers. As of December 31, 2018, throughput at the Ranch Westex plant was from Anadarko and one third-party customer.


•	Supply and delivery points. The Ranch Westex plant receives volumes from the West Texas complex and Crestwood Equity Partners LP’s gathering system. Residue gas from the Ranch Westex plant is delivered into the Oasis pipeline or Transwestern pipeline and NGLs production is delivered into the Lone Star pipeline.

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Mont Belvieu JV fractionation trains


•	Customers. The Mont Belvieu JV does not directly contract with customers, but rather is allocated volumes from Enterprise based on the available capacity of the other trains at Enterprise’s NGLs fractionation complex in Mont Belvieu, Texas.

•

Supply and delivery points. Enterprise receives volumes at its fractionation complex in Mont Belvieu, Texas via a large number of pipelines that terminate there, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline, TEP and Panola pipeline (see Transportation within these Items 1 and 2). Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminal.

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Brasada gathering, stabilization, treating and processing complex


•	Customers. Throughput at the Brasada complex was from one third-party customer as of December 31, 2018.


•	Supply. Supply of gas and NGLs comes from throughput gathered by the Springfield system.


•	Delivery points. The facility delivers residue gas into the Eagle Ford Midstream system operated by NET Midstream, LLC. It delivers stabilized condensate into Plains All American Pipeline and NGLs into the South Texas NGL Pipeline System operated by Enterprise.

Springfield gathering system, stabilization facility and storage


•	Customers. Throughput at the Springfield system was from numerous third-party customers as of December 31, 2018.


•	Supply. Supply of gas and oil comes from third-party production in the Eagleford shale.

•

Delivery points. The gas gathering system delivers rich gas to our Brasada complex, the Raptor processing plant owned by Targa Resources Corp. and Sanchez Midstream Partners LP, and to processing plants operated by Enterprise, ET and Kinder Morgan, Inc. The oil gathering system has delivery points to Plains All American Pipeline, Kinder Morgan, Inc.’s Double Eagle Pipeline, Hilcorp Energy Company’s Harvest Pipeline and NuStar Energy L.P.’s Pipeline.

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Overview - North-central Pennsylvania

Location

Asset

Type

Compressors

Compression Horsepower

Gathering Systems

Pipeline Miles

North-central Pennsylvania

Marcellus ⁽¹⁾

Gathering

9,660

146


⁽¹⁾	We own a 33.75% interest in the Marcellus Interest gathering systems.

Marcellus gathering systems


•	Customers. As of December 31, 2018, the Marcellus Interest gathering systems had multiple priority shippers. The largest producer provided 86% of the throughput for the year ended December 31, 2018. Capacity not used by priority shippers is available to third parties as determined by the operating partner, Alta Resources Development, LLC.


•	Supply and delivery points. The Marcellus Interest gathering systems are well positioned to serve dry gas production from the Marcellus shale. The Marcellus Interest gathering systems have access to Transcontinental Gas Pipe Line Company, LLC’s pipeline.

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Overview

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Location	Asset	Type	Pipeline Miles
Colorado, Kansas, Oklahoma	White Cliffs ^{(1) (2)}	Oil	1,054
Wyoming, Colorado, Kansas, Oklahoma	Saddlehorn^{(1) (3)}	Oil	600
Utah	GNB NGL ⁽¹⁾	NGLs	33
Northeast Wyoming	MIGC ⁽¹⁾	Gas	239
Southwest Wyoming	OTTCO	Gas	174
Southwest Wyoming	Wamsutter	Oil	47
Colorado, Oklahoma, Texas	FRP ^{(1) (4)}	NGLs	447
Texas, Oklahoma	TEG ⁽⁴⁾	NGLs	191
Texas	TEP ^{(1) (4)}	NGLs	593
Texas	Whitethorn ⁽⁵⁾	Oil	416
Texas	Panola^{(1) (6)}	NGL	248
Total			4,042


⁽¹⁾	White Cliffs, GNB NGL, MIGC, Saddlehorn, FRP, TEP and Panola are regulated by FERC.


⁽²⁾	We own a 10% interest in the White Cliffs pipeline, which is operated by a third party.


⁽³⁾	We own a 20% interest in the Saddlehorn pipeline, which is operated by a third party.


⁽⁴⁾	We own a 20% interest in TEG and TEP and a 33.33% interest in FRP. All three systems are operated by third parties.


⁽⁵⁾	We own a 20% interest in Whitethorn, which is operated by a third party.


⁽⁶⁾	We own a 15% interest in the Panola pipeline, which is operated by a third party.

Rocky Mountains - Colorado

White Cliffs pipeline

•

Customers. The White Cliffs pipeline had multiple committed shippers, including Anadarko, as of December 31, 2018. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual pipeline system provides crude oil takeaway capacity of approximately 190 MBbls/d from Platteville, Colorado to Cushing, Oklahoma. During 2019, one of the pipelines will be converted from crude service to NGL Y-grade service with an initial capacity of 90 MBbls/d. To achieve this, the pipeline will be taken out of service in early 2019 and is expected to come back online during the fourth quarter of 2019.


•	Supply. The White Cliffs pipeline is supplied by production from the DJ Basin. At the point of origin, there is a storage facility adjacent to a truck-unloading facility.


•	Delivery points. The White Cliffs pipeline delivery point is SemCrude’s storage facility in Cushing, Oklahoma, a major crude oil marketing center, which ultimately delivers to Gulf Coast and mid-continent refineries.

Saddlehorn pipeline


•	Customers. The Saddlehorn pipeline had multiple committed shippers, including Anadarko, as of December 31, 2018. In addition, other parties may ship on the Saddlehorn pipeline at FERC-based rates.


•	Supply. The Saddlehorn pipeline has multiple origin points including: Cheyenne, Wyoming; Ft. Laramie, Wyoming; Carr, Colorado; and Platteville, Colorado. Saddlehorn is supplied by the DJ Basin and basins that connect to a Wyoming access point.


•	Delivery points. The Saddlehorn pipeline delivers crude oil and condensate to storage facilities in Cushing, Oklahoma.

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Rocky Mountains - Utah

GNB NGL pipeline


•	Customers. Anadarko was the only shipper on the GNB NGL pipeline as of December 31, 2018.


•	Supply. The GNB NGL pipeline receives NGLs from Chipeta’s gas processing facility and Andeavor’s Stagecoach/Iron Horse gas processing complex.


•	Delivery points. The GNB NGL pipeline delivers NGLs to the MAPL pipeline, which provides transportation through the Seminole pipeline and TEP in West Texas, and ultimately to NGLs fractionation and storage facilities in Mont Belvieu, Texas.

Rocky Mountains - Wyoming

MIGC transportation system


•	Customers. Anadarko was the largest firm shipper on the MIGC system, with 85% of the throughput for the year ended December 31, 2018. The remaining throughput on the MIGC system was from numerous third-party shippers. MIGC is certificated for 175 MMcf/d of firm transportation capacity.


•	Supply. MIGC receives gas from various coal-bed methane gathering systems in the Powder River Basin and the Hilight system, as well as from WBI Energy Transmission, Inc. on the north end of the transportation system.


•	Delivery points. MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:


◦	CIG pipeline;


◦	TIGT pipeline; and


◦	WIC pipeline.

Volumes can also be delivered to Cheyenne Light Fuel & Power and several industrial users.

OTTCO transportation system

•

Customers. For the year ended December 31, 2018, 10% of OTTCO’s throughput was from Anadarko. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contracts that contain minimum volume commitments and volumetric fees paid by shippers under firm and interruptible gas transportation agreements.

•

Supply and delivery points. Supply points to the OTTCO transportation system include approximately 30 wellheads, the Granger complex and ExxonMobil Corporation’s Shute Creek plant, which are supplied by the eastern portion of the Greater Green River Basin, the Moxa Arch and the Jonah and Pinedale Anticline fields. Primary delivery points include the Red Desert complex, two third-party industrial facilities and an inactive interconnection with the Kern River pipeline.

Wamsutter pipeline


•	Customers. For the year ended December 31, 2018, 94% of the Wamsutter pipeline throughput was from two third-party shippers and the remaining throughput was from Anadarko. Revenues on the Wamsutter pipeline are generated from tariff-based rates regulated by the Wyoming Public Service Commission.


•	Supply and delivery points. The Wamsutter pipeline has three active receipt points in Sweetwater County, Wyoming and delivers crude oil into Andeavor’s Wamsutter Pipeline System.

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Texas

TEFR Interests

•

Front Range Pipeline. FRP provides takeaway capacity from the DJ Basin in Northeast Colorado. FRP has receipt points at gas plants in Weld and Adams Counties, Colorado (including the Lancaster and Wattenberg plants, which are within the DJ Basin complex) (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. As of December 31, 2018, FRP had multiple committed shippers, including Anadarko. FRP provides capacity to other shippers at the posted FERC tariff rate. In 2018, we elected to participate in the expansion of FRP, which will increase capacity by 100 MBbls/d, to a targeted total capacity of 258 MBbls/d, with the expansion expected to be completed in 2019.

•

Texas Express Gathering. TEG consists of two NGLs gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGLs takeaway capacity on TEP. TEG had one committed shipper as of December 31, 2018. In 2018, we participated in the expansion of the Texas/Oklahoma system of TEG, which has a total capacity of 100 MBbls/d and was completed in the second quarter of 2018.

•

Texas Express Pipeline. TEP delivers to NGLs fractionation and storage facilities in Mont Belvieu, Texas. TEP is supplied with NGLs from other pipelines including FRP, the MAPL pipeline and TEG. As of December 31, 2018, TEP had multiple committed shippers, including Anadarko. TEP provides capacity to other shippers at the posted FERC tariff rates. In 2018, we elected to participate in the expansion of TEP, which will increase capacity by 90 MBbls/d, to a targeted total capacity of 348 MBbls/d, with the expansion expected to be completed in 2019.

Whitethorn

Supply and delivery points. Whitethorn is supplied by production from the Permian Basin. Whitethorn transports crude oil and condensate from Enterprise’s Midland terminal to Enterprise’s Sealy terminal. From Sealy, shippers have access to Enterprise’s Rancho II pipeline, which extends to Enterprise’s ECHO terminal located in Houston, Texas. From ECHO, shippers have access to refineries in Houston, Texas City, Beaumont and Port Arthur, Texas, as well as Enterprise’s crude oil export facilities.

Panola pipeline

Supply and delivery points. The Panola pipeline transports mixed NGLs from Panola County, Texas to Mont Belvieu, Texas. As of December 31, 2018, the Panola pipeline had multiple committed shippers. The Panola pipeline provides capacity to other shippers at the posted FERC tariff rates.

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Assets Under Development

In addition to significant gathering expansion projects at the West Texas and DJ Basin complexes, the DBM oil system and the DBM water systems, we currently have the following significant projects scheduled for completion in 2019 in West Texas and Colorado. See Capital expenditures, under Part II, Item 7 of Exhibit 99.1 to this Current Report on Form 8-K.


•	Mentone Train II. We are currently constructing a second cryogenic processing train at the Mentone processing plant at the West Texas complex. Mentone Train II will have a capacity of 200 MMcf/d, and we expect this train to be completed in the first quarter of 2019. Upon completion of Mentone Train II, the West Texas complex will have a total processing capacity of 1,370 MMcf/d.

•

Latham processing plant. We are currently constructing two cryogenic processing trains at a new processing plant located in Weld County, Colorado. Latham Trains I and II will each have a capacity of 200 MMcf/d. Latham Train I is expected to be completed in mid-2019 and Latham Train II is expected to be completed around year-end 2019. The Latham processing plant will be part of the DJ Basin complex, and upon completion of Latham Trains I and II, the DJ Basin complex will have a total processing capacity of 1,410 MMcf/d.


•	Equity investments. We are currently contributing to the construction of the Cactus II pipeline, a crude oil pipeline connecting West Texas to the Corpus Christi area. The Cactus II pipeline will have a total capacity of 670 MBbls/d upon completion and is expected to become operational in late 2019.

COMPETITION

The midstream services business is extremely competitive. Our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. Competition varies in our different geographic areas of operation and is greatest in areas experiencing robust producer activity and during periods of high commodity prices. However, Anadarko supports our operations by providing dedications and/or minimum volume commitments with respect to a substantial portion of its throughput. We believe that our assets located outside of the dedicated areas are geographically well positioned to retain and attract third-party volumes due to our competitive rates. Major competitors in various aspects of our business include: Crestwood Equity Partners LP; DCP; EagleClaw Midstream Ventures, LLC; EnLink Midstream Partners, LP; Enterprise; ET; Kinder Morgan, Inc.; Plains All American Pipeline; and Targa Resources Partners LP.

We believe the primary advantages of our assets are their proximity to established and/or future production, and the service flexibility they provide to producers. We believe we can efficiently, and at competitive and flexible contract terms, provide services that customers require to connect, gather and process their natural gas, and gather and dispose of their produced water.

PART II

On February 28, 2019, in connection with the closing of the Merger (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), (i) Western Gas Partners, LP changed its name to Western Midstream Operating, LP and (ii) Western Gas Equity Partners, LP changed its name to Western Midstream Partners, LP. Item 6 of Exhibit 99.1 of this Current Report on Form 8-K, will refer to the reporting entities by their names as of the original filing date of the Form 10-K for the year ended December 31, 2018, filed with the SEC on February 20, 2019.

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Item 6. Selected Financial and Operating Data

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

The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by us, including AMA, as of December 31, 2018 (see Note 10—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K). Because Anadarko controls us through its control of WGP, which owns the entire interest in our general partner, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us. Further, after an acquisition of assets from Anadarko, we are required to recast our financial statements to include the activities of such Partnership assets from the date of common control.

For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of Partnership assets from Anadarko, including AMA, have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the Partnership assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership assets prior to our acquisitions from Anadarko as being “our” historical financial results.

Acquisitions. The following table presents the acquisitions completed by us, excluding the acquisition of AMA in February 2019 (see below), for the periods presented in the Summary Financial Information table below. Our consolidated financial statements include the combined financial results and operations for: (i) affiliate acquisitions for all periods presented and (ii) third-party acquisitions since the acquisition date.



	Acquisition Date	Percentage Acquired		Affiliate or Third-party Acquisition
TEFR Interests ⁽¹⁾	03/03/2014	Various ⁽¹⁾		Affiliate
DBM	11/25/2014	100	%	Third party
DBJV system	03/02/2015	50	%	Affiliate
Springfield system	03/14/2016	50.1	%	Affiliate
DBJV system ⁽²⁾	03/17/2017	50	%	Third party
Whitethorn LLC ⁽³⁾	06/01/2018	20	%	Third party
Cactus II ⁽³⁾	06/27/2018	15	%	Third party


⁽¹⁾	Acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP.


⁽²⁾	See Property exchange below.


⁽³⁾	See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for additional details.

Property exchange. In March 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration. We previously held a 50% interest in, and operated, the DBJV system.

Divestitures. In December 2018, the Newcastle system in Northeast Wyoming was sold to a third party. In June 2017, the Helper and Clawson systems, located in Utah, were sold to a third party. In October 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party. In July 2015, the Dew and Pinnacle systems in East Texas were sold to a third party.

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The information in the following table should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, which are included under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K, and with the information under the captions Items Affecting the Comparability of Our Financial Results, How We Evaluate Our Operations, Results of Operations, and Key Performance Metrics under Part II, Item 7 of Exhibit 99.1 to this Current Report on Form 8-K. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for a discussion of the impact the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) had on revenues and expenses.



thousands except per-unit data, throughput, Adjusted gross margin per Mcf and Adjusted gross margin per Bbl	Summary Financial Information
	2018 ⁽¹⁾			2017 ⁽¹⁾			2016 ⁽¹⁾			2015 ⁽¹⁾			2014 ⁽¹⁾
Statement of Operations Data (for the year ended):
Total revenues and other	$	2,299,658		$	2,429,614		$	1,941,330		$	1,853,233		$	1,642,571
Cost of product	415,505			953,792			517,371			551,287			495,926
Operating income (loss)	865,311			804,570			786,755			205,253			607,328
Net income (loss)	636,526			742,401			663,600			52,089			491,661
Net income attributable to noncontrolling interest	8,609			10,735			10,963			10,101			14,025
Net income (loss) attributable to Western Gas Partners, LP	627,917			731,666			652,637			41,988			477,636
Net income (loss) per common unit – basic	0.55			1.30			1.74			(1.95		)	2.13
Net income (loss) per common unit – diluted	0.55			1.30			1.74			(1.95		)	2.12
Distributions per unit	3.830			3.590			3.350			3.050			2.650
Balance Sheet Data (at year end):
Total assets	$	11,454,845		$	9,428,129		$	8,706,541		$	8,194,016		$	8,197,670
Total long-term liabilities	5,927,045			3,859,074			3,475,934			3,285,264			2,783,879
Total equity and partners’ capital	4,919,597			5,021,182			4,897,669			4,643,386			5,126,165
Cash Flow Data (for the year ended):
Net cash flows provided by (used in):
Operating activities	$	1,352,114		$	1,046,798		$	1,060,658		$	876,166		$	769,981
Investing activities	(2,210,813		)	(1,133,324		)	(1,229,874		)	(740,816		)	(2,956,523		)
Financing activities	870,333			(192,585		)	429,108			(104,371		)	2,152,831
Capital expenditures	(1,948,595		)	(1,026,932		)	(547,986		)	(786,945		)	(968,585		)
Throughput (MMcf/d except throughput measured in barrels):
Total throughput for natural gas assets	4,068			3,840			4,219			4,442			4,156
Throughput attributable to noncontrolling interest for natural gas assets	90			105			124			142			165
Total throughput attributable to Western Gas Partners, LP for natural gas assets	3,978			3,735			4,095			4,300			3,991
Throughput for crude oil, NGLs and produced water assets (MBbls/d)	775			406			371			295			224
Key Performance Metrics (for the year ended): ⁽²⁾
Adjusted gross margin for natural gas assets	$	1,472,827		$	1,281,796		$	1,250,250		$	1,191,981		$	1,049,056
Adjusted gross margin for crude oil, NGLs and produced water assets	545,750			269,091			232,326			162,363			126,900
Adjusted gross margin per Mcf for natural gas assets	1.01			0.94			0.83			0.76			0.72
Adjusted gross margin per Bbl for crude oil, NGLs and produced water assets	1.93			1.82			1.71			1.51			1.55
Adjusted EBITDA	1,500,179			1,196,201			1,140,343			983,693			847,687
Distributable cash flow	1,168,727			1,036,434			947,236			849,850			714,542


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to AMA. See Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

⁽²⁾

Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. For definitions and reconciliations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations under Part II, Item 7 of Exhibit 99.1 to this Current Report on Form 8-K.

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On February 28, 2019, in connection with the closing of the Merger (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), (i) Western Gas Partners, LP changed its name to Western Midstream Operating, LP and (ii) Western Gas Equity Partners, LP changed its name to Western Midstream Partners, LP. Item 7 of Exhibit 99.1 of this Current Report on Form 8-K, will refer to the reporting entities by their names as of the original filing date of the Form 10-K for the year ended December 31, 2018, filed with the SEC on February 20, 2019.

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, which are included under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K, and the information set forth in Risk Factors under Part I, Item 1A of our 2018 Form 10-K.

EXECUTIVE SUMMARY

We are a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream assets. We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. We are engaged in the business of gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, NGLs and crude oil; and gathering and disposing of produced water. In addition, in our capacity as a processor of natural gas, we also buy and sell natural gas, NGLs and condensate on behalf of ourselves and as agent for our customers under certain of our contracts. We provide these midstream services for Anadarko, as well as for third-party customers. As of December 31, 2018, our assets and investments consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems ⁽¹⁾	17	2	3	2
Treating facilities	34	3	—	3
Natural gas processing plants/trains	23	3	—	5
NGLs pipelines	2	—	—	4
Natural gas pipelines	5	—	—	—
Oil pipelines	3	1	—	3


⁽¹⁾	Includes the DBM water systems.

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In addition to the acquisition of AMA in February 2019 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), significant financial and operational events during the year ended December 31, 2018, included the following:

•

In August 2018, we completed an offering of $400.0 million aggregate principal amount of 4.750% Senior Notes due 2028 and $350.0 million aggregate principal amount of 5.500% Senior Notes due 2048. The net proceeds were used to repay the maturing 2.600% Senior Notes due August 2018, repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures. See Liquidity and Capital Resources within this Item 7 for additional information.


•	In June 2018, we acquired a 20% interest in Whitethorn and a 15% interest in Cactus II, both from third parties. See Acquisitions and Divestitures under Part I, Items 1 and 2 of Exhibit 99.1 to this Current Report on Form 8-K for additional information.

•

In March 2018, we completed an offering of $400.0 million aggregate principal amount of 4.500% Senior Notes due 2028 and $700.0 million aggregate principal amount of 5.300% Senior Notes due 2048. The net proceeds were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures. See Liquidity and Capital Resources within this Item 7 for additional information.

•

In February 2018, we entered into the five-year $1.5 billion (expandable to $2.0 billion) RCF by amending and restating the $1.2 billion credit facility originally entered into in February 2014. In December 2018, we amended the RCF to (i) subject to consummation of the Merger (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), increase the size of the RCF to $2.0 billion, and (ii) extend the maturity date of the RCF to February 2024. See Liquidity and Capital Resources within this Item 7 for additional information.


•	We commenced operation of two ROTFs at the DBM oil system (with total capacity of 120 MBbls/d) in the second and third quarter of 2018.


•	We commenced operation of Train VI at the DJ Basin oil system (with capacity of 30 MBbls/d) in the third quarter of 2018.


•	We commenced operation of Mentone Train I at the West Texas complex (with capacity of 200 MMcf/d) and an additional water system at the DBM water systems in the fourth quarter of 2018.


•	We raised our distribution to $0.980 per unit for the fourth quarter of 2018, representing a 2% increase over the distribution for the third quarter of 2018 and a 7% increase over the distribution for the fourth quarter of 2017, and resulting in a full-year 2018 distribution increase of 7% over full-year 2017.


•	Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,978 MMcf/d for the year ended December 31, 2018, representing a 7% increase compared to the year ended December 31, 2017.


•	Throughput for crude oil, NGLs and produced water assets totaled 775 MBbls/d for the year ended December 31, 2018, representing a 91% increase compared to the year ended December 31, 2017.


•	Operating income (loss) was $865.3 million for the year ended December 31, 2018, representing an 8% increase compared to the year ended December 31, 2017.


•	Adjusted gross margin for natural gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.01 per Mcf for the year ended December 31, 2018, representing a 7% increase compared to the year ended December 31, 2017.


•	Adjusted gross margin for crude oil, NGLs and produced water assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.93 per Bbl for the year ended December 31, 2018, representing a 6% increase compared to the year ended December 31, 2017.

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The following table provides additional information on throughput for the periods presented below:



	Year Ended December 31,
	2018	2017	Inc/ (Dec)		2018	2017	Inc/ (Dec)		2018	2017	Inc/ (Dec)
	Natural gas (MMcf/d)				Crude oil & NGLs (MBbls/d)				Produced water (MBbls/d)
Delaware Basin	1,041	811	28	%	132	76	74	%	239	28	NM
DJ Basin	1,133	975	16	%	105	102	3	%	—	—	—	%
Equity investments	291	290	—	%	241	148	63	%	—	—	—	%
Other	1,603	1,764	(9	)%	58	52	12	%	—	—	—	%
Total throughput	4,068	3,840	6	%	536	378	42	%	239	28	NM

NM-Not Meaningful

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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

Gathering and processing agreements. Certain of the gathering agreements for the West Texas complex and Springfield and DJ Basin oil systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Commodity price swap agreements. During all periods presented, our consolidated statements of operations and consolidated statements of equity and partners’ capital included the impacts of commodity price swap agreements. The commodity price swap agreements with Anadarko expired without renewal on December 31, 2018. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for further information.

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

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

Acquisitions and divestitures. For the year ended December 31, 2018, there was a net increase in Adjusted gross margin of $40.5 million related to our third party asset acquisitions and divestitures during 2018. For the year ended December 31, 2017, there was a net decrease in Adjusted gross margin of $44.9 million related to our third party asset acquisitions and divestitures during 2017. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for additional information.

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DBM complex. In December 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. During the year ended December 31, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to a change in the estimate of the amount that would be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, we reached a settlement with insurers and final proceeds were received. During the years ended December 31, 2017 and 2016, we received $52.9 million and $33.8 million, respectively, in cash proceeds from insurers, including $29.9 million and $16.3 million, respectively, in proceeds from business interruption insurance claims and $23.0 million and $17.5 million, respectively, in proceeds from property insurance claims. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Impairments. During 2017, we recognized impairments of $180.1 million, including an impairment of $158.8 million at the Granger complex due to a reduced throughput fee as a result of a producer’s bankruptcy. During 2018, we recognized impairments of $230.6 million, including impairments of (i) $125.9 million at the Third Creek gathering system (part of the DJ Basin complex) and $8.1 million at the Kitty Draw gathering system due to the shutdown of the systems, (ii) $38.7 million at the Hilight system and (iii) $34.6 million at the MIGC system. See Note 1—Summary of Significant Accounting Policies and Note 8—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Adoption of Topic 606. On January 1, 2018, we adopted Revenue from Contracts with Customers (Topic 606) (“Topic 606”). The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition (Topic 605). The following table summarizes the impact of adopting Topic 606 on the consolidated statement of operations:



	Year Ended December 31, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	1,905,728	$	1,751,242	$	154,486
Service revenues – product based	88,785		—		88,785
Product sales	303,020		1,405,898		(1,102,878		)
Expenses
Cost of product	415,505		1,338,100		(922,595		)
Operation and maintenance	480,861		480,668		193
Depreciation and amortization	389,164		386,179		2,985
Impairments	230,584		230,539		45
Income tax expense (benefit)	58,934		58,804		130

For more information on the adoption of Topic 606, see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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OUR OPERATIONS

Our results are driven primarily by the volumes of natural gas, NGLs, crude oil and produced water we service through our systems. In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil and produced water. We gather natural gas from individual wells or production facilities located near our gathering systems and the natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end users. We treat and process a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation. We gather crude oil from individual wells or production facilities located near our gathering systems, and in some cases, treat or stabilize the crude oil to satisfy required specifications for pipeline transportation. We also gather and dispose of produced water.

We currently have operations in Colorado, Utah, Wyoming, North-central Pennsylvania, Texas and New Mexico, with a substantial portion of our business concentrated in the Rocky Mountains and West Texas. For example, for the year ended December 31, 2018, our DJ Basin and West Texas assets provided (i) 31% and 28%, respectively, of our throughput for natural gas assets (excluding equity investment throughput), (ii) 20% and 69%, respectively, of our throughput for crude oil, NGLs and produced water assets (excluding equity investment throughput), and (iii) 39% and 32%, respectively, of our Adjusted gross margin.

For the year ended December 31, 2018, 59% of our total revenues and 43% of our throughput (on a per unit basis, assuming 1 Mcf equals 1 barrel, and excluding equity investment throughput) were attributable to transactions with Anadarko. We also recognized capital contributions from Anadarko of $51.6 million related to the above-market component of our commodity price swap agreements with Anadarko (see Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K). Anadarko supports our operations by providing dedications and/or minimum volume commitments with respect to a substantial portion of our throughput.

For the year ended December 31, 2018, 89% of our wellhead natural gas volumes (excluding equity investments) and 100% of our crude oil and produced water throughput (excluding equity investments) were attributable to fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil and produced water we gather, process, treat, transport or dispose. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements.

For the year ended December 31, 2018, 95% of our wellhead natural gas volumes (excluding equity investments) was attributable to either long-term, fee-based contracts, as discussed above, or percent-of-proceeds or keep-whole contracts that were hedged with commodity price swap agreements. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

We also have indirect exposure to commodity price risk in that the relatively volatile commodity price environment has 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 hydrocarbons available for our systems. We also bear a limited degree of commodity price risk through settlement of imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of Exhibit 99.1 to this Current Report on Form 8-K.

As a result of our acquisitions from Anadarko and third parties, our results of operations, financial position and cash flows may vary significantly in future periods. See Items Affecting the Comparability of Our Financial Results within this Item 7.

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HOW WE EVALUATE OUR OPERATIONS

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

Throughput. Throughput is an essential operating variable we use in assessing our ability to generate revenues. In order to maintain or increase throughput on our systems, we must connect to additional wells or production facilities. Our success in maintaining or increasing throughput is impacted by the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas, NGLs, crude oil or produced water volumes currently serviced by our competitors. During the year ended December 31, 2018, we added 540 receipt points to our systems.

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

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


•	expenses associated with annual and quarterly reporting;


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


•	expenses associated with listing on the NYSE; and


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

See further detail in Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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Non-GAAP financial measures

Adjusted gross margin attributable to Western Gas Partners, LP. We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. We believe Adjusted gross margin is an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds, percent-of-product and keep-whole contracts, (ii) costs associated with the valuation of our gas imbalances, and (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties.

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf for natural gas assets and Adjusted gross margin per Bbl for crude oil, NGLs and produced water assets. See Key Performance Metrics within this Item 7.

Adjusted EBITDA attributable to Western Gas Partners, LP. We define Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investments, 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, net, income from equity investments, interest income, income tax benefit, and other income. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:


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


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


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

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

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

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

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

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



	Year Ended December 31,
thousands	2018		2017		2016
Reconciliation of Operating income (loss) to Adjusted gross margin
Operating income (loss)	$	865,311	$	804,570	$	786,755
Add:
Distributions from equity investments	216,977		148,752		134,673
Operation and maintenance	480,861		345,617		332,405
General and administrative	63,166		51,077		48,701
Property and other taxes	51,848		53,147		45,638
Depreciation and amortization	389,164		318,771		295,959
Impairments	230,584		180,051		17,822
Less:
Gain (loss) on divestiture and other, net	1,312		132,388		(14,641		)
Proceeds from business interruption insurance claims	—		29,882		16,270
Equity income, net – affiliates	195,469		115,141		101,692
Reimbursed electricity-related charges recorded as revenues	66,678		56,860		59,733
Adjusted gross margin attributable to noncontrolling interest	15,875		16,827		16,323
Adjusted gross margin	$	2,018,577	$	1,550,887	$	1,482,576
Adjusted gross margin for natural gas assets	$	1,472,827	$	1,281,796	$	1,250,250
Adjusted gross margin for crude oil, NGLs and produced water assets	545,750		269,091		232,326

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	Year Ended December 31,
thousands	2018			2017			2016
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA
Net income (loss) attributable to Western Gas Partners, LP	$	627,917		$	731,666		$	652,637
Add:
Distributions from equity investments	216,977			148,752			134,673
Non-cash equity-based compensation expense	7,032			4,947			5,591
Interest expense	181,796			140,291			107,565
Income tax expense	58,934			20,483			32,969
Depreciation and amortization ⁽¹⁾	386,274			315,984			293,337
Impairments ⁽¹⁾	229,195			180,051			17,822
Other expense ⁽¹⁾	8,327			145			168
Less:
Gain (loss) on divestiture and other, net	1,312			132,388			(14,641		)
Equity income, net – affiliates	195,469			115,141			101,692
Interest income – affiliates	16,900			16,900			16,900
Other income ⁽¹⁾	2,592			1,283			468
Income tax benefit	—			80,406			—
Adjusted EBITDA	$	1,500,179		$	1,196,201		$	1,140,343
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities	$	1,352,114		$	1,046,798		$	1,060,658
Interest (income) expense, net	164,896			123,391			90,665
Uncontributed cash-based compensation awards	879			25			856
Accretion and amortization of long-term obligations, net	(5,142		)	(4,254		)	3,789
Current income tax (benefit) expense	(80,114		)	(6,785		)	(18,223		)
Other (income) expense, net⁽²⁾	(3,017		)	(1,299		)	(479		)
Distributions from equity investments in excess of cumulative earnings – affiliates	29,585			31,659			29,725
Changes in assets and liabilities:
Accounts receivable, net	60,460			16,177			48,441
Accounts and imbalance payables and accrued liabilities, net	(44,424		)	947			(60,696		)
Other items, net	37,802			3,048			(819		)
Adjusted EBITDA attributable to noncontrolling interest	(12,860		)	(13,506		)	(13,574		)
Adjusted EBITDA	$	1,500,179		$	1,196,201		$	1,140,343
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	1,352,114		$	1,046,798		$	1,060,658
Net cash used in investing activities	(2,210,813		)	(1,133,324		)	(1,229,874		)
Net cash provided by (used in) financing activities	870,333			(192,585		)	429,108


⁽¹⁾	Includes our 75% share of depreciation and amortization; impairments; other expense; and other income attributable to the Chipeta complex.


⁽²⁾	Excludes the non-cash loss on interest-rate swaps of $8.0 million for the year ended December 31, 2018. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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	Year Ended December 31,
thousands except Coverage ratio	2018			2017			2016
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Distributable cash flow and calculation of the Coverage ratio
Net income (loss) attributable to Western Gas Partners, LP	$	627,917		$	731,666		$	652,637
Add:
Distributions from equity investments	216,977			148,752			134,673
Non-cash equity-based compensation expense	7,032			4,947			5,591
Non-cash settled interest expense, net ⁽¹⁾	—			71			(7,747		)
Income tax (benefit) expense	58,934			(59,923		)	32,969
Depreciation and amortization ⁽²⁾	386,274			315,984			293,337
Impairments ⁽²⁾	229,195			180,051			17,822
Above-market component of swap agreements with Anadarko ⁽³⁾	51,618			58,551			45,820
Other expense ⁽²⁾	8,327			145			168
Less:
Recognized Service revenues – fee based (less than) in excess of customer billings ⁽⁴⁾	62,498			—			—
Gain (loss) on divestiture and other, net	1,312			132,388			(14,641		)
Equity income, net – affiliates	195,469			115,141			101,692
Cash paid for maintenance capital expenditures⁽²⁾	120,789			77,277			80,975
Capitalized interest	32,479			9,074			12,918
Cash paid for (reimbursement of) income taxes	2,408			1,194			838
Series A Preferred unit distributions	—			7,453			45,784
Other income ⁽²⁾	2,592			1,283			468
Distributable cash flow	$	1,168,727		$	1,036,434		$	947,236
Distributions declared ⁽⁵⁾
Limited partners – common units	$	584,487
General partner	327,363
Total	$	911,850
Coverage ratio	1.28		x


⁽¹⁾	Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.


⁽²⁾	Includes our 75% share of depreciation and amortization; impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex.


⁽³⁾	See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.


⁽⁴⁾	See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.


⁽⁵⁾	Reflects cash distributions of $3.830 per unit declared for the year ended December 31, 2018, including the cash distribution of $0.980 per unit paid on February 13, 2019, for the fourth-quarter 2018 distribution.

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GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from expected results.

Impact of crude oil, natural gas and NGLs prices. Crude oil, natural gas and NGLs prices can fluctuate significantly, and have done so over time. These fluctuations in commodity prices affect the overall level of our customers’ activity and how our customers allocate their capital within their own portfolio of assets. The relatively volatile commodity price environment over the past decade has impacted drilling activity in several of the basins served by our assets. Many of our customers, including Anadarko, have shifted capital spending towards opportunities with superior economics and reduced activity in other areas. To the extent possible, we will continue to connect new wells or production facilities to our systems to mitigate the impact of natural production declines in order to maintain throughput on our systems. However, our success in connecting additional wells or production facilities is dependent on the activity levels of our customers. Additionally, we will continue to evaluate the crude oil, NGLs and natural gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.

Liquidity and access to capital markets. Under the terms of our partnership agreement, we are required to distribute all of our available cash to our unitholders, which makes us dependent upon raising capital to fund growth projects and acquisitions. Historically, we have accessed the debt and equity capital markets to raise money for growth projects and acquisitions. From time to time, capital market turbulence and investor sentiment towards MLPs have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable. If we are unable either to access the capital markets or find alternative sources of capital at reasonable costs, our growth strategy will be more challenging to execute.

Changes in regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local and other laws and regulations that are becoming more numerous, more stringent and more complex. These laws and regulations include, among other things, limitations on hydraulic fracturing and other oil and gas operations, pipeline safety and integrity requirements, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and restrictions on produced water disposal wells. In addition, in certain areas in which we operate, public protests of oil and gas operations are becoming more frequent. The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect both the throughput on and profitability of our assets.

Impact of inflation. Although inflation in the United States has been relatively low in recent years, the U.S. economy could experience significant inflation, which could materially increase our operating costs and capital expenditures and negatively impact our financial results. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

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Impact of interest rates. Overall, both short- and longer-term interest rates increased during 2018, yet remained low relative to historical averages. Short-term interest rates experienced a sharp increase in response to the Federal Open Market Committee (“FOMC”) raising its target range for the federal funds rate four separate times during 2018. These increases, and any future increases, in the federal funds rate will ultimately result in an increase in our financing costs. Additionally, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and an associated implied distribution yield. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, reduce debt or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors would face similar circumstances.

Acquisition opportunities. A key component of our growth strategy is to acquire midstream assets over time. We may pursue certain asset acquisitions to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s or third-party production. However, if we do not make additional acquisitions on an economically accretive basis, our future growth could be limited, and the acquisitions we make could reduce, rather than increase, our cash flows generated from operations on a per-unit basis.

Upon the consummation of the Merger, we acquired substantially all of Anadarko’s midstream assets. See Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

EQUITY OFFERINGS

Series A Preferred units. In 2016, we issued 21,922,831 Series A Preferred units to private investors. Pursuant to an agreement between us and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units converted into common units on a one-for-one basis on May 2, 2017. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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RESULTS OF OPERATIONS

OPERATING RESULTS

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



	Year Ended December 31,
thousands	2018			2017			2016
Total revenues and other ⁽¹⁾	$	2,299,658		$	2,429,614		$	1,941,330
Equity income, net – affiliates	195,469			115,141			101,692
Total operating expenses ⁽¹⁾	1,631,128			1,902,455			1,257,896
Gain (loss) on divestiture and other, net	1,312			132,388			(14,641		)
Proceeds from business interruption insurance claims ⁽²⁾	—			29,882			16,270
Operating income (loss)	865,311			804,570			786,755
Interest income – affiliates	16,900			16,900			16,900
Interest expense	(181,796		)	(140,291		)	(107,565		)
Other income (expense), net	(4,955		)	1,299			479
Income (loss) before income taxes	695,460			682,478			696,569
Income tax (benefit) expense	58,934			(59,923		)	32,969
Net income (loss)	636,526			742,401			663,600
Net income attributable to noncontrolling interest	8,609			10,735			10,963
Net income (loss) attributable to Western Gas Partners, LP	$	627,917		$	731,666		$	652,637
Key performance metrics ⁽³⁾
Adjusted gross margin	$	2,018,577		$	1,550,887		$	1,482,576
Adjusted EBITDA	1,500,179			1,196,201			1,140,343
Distributable cash flow	1,168,727			1,036,434			947,236

⁽¹⁾

Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services, as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Items Affecting the Comparability of Our Financial Results within this Item 7 and Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.


⁽²⁾	See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

⁽³⁾

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

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2018” refer to the comparison of the year ended December 31, 2018, to the year ended December 31, 2017, and any increases or decreases “for the year ended December 31, 2017” refer to the comparison of the year ended December 31, 2017, to the year ended December 31, 2016.

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Throughput



	Year Ended December 31,
	2018	2017	Inc/ (Dec)		2016	Inc/ (Dec)
Throughput for natural gas assets (MMcf/d)
Gathering, treating and transportation ⁽¹⁾	546	958	(43	)%	1,537	(38	)%
Processing ⁽¹⁾	3,231	2,592	25	%	2,385	9	%
Equity investment ⁽²⁾	291	290	—	%	297	(2	)%
Total throughput for natural gas assets	4,068	3,840	6	%	4,219	(9	)%
Throughput attributable to noncontrolling interest for natural gas assets	90	105	(14	)%	124	(15	)%
Total throughput attributable to Western Gas Partners, LP for natural gas assets	3,978	3,735	7	%	4,095	(9	)%
Throughput for crude oil, NGLs and produced water assets (MBbls/d)
Gathering, treating, transportation and disposal	534	258	107	%	232	11	%
Equity investment ⁽³⁾	241	148	63	%	139	6	%
Total throughput for crude oil, NGLs and produced water assets	775	406	91	%	371	9	%


⁽¹⁾	The combination of the DBM complex and DBJV and Haley systems, effective January 1, 2018, into a single complex now referred to as the “West Texas complex” resulted in DBJV and Haley systems throughput previously reported as “Gathering, treating and transportation” now being reported as “Processing.”


⁽²⁾	Represents our 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput and 50% share of average Mi Vida throughput. Represents our 50% share of average Ranch Westex throughput for the years ended December 31, 2018 and 2017, and 33% share of average Ranch Westex throughput for the year ended December 31, 2016.


⁽³⁾	Represents our 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEG, TEP, Whitethorn and Saddlehorn throughput, 33.33% share of average FRP throughput and 15% share of average Panola throughput.

Natural gas assets

Gathering, treating and transportation throughput decreased by 412 MMcf/d for the year ended December 31, 2018, primarily due to (i) the combination of the DBM complex and DBJV and Haley systems into a single complex now referred to as the “West Texas complex”, which resulted in DBJV and Haley systems throughput previously reported as “Gathering, treating and transportation” now being reported as “Processing” (decrease of 258 MMcf/d) and (ii) the divestiture of the Non-Operated Marcellus Interest as part of the Property Exchange in March 2017 (decrease of 158 MMcf/d).

Gathering, treating and transportation throughput decreased by 579 MMcf/d for the year ended December 31, 2017, primarily due to the Property Exchange in March 2017 (decrease of 399 MMcf/d), production declines in the areas around the Marcellus Interest (decrease of 44 MMcf/d) and Springfield gas gathering systems (decrease of 44 MMcf/d), and the sale of the Hugoton system in October 2016 (decrease of 44 MMcf/d).

Processing throughput increased by 639 MMcf/d for the year ended December 31, 2018, primarily due to (i) the combination of the DBM complex and DBJV and Haley systems into the West Texas complex, (ii) increased production in the areas around the DJ Basin and West Texas complexes, (iii) the start-up of Train VI at the West Texas complex in December 2017, (iv) increased throughput at the West Texas complex due to the acquisition of the Additional DBJV System Interest as part of the Property Exchange in March 2017 and (v) increased throughput at the MGR assets due to downtime in 2017. These increases were partially offset by lower throughput at the Chipeta complex due to downstream fractionation capacity constraints in the third quarter of 2018 and the expiration and non-renewal of a contract in September 2017.

Processing throughput increased by 207 MMcf/d for the year ended December 31, 2017, primarily due to the incident at the DBM complex in 2015, the start-up of Train IV and Train V at the DBM complex in May 2016 and October 2016, respectively, and increased production in the areas around the DJ Basin complex. These increases were partially offset by production declines in the areas around the Chipeta complex and MGR assets.

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Equity investment throughput decreased by 7 MMcf/d for the year ended December 31, 2017, primarily due to decreased throughput at the Rendezvous and Fort Union systems due to production declines in the area. These decreases were partially offset by (i) increased throughput at the Mi Vida and Ranch Westex plants due to increased production in the Delaware Basin area and (ii) the acquisition of the additional interest in Ranch Westex in March 2017.

Crude oil, NGLs and produced water assets

Gathering, treating, transportation and disposal throughput increased by 276 MBbls/d for the year ended December 31, 2018, primarily due to (i) increased throughput from the DBM water systems, which commenced operation beginning in the second quarter of 2017 and (ii) increased throughput at the DBM oil system due to the ROTFs that commenced operation beginning in the second quarter of 2018.

Gathering, treating, transportation and disposal throughput increased by 26 MBbls/d for the year ended December 31, 2017, primarily due to (i) throughput from the DBM water systems, which commenced operation beginning in the second quarter of 2017 and (ii) increased production in the areas around the DBM oil system. These increases were partially offset by decreased throughput at the Springfield oil gathering system due to production declines in the area.

Equity investment throughput increased by 93 MBbls/d for the year ended December 31, 2018, primarily due to (i) the acquisition of the interest in Whitethorn in June 2018 and (ii) increased volumes on TEP and FRP as a result of increased NGLs production in the DJ Basin area.

Equity investment throughput increased by 9 MBbls/d for the year ended December 31, 2017, primarily due to (i) increased volumes on FRP and TEG as a result of increased NGLs production, (ii) an increase at the Mont Belvieu JV due to higher inlet throughput and (iii) the start-up of the Saddlehorn pipeline in October 2016. These increases were partially offset by decreased throughput at White Cliffs as a result of a competitive pipeline commencing service in September 2016.

Service Revenues



	Year Ended December 31,
thousands except percentages	2018		2017		Inc/ (Dec)		2016		Inc/ (Dec)
Service revenues – fee based	$	1,905,728	$	1,357,876	40	%	$	1,337,930	1	%
Service revenues – product based	88,785		—		NM		—		NM
Total service revenues	$	1,994,513	$	1,357,876	47	%	$	1,337,930	1	%

NM-Not Meaningful

Service revenues – fee based increased by $547.9 million for the year ended December 31, 2018, primarily due to increases of (i) $154.5 million from the adoption of Topic 606 as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, (ii) $141.3 million, $71.5 million and $19.1 million at the West Texas complex and DBM and DJ Basin oil systems, respectively, due to increased throughput, (iii) $112.7 million at the DJ Basin complex due to increased throughput ($91.3 million) and a higher processing fee ($21.4 million), and (iv) $78.4 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017. These increases were partially offset by decreases of (i) $22.1 million due to the divestiture of the Non-Operated Marcellus Interest as part of the Property Exchange in March 2017 and (ii) $10.4 million at the Springfield system due to a lower cost of service rate.

Service revenues – fee based increased by $19.9 million for the year ended December 31, 2017, primarily due to increases of (i) $88.7 million at the DBM complex due to increased throughput (see Operating Results–Throughput within this Item 7), (ii) $32.3 million at the DJ Basin complex due to a higher processing fee ($24.2 million) and increased throughput ($8.1 million), (iii) $20.3 million at the DBM oil system due to higher gathering fees and (iv) $9.5 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017. These increases were partially offset by decreases of (i) $42.9 million due to the Property Exchange in March 2017, (ii) $31.7 million at the Springfield system and $14.0 million at the Chipeta complex due to throughput decreases, (iii) $16.0 million due to the sale of the Hugoton system in October 2016, (iv) $9.7 million at the Granger complex due to a lower processing fee and (v) $9.0 million at the Marcellus Interest systems due to decreased throughput.

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Service revenues – product based increased by $88.8 million for the year ended December 31, 2018, due to the adoption of Topic 606 as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7. Under Topic 606, certain of our customer agreements result in revenues being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. In addition, retained proceeds from sales of customer products where we are acting as their agent are included in Service revenues – product based.

Product Sales



	Year Ended December 31,
thousands except percentages and per-unit amounts	2018		2017		Inc/ (Dec)		2016		Inc/ (Dec)
Natural gas sales ⁽¹⁾	$	85,015	$	391,393	(78	)%	$	231,410	69	%
NGLs sales ⁽¹⁾	218,005		659,817		(67	)%	367,839		79	%
Total Product sales	$	303,020	$	1,051,210	(71	)%	$	599,249	75	%
Gross average sales price per unit ⁽¹⁾:
Natural gas (per Mcf)	$	2.16	$	2.92	(26	)%	$	2.51	16	%
NGLs (per Bbl)	31.55		23.88		32	%	19.70		21	%

⁽¹⁾

Includes the effects of commodity price swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016), excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 8-K.

Natural gas sales decreased by $306.4 million for the year ended December 31, 2018, primarily due to decreases of (i) $258.9 million from the adoption of Topic 606 as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, (ii) $24.6 million at the West Texas complex due to a decrease in average price, partially offset by an increase in volumes sold, (iii) $5.7 million due to a decrease in average price and $9.3 million due to the shutdown of the Kitty Draw gathering system, both at the Hilight system (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K).

Natural gas sales increased by $160.0 million for the year ended December 31, 2017, primarily due to increases of (i) $93.4 million at the DBM complex due to an increase in average price and volumes sold (see Operating Results–Throughput within this Item 7) and (ii) $72.3 million at the DJ Basin complex due to an increase in the swap market price and volumes sold. These increases were partially offset by a decrease of $12.3 million at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.

NGLs sales decreased by $441.8 million for the year ended December 31, 2018, primarily due to a decrease of $844.0 million from the adoption of Topic 606 as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7. This decrease was partially offset by increases of (i) $256.8 million at the West Texas complex due to an increase in volumes sold, partially offset by a decrease in average price, (ii) $48.2 million at the DJ Basin complex due to an increase in the swap market price and volumes sold, (iii) $39.0 million at the DJ Basin oil system due to an increase in average price and volumes sold, (iv) $23.8 million at the Brasada complex due to volumes sold under a new sales agreement beginning January 1, 2018, and (v) $12.8 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017.

NGLs sales increased by $292.0 million for the year ended December 31, 2017, primarily due to increases of (i) $255.3 million at the DBM complex due to an increase in average price and volumes sold (see Operating Results–Throughput within this Item 7), (ii) $53.6 million at the DJ Basin complex due to an increase in the swap market price and volumes sold, (iii) $18.0 million at the DJ Basin oil system due to a new third-party sales agreement beginning in April 2017, and (iv) $15.3 million at the Hilight system due to an increase in average price. These increases were partially offset by a decrease of $64.5 million at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.

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Other Revenues



	Year Ended December 31,
thousands except percentages	2018		2017		Inc/ (Dec)		2016		Inc/ (Dec)
Other revenues	$	2,125	$	20,528	(90	)%	$	4,151	NM

For the year ended December 31, 2018, Other revenues decreased by $18.4 million, primarily due to deficiency fees of $8.8 million at the Chipeta complex and $7.2 million at the DBM water systems in 2017. Upon adoption of Topic 606 on January 1, 2018, deficiency fees are recorded as Service revenues – fee based in the consolidated statements of operations (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K).

For the year ended December 31, 2017, Other revenues increased by $16.4 million, primarily due to deficiency fees of $8.8 million at the Chipeta complex and $7.2 million at the DBM water systems in 2017.

Equity Income, Net – Affiliates



	Year Ended December 31,
thousands except percentages	2018		2017		Inc/ (Dec)		2016		Inc/ (Dec)
Equity income, net – affiliates	$	195,469	$	115,141	70	%	$	101,692	13	%

For the year ended December 31, 2018, Equity income, net – affiliates increased by $80.3 million, primarily due to (i) the acquisition of the interest in Whitethorn in June 2018 and (ii) increased volumes at the TEFR Interests, the Saddlehorn pipeline, Mi Vida and Ranch Westex. These increases were partially offset by a decrease in volumes at the Fort Union system.

For the year ended December 31, 2017, Equity income, net – affiliates increased by $13.4 million, primarily due to (i) the start-up of the Saddlehorn pipeline in October 2016, (ii) an increase in equity income from the Mont Belvieu JV due to product price increases and (iii) due to our 14.81% share of an impairment loss determined by the managing partner of Fort Union in 2016.

Cost of Product and Operation and Maintenance Expenses



	Year Ended December 31,
thousands except percentages	2018			2017		Inc/ (Dec)		2016		Inc/ (Dec)
NGLs purchases ⁽¹⁾	$	313,540		$	573,309	(45	)%	$	260,405	120	%
Residue purchases ⁽¹⁾	104,264			367,179		(72	)%	232,944		58	%
Other	(2,299		)	13,304		(117	)%	24,022		(45	)%
Cost of product	415,505			953,792		(56	)%	517,371		84	%
Operation and maintenance	480,861			345,617		39	%	332,405		4	%
Total Cost of product and Operation and maintenance expenses	$	896,366		$	1,299,409	(31	)%	$	849,776	53	%

⁽¹⁾

For the years ended December 31, 2017 and 2016, includes the effects of commodity price swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016), excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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NGL purchases decreased by $259.8 million for the year ended December 31, 2018, primarily due to a decrease of $669.4 million from the adoption of Topic 606 as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, partially offset by increases of (i) $269.5 million at the West Texas complex due to an increase in volumes purchased, (ii) $50.4 million and $40.4 million at the DJ Basin complex and DJ Basin oil system, respectively, due to an increase in average prices and volumes purchased, (iii) $22.0 million at the Brasada complex due to volumes purchased under a new purchase agreement beginning January 1, 2018, and (iv) $11.8 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017.

NGL purchases increased by $312.9 million for the year ended December 31, 2017, primarily due to increases of (i) $247.3 million at the DBM complex due to an increase in average price and volumes purchased (see Operating Results–Throughput within this Item 7), (ii) $58.2 million at the DJ Basin complex due to an increase in the swap market price and volumes purchased, (iii) $18.5 million at the DJ Basin oil system due to a new third-party purchase agreement beginning in April 2017, and (iv) $13.1 million at the Hilight system due to an increase in average price. These increases were partially offset by a decrease of $34.3 million at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.

Residue purchases decreased by $262.9 million for the year ended December 31, 2018, primarily due to decreases of (i) $243.4 million from the adoption of Topic 606 as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, (ii) $12.9 million at the West Texas complex due to a decrease in average price, partially offset by an increase in volumes purchased, (iii) $6.8 million at the MGR assets due to a decrease in average price and volumes purchased, and (iv) $5.0 million at the Hilight system due to a decrease in volumes purchased. These decreases were partially offset by an increase of $5.7 million at the DJ Basin complex due to an increase in volumes purchased, partially offset by a decrease in average price.

Residue purchases increased by $134.2 million for the year ended December 31, 2017, primarily due to increases of (i) $81.5 million at the DBM complex due to an increase in average price and volumes purchased (see Operating Results–Throughput within this Item 7), (ii) $61.6 million at the DJ Basin complex due to an increase in the swap market price and volumes purchased and (iii) $4.8 million at the Hilight system due to an increase in average price. These increases were partially offset by a decrease of $15.8 million at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.

Other items decreased by $15.6 million for the year ended December 31, 2018, primarily due to decreases of (i) $9.8 million from the adoption of Topic 606 as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7 and (ii) $6.6 million from changes in imbalance positions primarily at the West Texas complex.

Other items decreased by $10.7 million for the year ended December 31, 2017, primarily due a decrease at the DBM complex due to (i) fees paid in 2016 for rerouting volumes due to the incident at the DBM complex in 2015 and (ii) changes in imbalance positions.

Operation and maintenance expense increased by $135.2 million for the year ended December 31, 2018, primarily due to increases of (i) $62.2 million at the West Texas complex due to increases in salaries and wages, surface maintenance and plant repairs, utilities expense, and equipment rentals, (ii) $29.2 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017, (iii) $25.4 million at the DJ Basin complex due to increases in utilities expense, surface maintenance and plant repairs, and salaries and wages, and (iv) $14.8 million at the DBM oil system due to increases in surface maintenance and plant repairs, salaries and wages, and chemicals and treating services.

Operation and maintenance expense increased by $13.2 million for the year ended December 31, 2017, primarily due to increases of (i) $8.6 million at the DJ Basin complex primarily due to an increase in surface maintenance and plant repairs, (ii) $5.5 million at the DBM complex primarily due to increases in utilities expense and salaries and wages, partially offset by a decrease in surface maintenance and plant repairs, (iii) $4.5 million due to the Property Exchange in March 2017, and (iv) $2.7 million at the DJ Basin oil system due to increases in chemicals and treating services and surface maintenance and plant repairs. These increases were partially offset by decreases of (i) $7.5 million due to the sale of the Hugoton system in October 2016 and (ii) $4.4 million at the Chipeta complex primarily due to a decrease in utilities expense.

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Other Operating Expenses



	Year Ended December 31,
thousands except percentages	2018		2017		Inc/ (Dec)		2016		Inc/ (Dec)
General and administrative	$	63,166	$	51,077	24	%	$	48,701	5	%
Property and other taxes	51,848		53,147		(2	)%	45,638		16	%
Depreciation and amortization	389,164		318,771		22	%	295,959		8	%
Impairments	230,584		180,051		28	%	17,822		NM
Total other operating expenses	$	734,762	$	603,046	22	%	$	408,120	48	%

General and administrative expenses increased by $12.1 million for the year ended December 31, 2018, primarily due to (i) legal and consulting fees incurred in 2018 and (ii) personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement. These increases were partially offset by a decrease in bad debt expense.

General and administrative expenses increased by $2.4 million for the year ended December 31, 2017, primarily due to (i) increases in personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement and (ii) bad debt expense. These increases were partially offset by decreases in legal and consulting fees.

Property and other taxes decreased by $1.3 million for the year ended December 31, 2018, primarily due to ad valorem tax decreases of $5.8 million at the DJ Basin complex caused by revisions in estimated tax liabilities, offset by increases of $2.5 million and $2.1 million at the West Texas complex and the DJ Basin oil system, respectively.

Property and other taxes increased by $7.5 million for the year ended December 31, 2017, primarily due to ad valorem tax increases of $4.3 million at the DJ Basin complex, $1.8 million at the DBJV system and $1.7 million at the DBM complex.

Depreciation and amortization expense increased by $70.4 million for the year ended December 31, 2018, primarily due to increases of $30.4 million, $12.9 million and $10.8 million at the West Texas complex, DBM water systems and DBM oil system, respectively, due to capital projects being placed into service and $17.1 million at the DJ Basin complex related to the shutdown of the Third Creek gathering system (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K).

Depreciation and amortization expense increased by $22.8 million for the year ended December 31, 2017, primarily due to depreciation expense increases of (i) $15.7 million due to the Property Exchange in March 2017, (ii) $11.3 million at the Bison facility due to a change in the estimated property life, (iii) $10.6 million related to capital projects at the DBM complex and (iv) $3.7 million and $2.2 million related to capital projects at the DJ Basin oil system and the DBM water systems, respectively. These increases were partially offset by decreases of (i) $7.3 million at the Granger complex due to an impairment recorded in the first quarter of 2017 (see impairment expense below), (ii) $5.5 million due to the sale of the Hugoton system in October 2016, (iii) $4.4 million at the MGR assets due to a change in the estimated property life and (iv) $3.5 million at the DJ Basin complex due to a change in estimated salvage values.

Impairment expense for the year ended December 31, 2018, was primarily due to impairments of (i) $125.9 million at the Third Creek gathering system and $8.1 million at the Kitty Draw gathering system (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), (ii) $38.7 million at the Hilight system, (iii) $34.6 million at the MIGC system, (iv) $10.9 million at the GNB NGL pipeline and (v) $5.6 million at the Chipeta complex.

Impairment expense for the year ended December 31, 2017, included (i) a $158.8 million impairment at the Granger complex, (ii) an $8.2 million impairment at the Hilight system, (iii) a $3.7 million impairment at the Granger straddle plant, (iv) a $3.1 million impairment at the Fort Union system, (v) a $2.0 million impairment of an idle facility in northeast Wyoming and (vi) an impairment related to the cancellation of a pipeline project in West Texas.

Impairment expense for the year ended December 31, 2016, included (i) a $6.1 million impairment at the Newcastle system and (ii) $11.7 million of impairments primarily related to the cancellation of projects at the DJ Basin complex and at the Springfield, DBJV and DBM oil systems and the abandonment of compressors at the MIGC system.

For further information on impairment expense for the periods presented, see Note 8—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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Interest Income – Affiliates and Interest Expense



	Year Ended December 31,
thousands except percentages	2018			2017			Inc/ (Dec)		2016			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	$	(199,322	)	$	(142,525	)	40	%	$	(121,832	)	17	%
Amortization of debt issuance costs and commitment fees	(8,207		)	(6,616		)	24	%	(6,398		)	3	%
Capitalized interest	32,479			9,074			NM		12,918			(30	)%
Affiliates
Deferred purchase price obligation – Anadarko ⁽¹⁾	—			(71		)	(100	)%	7,747			(101	)%
APCWH Note Payable	(6,746		)	(153		)	NM		—			NM
Interest expense	$	(181,796	)	$	(140,291	)	30	%	$	(107,565	)	30	%


⁽¹⁾	See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for a discussion of the Deferred purchase price obligation - Anadarko.

Interest expense increased by $41.5 million for the year ended December 31, 2018, primarily due to (i) $46.3 million of interest incurred on the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 that were issued in March 2018, (ii) $15.3 million of interest incurred on the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 that were issued in August 2018 and (iii) $6.6 million of interest incurred on the APCWH Note Payable. These increases were partially offset by an increase in capitalized interest of $23.4 million, primarily due to continued construction and expansion at (i) the DJ Basin complex, including construction of the Latham processing plant beginning in 2018, (ii) the West Texas complex, including construction of the Mentone processing plant beginning in the fourth quarter of 2017 and (iii) the DBM oil system, including construction of the ROTFs which commenced operation in 2018.

Interest expense increased by $32.7 million for the year ended December 31, 2017, primarily due to (i) accretion revisions in 2016 recorded as reductions to interest expense for the Deferred purchase price obligation - Anadarko (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), (ii) $12.3 million of interest incurred on the 4.650% Senior Notes due 2026 issued in July 2016 and (iii) $8.7 million of interest incurred on the additional 5.450% Senior Notes due 2044 issued in October 2016. Capitalized interest decreased by $3.8 million for the year ended December 31, 2017, primarily due to (i) the completion of Trains IV and V in May 2016 and October 2016, respectively, at the DBM complex and (ii) the completion of COSF Trains I through V in June 2016 at the DJ Basin oil system, partially offset by the construction of Train VI beginning in the fourth quarter of 2016 and the purchase of long-lead items associated with the Mentone plant at the DBM complex.

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Other Income (Expense), Net



	Year Ended December 31,
thousands except percentages	2018			2017		Inc/ (Dec)	2016		Inc/ (Dec)
Other income (expense), net	$	(4,955	)	$	1,299	NM	$	479	171	%

Other income (expense), net decreased by $6.3 million for the year ended December 31, 2018, primarily due to a non-cash loss of $8.0 million on interest-rate swaps entered into in December 2018. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for additional information.

Income Tax (Benefit) Expense



	Year Ended December 31,
thousands except percentages	2018			2017			Inc/ (Dec)		2016			Inc/ (Dec)
Income (loss) before income taxes	$	695,460		$	682,478		2	%	$	696,569		(2	)%
Income tax (benefit) expense	58,934			(59,923		)	(198	)%	32,969			NM
Effective tax rate	8		%	NM					5		%

We are not a taxable entity for U.S. federal income tax purposes. However, our income apportionable to Texas is subject to Texas margin tax. For the years ended December 31, 2018 and 2016, the variance from the federal statutory rate was primarily due to federal and state taxes on pre-acquisition income attributable to Partnership assets acquired from Anadarko, and our share of Texas margin tax.

During the year ended December 31, 2017, AMA recognized a one-time deferred tax benefit of $87.3 million due to the impact of the U.S. Tax Cuts and Jobs Act signed into law on December 22, 2017. This was offset by federal and state taxes on pre-acquisition income attributable to the AMA assets acquired from Anadarko and our share of Texas margin tax.

Income attributable to (i) the AMA assets prior to and including February 2019 and (ii) the Springfield system prior to and including February 2016, was subject to federal and state income tax. Income earned on the AMA assets and Springfield system for periods subsequent to February 2019 and February 2016, respectively, was only subject to Texas margin tax on income apportionable to Texas.

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KEY PERFORMANCE METRICS



	Year Ended December 31,
thousands except percentages and per-unit amounts	2018		2017		Inc/ (Dec)		2016		Inc/ (Dec)
Adjusted gross margin for natural gas assets ⁽¹⁾	$	1,472,827	$	1,281,796	15	%	$	1,250,250	3	%
Adjusted gross margin for crude oil, NGLs and produced water assets ⁽²⁾	545,750		269,091		103	%	232,326		16	%
Adjusted gross margin ⁽³⁾	2,018,577		1,550,887		30	%	1,482,576		5	%
Adjusted gross margin per Mcf for natural gas assets ⁽⁴⁾	1.01		0.94		7	%	0.83		13	%
Adjusted gross margin per Bbl for crude oil, NGLs and produced water assets ⁽⁵⁾	1.93		1.82		6	%	1.71		6	%
Adjusted EBITDA ⁽³⁾	1,500,179		1,196,201		25	%	1,140,343		5	%
Distributable cash flow ⁽³⁾	1,168,727		1,036,434		13	%	947,236		9	%

⁽¹⁾

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

⁽²⁾

Adjusted gross margin for crude oil, NGLs and produced water assets is calculated as total revenues and other for crude oil, NGLs and produced water assets (less reimbursements for electricity-related expenses recorded as revenue), less cost of product for crude oil, NGLs and produced water assets, and plus distributions from our equity investments. See the reconciliation of Adjusted gross margin for crude oil, NGLs and produced water assets to its most comparable GAAP measure under How We Evaluate Our Operations—Reconciliation of non-GAAP measures within this Item 7.


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


⁽⁴⁾	Average for period. Calculated as Adjusted gross margin 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 oil, NGLs and produced water assets, divided by total throughput (MBbls/d) for crude oil, NGLs and produced water assets.

Adjusted gross margin. Adjusted gross margin increased by $467.7 million for the year ended December 31, 2018, primarily due to (i) increased throughput at the West Texas complex and DBM oil system, (ii) a cost of service rate adjustment in the fourth quarter of 2018 and increased throughput at the DJ Basin oil system, (iii) increased throughput and a higher processing fee at the DJ Basin complex, (iv) the start-up of the DBM water systems beginning in the second quarter of 2017, (v) the acquisition of the interest in Whitethorn in June 2018, (vi) the Property Exchange in March 2017, and (vii) a cost of service rate adjustment at the Springfield system in the fourth quarter of 2018 (see Revenue from contracts with customers (Topic 606) under Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K). These increases were partially offset by a decrease due to the shutdown of the Kitty Draw gathering system (part of the Hilight system) in 2018 (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K).

Adjusted gross margin increased by $68.3 million for the year ended December 31, 2017, primarily due to (i) an increase in throughput at the DBM complex and DBM oil system, (ii) an increase in processed volumes at the DJ Basin complex, and (iii) the start-up of the DBM water systems beginning in the second quarter of 2017. These increases were partially offset by decreases from (i) the Property Exchange in March 2017, (ii) lower throughput at the Springfield and Marcellus Interest systems, (iii) the partial equity treatment of the above-market swap agreement at the MGR assets beginning January 1, 2017, and (iv) the sale of the Hugoton system in October 2016.

Adjusted gross margin per Mcf for natural gas assets increased by $0.07 for the year ended December 31, 2018, primarily due to (i) increased throughput at the West Texas complex, which has a higher-than-average margin as compared to our other natural gas assets, (ii) the Property Exchange in March 2017, and (iii) a cost of service rate adjustment at the Springfield gas gathering system in the fourth quarter of 2018.

Adjusted gross margin per Mcf for natural gas assets increased by $0.11 for the year ended December 31, 2017, primarily due to (i) the Property Exchange in March 2017 and (ii) increased throughput at the DBM and DJ Basin complexes.

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Adjusted gross margin per Bbl for crude oil, NGLs and produced water assets increased by $0.11 for the year ended December 31, 2018, primarily due to (i) a cost of service rate adjustment in the fourth quarter of 2018 and increased throughput at the DJ Basin oil system, (ii) increased throughput at the DBM oil system, (iii) the acquisition of the interest in Whitethorn in June 2018, (iv) higher distributions received from the TEFR Interests and the Mont Belvieu JV and (v) a cost of service rate adjustment at the Springfield oil gathering system in the fourth quarter of 2018. These increases were partially offset by increased throughput at the DBM water systems, which have lower margins per Bbl than our other crude oil and NGLs assets.

Adjusted gross margin per Bbl for crude oil, NGLs and produced water assets increased by $0.11 for the year ended December 31, 2017, primarily due to (i) increased throughput at the DBM oil system, (ii) the start-up of the Saddlehorn pipeline in October 2016, and (iii) higher distributions received from TEP. These increases were partially offset by (i) lower throughput at the Springfield oil gathering system and (ii) the start-up of the DBM water systems beginning in the second quarter of 2017.

Adjusted EBITDA. Adjusted EBITDA increased by $304.0 million for the year ended December 31, 2018, primarily due to (i) a $538.9 million decrease in cost of product (net of lower of cost or market inventory adjustments) and (ii) a $68.2 million increase in distributions from equity investments. These amounts were partially offset by (i) a $135.2 million increase in operation and maintenance expenses, (ii) a $130.0 million decrease in total revenues and other, (iii) a $29.9 million decrease in business interruption proceeds, and (iv) a $10.0 million increase in general and administrative expenses excluding non-cash equity-based compensation expense.

Adjusted EBITDA increased by $55.9 million for the year ended December 31, 2017, primarily due to (i) a $488.3 million increase in total revenues and other, (ii) a $14.1 million increase in distributions from equity investments, and (iii) a $13.6 million increase in business interruption proceeds. These amounts were partially offset by (i) a $436.4 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a $13.2 million increase in operation and maintenance expenses, (iii) a $7.5 million increase in property and other tax expense, and (iv) a $3.0 million increase in general and administrative expenses excluding non-cash equity-based compensation expense.

Distributable cash flow. Distributable cash flow increased by $132.3 million for the year ended December 31, 2018, primarily due to (i) a $304.0 million increase in Adjusted EBITDA and (ii) a $7.5 million decrease in Series A Preferred unit distributions. These amounts were partially offset by (i) a $65.0 million increase in net cash paid for interest expense, (ii) $62.5 million of customer billings less than the amount recognized as Service revenues – fee based, (iii) a $43.5 million increase in cash paid for maintenance capital expenditures, and (iv) a $6.9 million decrease in the above-market component of the swap agreements with Anadarko.

Distributable cash flow increased by $89.2 million for the year ended December 31, 2017, primarily due to (i) a $55.9 million increase in Adjusted EBITDA, (ii) a $38.3 million decrease in Series A Preferred unit distributions, (iii) a $12.7 million increase in the above-market component of the swap agreements with Anadarko, and (iv) a $3.7 million decrease in cash paid for maintenance capital expenditures. These amounts were partially offset by a $21.1 million increase in net cash paid for interest expense.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owner. Our sources of liquidity as of December 31, 2018, included cash and cash equivalents, cash flows generated from operations, interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under the RCF, and issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements and other factors and will be determined by the Board of Directors on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under the RCF to pay distributions or fund other short-term working capital requirements.

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Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. The Board of Directors declared a cash distribution to our unitholders for the fourth quarter of 2018 of $0.980 per unit, or $234.8 million in aggregate, including incentive distributions, but excluding distributions on Class C units. The cash distribution was paid on February 13, 2019, to unitholders of record at the close of business on February 1, 2019. In connection with the closing of the DBM acquisition in November 2014, we issued Class C units that will receive distributions in the form of additional Class C units until the earlier of (i) the consummation of the Merger (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K) or (ii) March 1, 2020, unless we elect to convert such units earlier or Anadarko extends the conversion date (see Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K). The Class C unit distribution, if paid in cash, would have been $14.1 million for the fourth quarter of 2018.

Management continuously monitors our leverage position and coordinates our capital expenditure program, quarterly distributions and acquisition strategy with our expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance outstanding debt balances with longer term notes. To facilitate potential debt or equity securities offerings, we have the ability to sell securities under our shelf registration statements. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part I, Item 1A of our 2018 Form 10-K.

Working capital. As of December 31, 2018, we had a $270.2 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Working capital is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable and factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for maintenance and expansion activity. Our working capital deficit as of December 31, 2018, was primarily due to (i) the costs incurred related to continued construction and expansion at the West Texas and DJ Basin complexes, the DBM and DJ Basin oil systems and the DBM water systems and (ii) system shutdowns at the Kitty Draw gathering system (part of the Hilight system) and Third Creek gathering system (part of the DJ Basin complex). See Note 1—Summary of Significant Accounting Policies and Note 11—Components of Working Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K. As of December 31, 2018, we had $1.3 billion available for borrowing under the RCF. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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

•

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


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

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



	Year Ended December 31,
thousands	2018		2017		2016
Acquisitions	$	162,112	$	181,708	$	716,465

Expansion capital expenditures	$	1,827,730	$	949,375	$	467,005
Maintenance capital expenditures	120,865		77,557		80,981
Total capital expenditures ^{(1) (2)}	$	1,948,595	$	1,026,932	$	547,986

Capital incurred ^{(2) (3)}	$	1,910,508	$	1,252,067	$	550,895


⁽¹⁾	Capital expenditures for the years ended December 31, 2017 and 2016, are presented net of $1.4 million and $6.1 million, respectively, of contributions in aid of construction costs from affiliates. Capital expenditures for the years ended December 31, 2018, 2017 and 2016, included $762.8 million, $353.3 million and $74.1 million, respectively, of pre-acquisition capital expenditures for AMA.


⁽²⁾	For the years ended December 31, 2018, 2017 and 2016, included $31.1 million, $9.1 million and $9.3 million, respectively, of capitalized interest.


⁽³⁾	Capital incurred for the years ended December 31, 2018, 2017 and 2016, included $733.1 million, $453.4 million and $59.5 million, respectively, of pre-acquisition capital incurred for AMA.

Acquisitions during 2018 included a 20% interest in Whitethorn, a 15% interest in Cactus II and equipment purchases from Anadarko. Acquisitions during 2017 included the Additional DBJV System Interest, the additional interest in Ranch Westex and equipment purchases from Anadarko. Acquisitions during 2016 included Springfield and equipment purchases from Anadarko. See Note 3—Acquisitions and Divestitures and Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Capital expenditures, excluding acquisitions, increased by $921.7 million for the year ended December 31, 2018. Expansion capital expenditures increased by $878.4 million (including a $22.0 million increase in capitalized interest) for the year ended December 31, 2018, primarily due to increases of (i) $271.7 million at the West Texas complex, $222.4 million at the DJ Basin complex and $182.4 million at the DBM oil system, primarily due to pipe, compression and processing projects, and (ii) $200.2 million at the DBM water systems due to produced-water gathering and disposal projects. Maintenance capital expenditures increased by $43.3 million for the year ended December 31, 2018, primarily due to increases at the DJ Basin and West Texas complexes and the DJ Basin oil system, which were partially offset by a decrease at the DBM oil system.

Capital expenditures, excluding acquisitions, increased by $478.9 million for the year ended December 31, 2017. Expansion capital expenditures increased by $482.4 million (including a $0.2 million decrease in capitalized interest) for the year ended December 31, 2017, primarily due to (i) increases of $187.2 million at the DBM oil system, $176.5 million at the DBJV system and $70.1 million at the DJ Basin complex, primarily due to pipe and compression projects, and (ii) an increase of $149.6 million due to the construction of the DBM water systems. These increases were partially offset by decreases of $77.5 million and $17.6 million at the DBM complex and the DJ Basin oil system, respectively. Maintenance capital expenditures decreased by $3.4 million for the year ended December 31, 2017, primarily due to the Property Exchange in March 2017 and decreases at the DBM complex due to repairs made in 2016 as a result of the incident in 2015. These decreases were partially offset by increases at the DBM oil system and the Hilight and Haley systems.

For the year ending December 31, 2019, we estimate that our total capital expenditures will be between $1.3 billion to $1.4 billion (excluding acquisitions and including our 75% share of Chipeta’s capital expenditures, equity investments and the 30% interest in Red Bluff Express Pipeline, LLC we closed on in January 2019) and our maintenance capital expenditures will be between $110 million to $120 million.

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



	Year Ended December 31,
thousands	2018			2017			2016
Net cash provided by (used in):
Operating activities	$	1,352,114		$	1,046,798		$	1,060,658
Investing activities	(2,210,813		)	(1,133,324		)	(1,229,874		)
Financing activities	870,333			(192,585		)	429,108
Net increase (decrease) in cash and cash equivalents	$	11,634		$	(279,111	)	$	259,892

Operating Activities. Net cash provided by operating activities increased for the year ended December 31, 2018, primarily due to the impact of changes in working capital items and increases in distributions from equity investments. Net cash provided by operating activities decreased for the year ended December 31, 2017, primarily due to the impact of changes in working capital items. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2018, included the following:


•	$1.9 billion of capital expenditures, primarily related to construction and expansion at the DBM oil and DBM water systems and the West Texas and DJ Basin complexes;


•	$161.9 million of cash paid for the acquisitions of the interests in Whitethorn and Cactus II;


•	$133.6 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Whitethorn and White Cliffs for construction activities; and


•	$29.6 million of distributions received from equity investments in excess of cumulative earnings.

Net cash used in investing activities for the year ended December 31, 2017, included the following:


•	$1.0 billion of capital expenditures, net of $1.4 million of contributions in aid of construction costs from affiliates, primarily related to construction and expansion at the DBJV system, DBM complex, DBM oil system and DJ Basin complex and the construction of the DBM water systems;


•	$155.3 million of cash consideration paid as part of the Property Exchange;


•	$31.7 million of distributions received from equity investments in excess of cumulative earnings;


•	$23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah;


•	$23.0 million of proceeds from property insurance claims attributable to the incident at the DBM complex in 2015;


•	$22.5 million of cash paid for the acquisition of the additional interest in Ranch Westex; and


•	$3.9 million of cash paid for equipment purchases from Anadarko.

Net cash used in investing activities for the year ended December 31, 2016, included the following:


•	$712.5 million of cash paid for the acquisition of Springfield;

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•	$548.0 million of capital expenditures, net of $6.1 million of contributions in aid of construction costs from affiliates, primarily related to plant construction and expansion at the DBM and DJ Basin complexes and the DBJV system;


•	$58.7 million of capital contributions primarily paid to Saddlehorn and Panola for construction activities;


•	$45.1 million of net proceeds from the sale of the Hugoton system in Southwest Kansas and Oklahoma;


•	$29.7 million of distributions received from equity investments in excess of cumulative earnings;


•	$17.5 million of proceeds from property insurance claims attributable to the incident at the DBM complex in 2015; and


•	$4.0 million of cash paid for equipment purchases from Anadarko.

Financing Activities. Net cash provided by financing activities for the year ended December 31, 2018, included the following:


•	$1.08 billion of net proceeds from the offering of the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 in March 2018, after underwriting and original issue discounts and offering costs, which were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures;


•	$893.6 million of distributions paid to our unitholders;


•	$738.1 million of net proceeds from the offering of the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 in August 2018, after underwriting and original issue discounts and offering costs, which were used to repay the maturing 2.600% Senior Notes due August 2018, repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures;


•	$690.0 million of repayments of outstanding borrowings under the RCF;


•	$534.2 million of borrowings under the RCF, net of extension and amendment costs, which were used for general partnership purposes, including to fund capital expenditures;


•	$350.0 million of principal repayment on the maturing 2.600% Senior Notes due August 2018;


•	$321.8 million in borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;


•	$97.8 million of net contributions from Anadarko representing pre-acquisition intercompany transactions attributable to the acquisition of AMA;


•	$51.6 million of capital contributions from Anadarko related to the above-market component of swap agreements;


•	$13.5 million of distributions paid to the noncontrolling interest owner of Chipeta; and


•	$3.4 million of issuance costs incurred in connection with the 364-day Facility.

Net cash used in financing activities for the year ended December 31, 2017, included the following:


•	$801.3 million of distributions paid to our unitholders;


•	$370.0 million of borrowings under the RCF, which were used for general partnership purposes, including funding of capital expenditures;

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•	$125.6 million of net contributions from Anadarko representing pre-acquisition intercompany transactions attributable to the acquisition of AMA;


•	$98.8 million in borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;


•	$58.6 million of capital contributions from Anadarko related to the above-market component of swap agreements;


•	$37.3 million of cash paid to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko; and


•	$13.6 million of distributions paid to the noncontrolling interest owner of Chipeta.

Net cash provided by financing activities for the year ended December 31, 2016, included the following:


•	$900.0 million of repayments of outstanding borrowings under the RCF;


•	$671.9 million of distributions paid to our unitholders;


•	$599.3 million of borrowings under the RCF, net of extension costs, which were used to fund a portion of the Springfield acquisition and for general partnership purposes, including funding capital expenditures;


•	$494.6 million of net proceeds from the offering of the 4.650% Senior Notes due 2026 in July 2016, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under the RCF;


•	$440.0 million of net proceeds from the issuance of 14,030,611 Series A Preferred units in March 2016, all of which was used to fund a portion of the acquisition of Springfield;


•	$246.9 million of net proceeds from the issuance of 7,892,220 Series A Preferred units in April 2016, all of which was used to pay down amounts borrowed under the RCF in connection with the acquisition of Springfield;


•	$203.3 million of net proceeds from the offering of the additional 5.450% Senior Notes due 2044 in October 2016, after underwriting discounts and original issue premium and offering costs, all of which was used to repay amounts then outstanding under the RCF and for general partnership purposes, including capital expenditures;


•	$45.8 million of capital contributions from Anadarko related to the above-market component of swap agreements;


•	$42.2 million of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to the acquisitions of Springfield and AMA;


•	$25.0 million of net proceeds from the sale of common units to WGP, all of which was used to fund a portion of the acquisition of Springfield; and


•	$13.8 million of distributions paid to the noncontrolling interest owner of Chipeta.

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Debt and credit facilities. As of December 31, 2018, the carrying value of our outstanding debt was $5.2 billion. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Senior Notes. In August 2018, the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 were offered to the public at prices of 99.818% and 98.912%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the senior notes are 4.885% and 5.652%, respectively. Interest is paid on each such series semi-annually on February 15 and August 15 of each year, beginning February 15, 2019. The net proceeds were used to repay the maturing 2.600% Senior Notes due August 2018, repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures.

In March 2018, the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 were offered to the public at prices of 99.435% and 99.169%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the senior notes are 4.682% and 5.431%, respectively. Interest is paid on each such series semi-annually on March 1 and September 1 of each year, beginning September 1, 2018. The net proceeds were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures.

At December 31, 2018, we were in compliance with all covenants under the indentures governing our outstanding notes.

Revolving credit facility. In February 2018, we entered into the five-year $1.5 billion RCF by amending and restating the $1.2 billion credit facility that was originally entered into in February 2014. The RCF is expandable to a maximum of $2.0 billion, matures in February 2023, with options to extend maturity by up to two additional one year increments, and bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based upon our senior unsecured debt rating. We are required to pay a quarterly facility fee ranging from 0.125% to 0.250% of the commitment amount (whether used or unused), also based upon our senior unsecured debt rating.

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

As of December 31, 2018, we had $220.0 million in outstanding borrowings and $4.6 million in outstanding letters of credit, resulting in $1.3 billion available for borrowing under the RCF. At December 31, 2018, the interest rate on the RCF was 3.74% and the facility fee rate was 0.20%. At December 31, 2018, we were in compliance with all covenants under the RCF.

In December 2018, we entered into an amendment to the RCF for (i) subject to the consummation of the Merger (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K), an increase to the size of the RCF to $2.0 billion, while leaving the $0.5 billion accordion feature of the RCF unexercised, and (ii) effective on February 15, 2019, the exercise of one of our one-year extension options to extend the maturity date of the RCF to February 2024.

All notes and obligations under the RCF are recourse to our general partner. Our general partner is indemnified by wholly owned subsidiaries of Anadarko against any claims made against the general partner for our long-term debt and/or borrowings under the RCF.

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364-day Facility. In December 2018, we entered into the $2.0 billion 364-day Facility, the proceeds of which will be used to fund substantially all of the cash portion of the consideration under the Merger Agreement and the payment of related transaction costs (see Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K). The 364-day Facility will mature on the day prior to the one-year anniversary of the completion of the Merger, and will bear interest at LIBOR, plus applicable margins ranging from 1.000% to 1.625%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case as defined in the 364-day Facility and plus applicable margins currently ranging from zero to 0.625%, based upon our senior unsecured debt rating. We are also required to pay a ticking fee of 0.175% on the commitment amount beginning 90 days after the effective date of the credit agreement through the date of funding under the 364-day Facility.

Funding of the 364-day Facility is conditioned upon the consummation of the Merger and net cash proceeds received from future asset sales and debt or equity offerings by us must be used to repay amounts outstanding under the facility. The 364-day Facility contains covenants and customary events of default that are substantially similar to those contained in the RCF.

APCWH Note Payable. In June 2017, in connection with funding the construction of the APC water systems, which were acquired as part of the AMA acquisition, APCWH entered into an eight-year note payable agreement with Anadarko (the “APCWH Note Payable”). This note payable has a maximum borrowing limit of $500 million, and accrues interest, which is payable upon maturity, at the applicable mid-term federal rate based on a quarterly compounding basis as determined by the U.S. Secretary of the Treasury.

As of December 31, 2018, we had $427.5 million in outstanding borrowings under the APCWH Note Payable and the interest rate on outstanding borrowings was 3.04%. At December 31, 2018, we were in compliance with all covenants under this agreement.

Interest-rate swaps. In December 2018, we entered into interest-rate swap agreements with an aggregate notional amount of $750.0 million to manage interest rate risk associated with anticipated 2019 debt issuances. Pursuant to these swap agreements, we exchanged a floating interest rate indexed to the three-month LIBOR for a fixed interest rate. Depending on market conditions, liability management actions or other factors, we may settle or amend certain or all of the currently outstanding interest-rate swaps.

We do not apply hedge accounting and, therefore, gains and losses associated with the interest-rate swaps are recognized currently in earnings. For the year ended December 31, 2018, we recognized a non-cash loss of $8.0 million, which is included in Other income (expense), net in the consolidated statements of operations. The fair value of the interest-rate swaps as of December 31, 2018, was an $8.0 million liability, which is reported in Accrued liabilities on the consolidated balance sheets. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for additional information.

DBJV acquisition - Deferred purchase price obligation - Anadarko. Prior to our agreement with Anadarko to settle the deferred purchase price obligation early, the consideration that would have been paid for the March 2015 acquisition of DBJV from Anadarko consisted of a cash payment to Anadarko due on March 31, 2020. In May 2017, we reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.

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Securities. We may issue an indeterminate amount of common units and various debt securities under our effective shelf registration statement on file with the SEC. We may also issue common units under the $500.0 million COP, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of offering. As of December 31, 2018, we had issued no common units under the registration statement associated with the $500.0 million COP. Upon the consummation of the Merger, we will terminate the registration statement relating to the $500.0 million COP and, therefore, common units will no longer be available for issuance thereunder. See Note 15—Subsequent Events in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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

We do not, however, maintain a credit limit with respect to Anadarko. Consequently, we are subject to the risk of non-payment or late payment by Anadarko for gathering, processing, transportation and disposal fees and for proceeds from the sale of residue, NGLs and condensate to Anadarko.

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we are exposed to credit risk on the note receivable from Anadarko. We are also party to agreements with Anadarko under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits and income taxes with respect to the assets acquired from Anadarko. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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

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CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual cash obligations as of December 31, 2018. 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 2019.



	Obligations by Period
thousands	2019		2020		2021		2022		2023		Thereafter		Total
Long-term debt
Principal	$	—	$	—	$	500,000	$	670,000	$	220,000	$	3,870,593	$	5,260,593
Interest	231,068		231,068		214,420		204,019		170,079		2,310,717		3,361,371
Asset retirement obligations	25,938		28,111		6,297		—		—		265,616		325,962
Capital expenditures	85,346		—		—		—		—		—		85,346
Credit facility fees	3,100		3,100		3,100		3,100		396		—		12,796
Environmental obligations	863		292		291		109		110		—		1,665
Operating leases	8,711		2,236		460		467		473		1,547		13,894
Total	$	355,026	$	264,807	$	724,568	$	877,695	$	391,058	$	6,448,473	$	9,061,627

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 in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settlement. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Capital expenditures. Included in this amount are capital obligations related to our expansion projects. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual obligations made in advance of the actual expenditures. See Note 14—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Credit facility fees. For additional information on credit facility fees required under the RCF, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Environmental obligations. We are subject to various environmental remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We regularly monitor the remediation and reclamation process and the liabilities recorded and believe that the amounts reflected in our recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations. For additional information on environmental obligations, see Note 14—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

Operating leases. Anadarko, on our behalf, has entered into lease arrangements for corporate offices, shared field offices and equipment supporting our operations, for which it charges us rent. The amounts above represent existing contractual operating lease obligations that may be assigned or otherwise charged to us pursuant to the reimbursement provisions of the omnibus agreement. See Note 14—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

For additional information on contracts, obligations and arrangements we enter into from time to time, see Note 6—Transactions with Affiliates and Note 14—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with GAAP requires our management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and affect the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of property, plant and equipment, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues and fair values. On an annual basis, as determined by the specific agreement, management reviews and updates certain gathering rates that are based on cost of service agreements. These cost of service gathering rates are calculated using a contractually specified rate of return and estimates including long-term assumptions for capital invested, receipt volumes, and operating and maintenance expenses, among others. See Contract balances in Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with the Audit Committee of our general partner. For additional information concerning our accounting policies, see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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

In assessing long-lived assets for impairments, our management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. Since a significant portion of our revenues arises from gathering, processing and transporting production from Anadarko-operated properties, significant downward revisions in reserve estimates or changes in future development plans by Anadarko, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability. Such assessment requires application of judgment regarding the use and ultimate disposition of the asset, long-range revenue and expense estimates, global and regional economic conditions, including commodity prices and drilling activity by our customers, as well as other factors affecting estimated future net cash flows. The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. See Note 8—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K for a description of impairments recorded during the years ended December 31, 2018, 2017 and 2016.

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Fair value. Among other things, management estimates fair value (i) of long-lived assets for impairment testing, (ii) of reporting units for goodwill impairment testing when necessary, (iii) of assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, (iv) for the initial measurement of asset retirement obligations, (v) for the initial measurement of environmental obligations assumed in a third-party acquisition and (vi) of interest-rate swaps. When our management is required to measure fair value and there is not a market-observable price for the asset or liability or 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 cost approach is based on management’s best estimate of the current asset replacement cost. 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 multiples approach uses management’s best assumptions regarding expectations of projected EBITDA and the multiple of that EBITDA that a buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than operating leases and standby letters of credit. The information pertaining to operating leases and our standby letters of credit required for this item is provided under Note 14—Commitments and Contingencies and Note 13—Debt and Interest Expense, respectively, included in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 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 Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk. Certain of our processing services are provided under percent-of-proceeds and keep-whole agreements in which Anadarko is typically responsible for the marketing of the natural gas, condensate and NGLs. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of residue and/or NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced and the processed natural gas, or value of the natural gas, is returned to the producer, and because some of the gas is used and removed during processing, we compensate the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas used.

For the year ended December 31, 2018, 89% of our wellhead natural gas volumes (excluding equity investments) and 100% of our crude oil and produced water throughput (excluding equity investments) were attributable to fee-based contracts. A 10% increase or decrease in commodity prices would not have a material impact on our operating income (loss), financial condition or cash flows for the next twelve months, excluding the effect of imbalances described below.

We bear a limited degree of commodity price risk with respect to settlement of our natural gas imbalances that arise from differences in gas volumes received into our systems and gas volumes delivered by us to customers, as well as instances where our actual liquids recovery or fuel usage varies from the contractually stipulated amounts. Natural gas volumes owed to or by us that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates, and generally reflect market index prices. Other natural gas volumes owed to or by us are valued at our weighted-average cost of natural gas as of the balance sheet dates and are settled in-kind. Our exposure to the impact of changes in commodity prices on outstanding imbalances depends on the timing of settlement of the imbalances.

Interest rate risk. The FOMC raised its target range for the federal funds rate three separate times during 2017 and four times during 2018. These increases, and any future increases, in the federal funds rate will ultimately result in an increase in our financing costs. As of December 31, 2018, we had $220.0 million in outstanding borrowings under the RCF (which bears interest at a rate based on LIBOR or, at our option, an alternative base rate). While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on outstanding borrowings under the RCF, it would impact the fair value of the Senior Notes at December 31, 2018.

In December 2018, we entered into interest-rate swap agreements to manage interest rate risk associated with anticipated 2019 debt issuances. At December 31, 2018, we had a net derivative liability position of $8.0 million related to interest-rate swaps. A 10% increase or decrease in the LIBOR interest rate curve would change the aggregate fair value of outstanding interest-rate swap agreements by $23.2 million. However, any change in the interest rate derivative gain or loss could be substantially offset by changes in actual borrowing costs associated with anticipated 2019 debt issuances. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of Exhibit 99.1 to this Current Report on Form 8-K.

We may incur additional variable-rate debt in the future, either under the RCF, the 364-day Facility or other financing sources, including commercial bank borrowings or debt issuances.

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Item 8. Financial Statements and Supplementary Data

On February 28, 2019, in connection with the closing of the Merger (see Note 15—Subsequent Events), (i) Western Gas Partners, LP changed its name to Western Midstream Operating, LP and (ii) Western Gas Equity Partners, LP changed its name to Western Midstream Partners, LP. Item 8 of Exhibit 99.1 of this Current Report on Form 8-K, will refer to the reporting entities by their names as of the original filing date of the Form 10-K for the year ended December 31, 2018, filed with the U.S. Securities and Exchange Commission on February 20, 2019.

WESTERN GAS PARTNERS, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm	72
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016	73
Consolidated Balance Sheets as of December 31, 2018 and 2017	74
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2018, 2017 and 2016	75
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	76
Notes to Consolidated Financial Statements	77
Note 1. Summary of Significant Accounting Policies	77
Note 2. Revenue from Contracts with Customers	88
Note 3. Acquisitions and Divestitures	90
Note 4. Partnership Distributions	94
Note 5. Equity and Partners’ Capital	96
Note 6. Transactions with Affiliates	99
Note 7. Income Taxes	105
Note 8. Property, Plant and Equipment	107
Note 9. Goodwill and Intangibles	108
Note 10. Equity Investments	109
Note 11. Components of Working Capital	111
Note 12. Asset Retirement Obligations	112
Note 13. Debt and Interest Expense	113
Note 14. Commitments and Contingencies	116
Note 15. Subsequent Events	118
Supplemental Quarterly Information	119

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WESTERN GAS PARTNERS, LP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP) and Unitholders of Western Midstream Partners, LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Western Gas Partners, LP and subsidiaries (the Partnership) as of December 31, 2018 and 2017, the related consolidated statements of operations, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Partnership has changed its method of accounting for revenue recognition in 2018 due to the adoption of Accounting Standards Codification Topic 606 Revenue from Contracts with Customers.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2007.

Houston, Texas

May 17, 2019

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS



	Year Ended December 31,
thousands except per-unit amounts	2018 ⁽¹⁾			2017 ⁽¹⁾			2016 ⁽¹⁾
Revenues and other – affiliates
Service revenues – fee based	$	1,070,066		$	769,305		$	853,837
Service revenues – product based	3,339			—			—
Product sales	280,306			753,724			505,081
Other	—			16,076			—
Total revenues and other – affiliates	1,353,711			1,539,105			1,358,918
Revenues and other – third parties
Service revenues – fee based	835,662			588,571			484,093
Service revenues – product based	85,446			—			—
Product sales	22,714			297,486			94,168
Other	2,125			4,452			4,151
Total revenues and other – third parties	945,947			890,509			582,412
Total revenues and other	2,299,658			2,429,614			1,941,330
Equity income, net – affiliates	195,469			115,141			101,692
Operating expenses
Cost of product ⁽²⁾	415,505			953,792			517,371
Operation and maintenance ⁽²⁾	480,861			345,617			332,405
General and administrative ⁽²⁾	63,166			51,077			48,701
Property and other taxes	51,848			53,147			45,638
Depreciation and amortization	389,164			318,771			295,959
Impairments	230,584			180,051			17,822
Total operating expenses	1,631,128			1,902,455			1,257,896
Gain (loss) on divestiture and other, net ⁽³⁾	1,312			132,388			(14,641		)
Proceeds from business interruption insurance claims	—			29,882			16,270
Operating income (loss)	865,311			804,570			786,755
Interest income – affiliates	16,900			16,900			16,900
Interest expense ⁽⁴⁾	(181,796		)	(140,291		)	(107,565		)
Other income (expense), net	(4,955		)	1,299			479
Income (loss) before income taxes	695,460			682,478			696,569
Income tax expense (benefit)	58,934			(59,923		)	32,969
Net income (loss)	636,526			742,401			663,600
Net income attributable to noncontrolling interest	8,609			10,735			10,963
Net income (loss) attributable to Western Gas Partners, LP	$	627,917		$	731,666		$	652,637
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Gas Partners, LP	$	627,917		$	731,666		$	652,637
Pre-acquisition net (income) loss allocated to Anadarko	(182,142		)	(164,183		)	(72,632		)
Series A Preferred units interest in net (income) loss ⁽⁵⁾	—			(42,373		)	(76,893		)
General partner interest in net (income) loss ⁽⁵⁾	(346,538		)	(303,835		)	(236,561		)
Common and Class C limited partners’ interest in net income (loss) ⁽⁵⁾	99,237			221,275			266,551
Net income (loss) per common unit – basic and diluted ⁽⁵⁾	$	0.55		$	1.30		$	1.74


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to AMA. See Note 1 and Note 3.

⁽²⁾

Cost of product includes product purchases from affiliates (as defined in Note 1) of $168.5 million, $74.6 million and $76.0 million for the years ended December 31, 2018, 2017 and 2016, respectively. Operation and maintenance includes charges from affiliates of $115.9 million, $82.2 million and $82.1 million for the years ended December 31, 2018, 2017 and 2016, respectively. General and administrative includes charges from affiliates of $48.8 million, $42.4 million and $41.2 million for the years ended December 31, 2018, 2017 and 2016, respectively. See Note 6.


⁽³⁾	Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.


⁽⁴⁾	Includes affiliate (as defined in Note 1) amounts of $(6.7) million, $(0.2) million and $7.7 million for the years ended December 31, 2018, 2017 and 2016, respectively. See Note 3 and Note 13.


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

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS



	December 31,
thousands except number of units	2018 ⁽¹⁾		2017 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	90,448	$	78,814
Accounts receivable, net ⁽²⁾	221,373		160,910
Other current assets ⁽³⁾	26,181		15,409
Total current assets	338,002		255,133
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	11,258,773		8,979,618
Less accumulated depreciation	2,848,420		2,213,718
Net property, plant and equipment	8,410,353		6,765,900
Goodwill	445,800		445,800
Other intangible assets	841,408		872,187
Equity investments	1,092,088		817,352
Other assets ⁽⁴⁾	67,194		11,757
Total assets	$	11,454,845	$	9,428,129
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables	$	443,343	$	466,838
Accrued ad valorem taxes	36,986		33,136
Accrued liabilities ⁽⁵⁾	127,874		47,899
Total current liabilities	608,203		547,873
Long-term liabilities
Long-term debt	4,787,381		3,464,712
APCWH Note Payable ⁽⁶⁾	427,493		98,966
Deferred income taxes	280,017		139,635
Asset retirement obligations	300,024		152,267
Other liabilities ⁽⁷⁾	132,130		3,494
Total long-term liabilities	5,927,045		3,859,074
Total liabilities	6,535,248		4,406,947
Equity and partners’ capital
Common units (152,609,285 and 152,602,105 units issued and outstanding at December 31, 2018 and 2017, respectively)	2,475,540		2,950,010
Class C units (14,372,665 and 13,243,883 units issued and outstanding at December 31, 2018 and 2017, respectively) ⁽⁸⁾	791,410		780,040
General partner units (2,583,068 units issued and outstanding at December 31, 2018 and 2017)	206,862		179,232
Net investment by Anadarko	1,388,018		1,050,171
Total partners’ capital	4,861,830		4,959,453
Noncontrolling interest	57,767		61,729
Total equity and partners’ capital	4,919,597		5,021,182
Total liabilities, equity and partners’ capital	$	11,454,845	$	9,428,129


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to AMA. See Note 1 and Note 3.


⁽²⁾	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $72.8 million and $36.3 million as of December 31, 2018 and 2017, respectively.


⁽³⁾	Other current assets includes affiliate amounts of $3.7 million and zero as of December 31, 2018 and 2017, respectively.


⁽⁴⁾	Other assets includes affiliate amounts of $42.2 million and zero as of December 31, 2018 and 2017, respectively.


⁽⁵⁾	Accrued liabilities includes affiliate amounts of $2.2 million and $0.2 million as of December 31, 2018 and 2017, respectively.


⁽⁶⁾	See Note 6 and Note 15.


⁽⁷⁾	Other liabilities includes affiliate amounts of $47.8 million and $0.7 million as of December 31, 2018 and 2017, respectively.


⁽⁸⁾	All outstanding Class C units will convert into the Partnership’s common units on a one-for-one basis immediately prior to the closing of the Merger (as defined in Note 15), if consummated. If the Merger is not consummated, the conversion will occur on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 5 and Note 15.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL



	Partners’ Capital
thousands	Net Investment by Anadarko			Common Units			Class C Units			Series A Preferred Units			General Partner Units			Noncontrolling Interest			Total
Balance at December 31, 2015 ⁽¹⁾	$	1,155,956		$	2,588,991		$	710,891		$	—		$	120,164		$	67,384		$	4,643,386
Net income (loss)	72,632			269,018			28,642			45,784			236,561			10,963			663,600
Above-market component of swap agreements with Anadarko ⁽²⁾	—			45,820			—			—			—			—			45,820
Issuance of common units, net of offering expenses	—			25,000			—			—			—			—			25,000
Issuance of Series A Preferred units, net of offering expenses	—			—			—			686,937			—			—			686,937
Beneficial conversion feature of Series A Preferred units	—			93,409			—			(93,409		)	—			—			—
Amortization of beneficial conversion feature of Class C units and Series A Preferred units	—			(42,407		)	11,298			31,109			—			—			—
Distributions to noncontrolling interest owner	—			—			—			—			—			(13,784		)	(13,784		)
Distributions to unitholders	—			(428,231		)	—			(30,876		)	(212,831		)	—			(671,938		)
Acquisitions from affiliates	(553,833		)	(158,667		)	—			—			—			—			(712,500		)
Revision to Deferred purchase price obligation – Anadarko ⁽³⁾	—			139,487			—			—			—			—			139,487
Contributions of equity-based compensation from Anadarko	—			4,131			—			—			83			—			4,214
Net pre-acquisition contributions from (distributions to) Anadarko	(42,224		)	—			—			—			—			—			(42,224		)
Net contributions from (distributions to) Anadarko of other assets	130			(572		)	—			—			(9		)	—			(451		)
Elimination of net deferred tax liabilities	129,229			—			—			—			—			—			129,229
Other	—			893			—			—			—			—			893
Balance at December 31, 2016 ⁽¹⁾	$	761,890		$	2,536,872		$	750,831		$	639,545		$	143,968		$	64,563		$	4,897,669
Net income (loss)	164,183			231,405			24,790			7,453			303,835			10,735			742,401
Above-market component of swap agreements with Anadarko ⁽²⁾	—			58,551			—			—			—			—			58,551
Conversion of Series A Preferred units into common units ⁽⁴⁾	—			686,936			—			(686,936		)	—			—			—
Amortization of beneficial conversion feature of Class C units and Series A Preferred units	—			(66,718		)	4,419			62,299			—			—			—
Distributions to noncontrolling interest owner	—			—			—			—			—			(13,569		)	(13,569		)
Distributions to unitholders	—			(510,228		)	—			(22,361		)	(268,711		)	—			(801,300		)
Acquisitions from affiliates	(1,263		)	1,263			—			—			—			—			—
Revision to Deferred purchase price obligation – Anadarko⁽³⁾	—			4,165			—			—			—			—			4,165
Contributions of equity-based compensation from Anadarko	—			4,473			—			—			90			—			4,563
Net pre-acquisition contributions from (distributions to) Anadarko	126,866			—			—			—			—			—			126,866
Net contributions from (distributions to) Anadarko of other assets	—			3,139			—			—			50			—			3,189
Elimination of net deferred tax liabilities	(1,505		)	—			—			—			—			—			(1,505		)
Other	—			152			—			—			—			—			152
Balance at December 31, 2017 ⁽¹⁾	$	1,050,171		$	2,950,010		$	780,040		$	—		$	179,232		$	61,729		$	5,021,182
Cumulative effect of accounting change ⁽⁵⁾	629			(41,108		)	(3,533		)	—			(696		)	958			(43,750		)
Net income (loss)	182,142			87,581			11,656			—			346,538			8,609			636,526
Above-market component of swap agreements with Anadarko ⁽²⁾	—			51,618			—			—			—			—			51,618
Amortization of beneficial conversion feature of Class C units	—			(3,247		)	3,247			—			—			—			—
Distributions to noncontrolling interest owner	—			—			—			—			—			(13,529		)	(13,529		)
Distributions to unitholders	—			(575,323		)	—			—			(318,326		)	—			(893,649		)
Contributions of equity-based compensation from Anadarko	—			5,613			—			—			114			—			5,727
Net pre-acquisition contributions from (distributions to) Anadarko	97,755			—			—			—			—			—			97,755
Net contributions from (distributions to) Anadarko of other assets	58,835			—			—			—			—			—			58,835
Elimination of net deferred tax liabilities	(1,514		)	—			—			—			—			—			(1,514		)
Other	—			396			—			—			—			—			396
Balance at December 31, 2018 ⁽¹⁾	$	1,388,018		$	2,475,540		$	791,410		$	—		$	206,862		$	57,767		$	4,919,597


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to AMA. See Note 1 and Note 3.


⁽²⁾	See Note 6.


⁽³⁾	See Note 3.


⁽⁴⁾	See Note 5.


⁽⁵⁾	See Note 1.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Year Ended December 31,
thousands	2018 ⁽¹⁾			2017 ⁽¹⁾			2016 ⁽¹⁾
Cash flows from operating activities
Net income (loss)	$	636,526		$	742,401		$	663,600
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	389,164			318,771			295,959
Impairments	230,584			180,051			17,822
Non-cash equity-based compensation expense	6,153			4,922			4,735
Deferred income taxes	139,048			(53,138		)	51,192
Accretion and amortization of long-term obligations, net	5,142			4,254			(3,789		)
Equity income, net – affiliates	(195,469		)	(115,141		)	(101,692		)
Distributions from equity investment earnings – affiliates	187,392			117,093			104,948
(Gain) loss on divestiture and other, net ⁽²⁾	(1,312		)	(132,388		)	14,641
(Gain) loss on interest-rate swaps	7,972			—			—
Lower of cost or market inventory adjustments	752			145			168
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(60,460		)	(16,177		)	(48,441		)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net	44,424			(947		)	60,696
Change in other items, net	(37,802		)	(3,048		)	819
Net cash provided by operating activities	1,352,114			1,046,798			1,060,658
Cash flows from investing activities
Capital expenditures	(1,948,595		)	(1,028,319		)	(554,121		)
Contributions in aid of construction costs from affiliates	—			1,387			6,135
Acquisitions from affiliates	(254		)	(3,910		)	(716,465		)
Acquisitions from third parties	(161,858		)	(177,798		)	—
Investments in equity affiliates	(133,629		)	(2,884		)	(58,726		)
Distributions from equity investments in excess of cumulative earnings – affiliates	29,585			31,659			29,725
Proceeds from the sale of assets to affiliates	—			—			623
Proceeds from the sale of assets to third parties	3,938			23,564			45,490
Proceeds from property insurance claims	—			22,977			17,465
Net cash used in investing activities	(2,210,813		)	(1,133,324		)	(1,229,874		)
Cash flows from financing activities
Borrowings, net of debt issuance costs ⁽³⁾	2,671,344			468,803			1,297,218
Repayments of debt	(1,040,000		)	—			(900,000		)
Settlement of the Deferred purchase price obligation – Anadarko ⁽⁴⁾	—			(37,346		)	—
Increase (decrease) in outstanding checks	(3,206		)	5,593			2,079
Proceeds from the issuance of common units, net of offering expenses	—			(183		)	25,000
Proceeds from the issuance of Series A Preferred units, net of offering expenses	—			—			686,937
Distributions to unitholders⁽⁵⁾	(893,649		)	(801,300		)	(671,938		)
Distributions to noncontrolling interest owner	(13,529		)	(13,569		)	(13,784		)
Net contributions from (distributions to) Anadarko	97,755			126,866			(42,224		)
Above-market component of swap agreements with Anadarko ⁽⁵⁾	51,618			58,551			45,820
Net cash provided by (used in) financing activities	870,333			(192,585		)	429,108
Net increase (decrease) in cash and cash equivalents	11,634			(279,111		)	259,892
Cash and cash equivalents at beginning of period	78,814			357,925			98,033
Cash and cash equivalents at end of period	$	90,448		$	78,814		$	357,925
Supplemental disclosures
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko ⁽⁴⁾	$	—		$	(4,094	)	$	(147,234	)
Net distributions to (contributions from) Anadarko of other assets ⁽⁶⁾	(58,835		)	(3,189		)	451
Interest paid, net of capitalized interest	139,482			135,079			98,241
Taxes paid (reimbursements received)	2,408			1,194			838
Accrued capital expenditures	274,632			312,720			87,586
Fair value of properties and equipment from non-cash third party transactions ⁽⁴⁾	—			551,453			—


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to AMA. See Note 1 and Note 3.


⁽²⁾	Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.


⁽³⁾	For the years ended December 31, 2018 and 2017, includes $321.8 million and $98.8 million of borrowings, respectively, under the APCWH Note Payable.


⁽⁴⁾	See Note 3.


⁽⁵⁾	See Note 6.


⁽⁶⁾	Includes $(1.4) million related to pipe and equipment purchases and $(1.8) million related to other assets for the year ended December 31, 2017. See Note 6.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership (“MLP”) formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop and operate midstream assets.

For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership. WGP has no independent operations or material assets other than owning the partnership interests in the Partnership (see Holdings of Partnership equity in Note 5). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”), Front Range Pipeline LLC (“FRP”), Whitethorn Pipeline Company LLC (“Whitethorn LLC”), Cactus II Pipeline LLC (“Cactus II”), Saddlehorn Pipeline Company, LLC (“Saddlehorn”), Panola Pipeline Company, LLC (“Panola”), Mi Vida JV LLC (“Mi Vida”) and Ranch Westex JV LLC (“Ranch Westex”). See Note 3. The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “MGR assets” refers to the Red Desert complex and the Granger straddle plant. The “West Texas complex” refers to the Delaware Basin Midstream, LLC (“DBM”) complex and DBJV and Haley systems, all of which were combined into a single complex effective January 1, 2018.

The Partnership is engaged in the business of gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, natural gas liquids (“NGLs”) and crude oil; and gathering and disposing of produced water. In addition, in its capacity as a processor of natural gas, the Partnership also buys and sells natural gas, NGLs and condensate on behalf of itself and as agent for its customers under certain of its contracts. The Partnership provides these midstream services for Anadarko, as well as for third-party customers. As of December 31, 2018, the Partnership’s assets and investments, including AMA (as defined in Note 3), consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems ⁽¹⁾	17	2	3	2
Treating facilities	34	3	—	3
Natural gas processing plants/trains	23	3	—	5
NGLs pipelines	2	—	—	4
Natural gas pipelines	5	—	—	—
Oil pipelines	3	1	—	3


⁽¹⁾	Includes the DBM water systems.

These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. Mentone Train I, a processing train that is part of the West Texas complex, and an additional water system at the DBM water systems commenced operation in the fourth quarter of 2018. Mentone Train II, a second processing train that is part of the West Texas complex, is expected to commence operation in the first quarter of 2019.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Basis of presentation. The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements for entities not wholly owned:



	Percentage Interest
Equity investments ⁽¹⁾
Fort Union	14.81	%
White Cliffs	10.00	%
Rendezvous	22.00	%
Mont Belvieu JV	25.00	%
TEP	20.00	%
TEG	20.00	%
FRP	33.33	%
Whitethorn	20.00	%
Cactus II	15.00	%
Saddlehorn	20.00	%
Panola	15.00	%
Mi Vida	50.00	%
Ranch Westex	50.00	%
Proportionate consolidation ⁽²⁾
Marcellus Interest systems	33.75	%
Springfield system	50.10	%
Full consolidation
Chipeta ⁽³⁾	75.00	%


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


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


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

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

Adjustments to previously issued financial statements. The Partnership’s consolidated statements of operations for the year ended December 31, 2018, include adjustments to revenue and cost of product expense of the following amounts: (i) $42.6 million increase in Service revenues - fee based, (ii) $13.8 million increase in Product sales and (iii) $56.4 million increase in Cost of product; all of which relate to the nine months ended September 30, 2018. During the third quarter of 2018, management determined that under ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Topic 606”) adopted on January 1, 2018, the Partnership’s marketing affiliate was acting as the Partnership’s agent in certain product sales transactions on behalf of the Partnership and in performing marketing services on behalf of the Partnership’s customers. The adjustments have no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows or any non-GAAP metric the Partnership uses to evaluate its operations (see How We Evaluate Our Operations under Part II, Item 7 of Exhibit 99.1 to this Current Report on Form 8-K) and are not considered material to the Partnership’s results of operations for the year ended December 31, 2018. The Partnership will revise its previously reported unaudited financial statements for the 2018 interim periods to reflect the adjustments in future filings.

Table of Contents

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Presentation of Partnership assets. The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by the Partnership, including AMA (as defined in Note 3), as of December 31, 2018 (see Note 10). Because Anadarko controls the Partnership through its control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of assets from Anadarko, the Partnership is required to recast its financial statements to include the activities of such Partnership assets from the date of common control.

For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko, including AMA, are prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.

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

Shutdown of gathering systems. In May 2018, after assessing a number of factors, with safety and protection of the environment as the primary focus, the Partnership decided to take the Kitty Draw gathering system in Wyoming (part of the Hilight system) and the Third Creek gathering system in Colorado (part of the DJ Basin complex) permanently out of service. Results for the year ended December 31, 2018, reflect (i) an accrual of $10.9 million in anticipated costs associated with the shutdown of the systems, recorded as a reduction in affiliate Product sales in the consolidated statements of operations and (ii) impairment expense of $134.0 million associated with reducing the net book value of the gathering systems and increasing the asset retirement obligation.

Fair value. The fair-value-measurement standard defines fair value as the price that would be received upon sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three input levels of the fair value hierarchy are as follows:

Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 – Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Table of Contents

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

In determining fair value, management uses observable market data when available, or models that incorporate observable market data. When a fair value measurement is required and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the cost, income, or multiples approach is used, depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. 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 multiples approach uses management’s best assumptions regarding expectations of projected earnings before interest, taxes, depreciation, and amortization (“EBITDA”) and the 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, the assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in the Partnership’s business plans and investment decisions.

In arriving at fair-value estimates, management uses relevant observable inputs available for the valuation technique employed. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair value measurement is characterized based on the lowest level of input that is significant to the fair value measurement. Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs.

The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 13.

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items.

Cash equivalents. All highly liquid investments with a maturity of three months or less when purchased are considered to be cash equivalents.

Allowance for uncollectible accounts. Revenues are primarily from Anadarko, for which no credit limit is maintained. Exposure to bad debts is analyzed on a customer-by-customer basis for its third-party accounts receivable and the Partnership may establish credit limits for significant third-party customers. The allowance for uncollectible accounts was immaterial at December 31, 2018 and 2017.

Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2018, imbalance receivables and payables were $9.0 million and $9.6 million, respectively. As of December 31, 2017, imbalance receivables and payables were $2.1 million and $3.1 million, respectively. Net changes in imbalance receivables and payables are reported in Cost of product in the consolidated statements of operations.

Inventory. The cost of NGLs inventories is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or net realizable value and is reported in Other current assets on the consolidated balance sheets. See Note 11.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Property, plant and equipment. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the assets acquired from Anadarko are initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to partners’ capital.

Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred.

Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area.

Management evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense. Refer to Note 8 for a description of impairments recorded during the years ended December 31, 2018, 2017 and 2016.

Insurance recoveries. Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts that are received from insurance carriers are net of any deductibles related to the covered event. A receivable is recorded from insurance to the extent a loss is recognized from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. A gain on involuntary conversion is recognized when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, gains related to insurance recoveries are not recognized until all contingencies related to such proceeds have been resolved; that is, a cash payment is received from the insurance carrier or there is a binding settlement agreement with the carrier that clearly states that a payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on the consolidated balance sheets and presented as Capital expenditures in the consolidated statements of cash flows. With respect to business interruption insurance claims, income is recognized only when cash proceeds are received from insurers, which are presented in the consolidated statements of operations as a component of Operating income (loss).

In December 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. During the year ended December 31, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to a change in the Partnership’s estimate of the amount that would be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, the Partnership reached a settlement with insurers and final proceeds were received. During the years ended December 31, 2017 and 2016, the Partnership received $52.9 million and $33.8 million, respectively, in cash proceeds from insurers, including $29.9 million and $16.3 million, respectively, in proceeds from business interruption insurance claims and $23.0 million and $17.5 million, respectively, in proceeds from property insurance claims.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred during the period. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset.

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the Partnership assets acquired from Anadarko. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. Goodwill is evaluated for impairment annually, as of October 1, or more often as facts and circumstances warrant. An initial qualitative assessment is performed to determine the likelihood of whether or not goodwill is impaired. If management concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired and further testing is not necessary. If a quantitative assessment must be performed and the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value through a charge to impairment expense. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement. See Note 9.

Other intangible assets. The Partnership assesses intangible assets, as described in Note 9, for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment within this Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets.

Asset retirement obligations. A liability based on the estimated costs of retiring tangible long-lived assets is recognized as an asset retirement obligation in the period incurred. The liability is recognized at fair value, measured using discounted expected future cash outflows for the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Over time, the discounted liability is adjusted to its expected settlement value through accretion expense, which is reported within Depreciation and amortization in the consolidated statements of operations. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 12.

Environmental expenditures. The Partnership expenses environmental obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 14.

Segments. The Partnership’s operations are organized into a single operating segment, the assets of which gather, compress, treat, process and transport natural gas; gather, stabilize and transport condensate, NGLs and crude oil; and gather and dispose of produced water in the United States.

Table of Contents

WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Revenue and cost of product. Upon adoption of the new revenue recognition standard on January 1, 2018 (discussed in Recently adopted accounting standards), the Partnership changed its accounting policy for revenue recognition as described below.

The Partnership provides gathering, processing, treating, transportation and disposal services pursuant to a variety of contracts. Under these arrangements, the Partnership receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in Service revenues and Product sales in the consolidated statements of operations. Payment is generally received from the customer in the month following the service or delivery of the product. Contracts with customers generally have initial terms ranging from 5 to 10 years.

Service revenues – fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation and disposal of natural gas, NGLs, condensate, crude oil and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed upon completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties. The Partnership also recognizes revenue and cost of product expense from marketing services performed on behalf of its customers by Anadarko.

The Partnership also receives Service revenues – fee based from contracts that have minimum volume commitment demand fees and fees that require periodic rate redeterminations based upon the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate.

Service revenues – product based includes service revenues from percent-of-proceeds gathering and processing contracts that are recognized net of the cost of product for purchases from the Partnership’s customers since it is acting as the agent in the product sale. Keep-whole and percent-of-product agreements result in Service revenues – product based being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. Noncash consideration for these services is valued at the time the services are provided. Revenue from product sales is also recognized, along with the cost of product expense related to the sale, when the product received as noncash consideration is sold to either Anadarko or a third party. When the product is sold to Anadarko, Anadarko is acting as the Partnership’s agent in the product sale, with the Partnership recognizing revenue and related cost of product expense associated with these marketing activities based on the Anadarko sales price to the third party.

The Partnership also purchases natural gas volumes from producers at the wellhead or from a production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. When the fees relate to services performed after control of the product has transferred to the Partnership, the fees are treated as a reduction of the purchase cost. If the fees relate to services performed before control of the product has transferred to the Partnership, the fees are treated as Service revenues – fee based. Product sales revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to either Anadarko or a third party.

The Partnership receives aid in construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs, etc.) under certain service contracts. Aid in construction reimbursements are reflected as a contract liability upon receipt and amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Equity-based compensation. Prior to October 17, 2017, phantom unit awards were granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “WES 2008 LTIP”). On October 17, 2017, however, the Partnership’s common and Class C unitholders approved the Western Gas Partners, LP 2017 Long-Term Incentive Plan (the “WES 2017 LTIP”), which replaced the WES 2008 LTIP. As used in this section, the term “WES LTIP” refers to the WES 2008 LTIP with respect to awards granted prior to October 17, 2017, and to the WES 2017 LTIP with respect to awards granted after October 17, 2017. The WES 2017 LTIP permits the issuance of up to 2,250,000 units, of which 2,241,980 units remained available for future issuance as of December 31, 2018. Upon vesting of each phantom unit, the holder will receive common units of the Partnership or, at the discretion of the Board of Directors of its general partner (the “Board of Directors”), cash in an amount equal to the market value of common units of the Partnership on the vesting date. Equity-based compensation expense attributable to grants made under the WES LTIP impacts cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. Equity-based compensation expense attributable to grants made under the WES LTIP is amortized over the vesting periods applicable to the awards.

Additionally, general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) and (ii) the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as amended and restated (the “Anadarko Incentive Plan”) for all periods presented. Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plan does not impact cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized.

Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership’s acquisition of these assets from Anadarko.

For periods beginning on and subsequent to the Partnership’s acquisition of the Partnership assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its estimated share of taxes from all forms of taxation, excluding income taxes imposed by the United States, that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership.

The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2018 or 2017.

With respect to assets acquired from Anadarko, the Partnership recorded Anadarko’s historic deferred income taxes for the periods prior to the Partnership’s ownership of the assets. For periods on and subsequent to the Partnership’s acquisition, the Partnership is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the assets acquired from Anadarko.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Net income (loss) per common unit. The Partnership applies the two-class method in determining net income (loss) per common unit applicable to MLPs having multiple classes of securities including common units, Class C units, general partner units and IDRs. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Under the two-class method, net income (loss) per common unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for the allocation of undistributed earnings to the general partner, limited partners and IDR holders and the circumstances in which such an allocation should be made. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes to its unitholders an amount of cash equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period or any other economic or practical limitation on the ability to make a full distribution of all of the net income for the period. See Note 5.

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Partnership adopted this ASU using a retrospective approach on January 1, 2018, with no impact to the consolidated financial statements.

Revenue from contracts with customers (Topic 606). The Partnership adopted Topic 606 on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The cumulative effect adjustment that was recognized in the opening balance of equity and partners’ capital was a decrease of $43.8 million. The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition (Topic 605) (“Topic 605”).

Effective January 1, 2018, the Partnership changed its accounting policy for revenue recognition as detailed below:

•

Fee-based gathering / processing. Under Topic 605, fee revenues were recognized based on the rate in effect for the month of service, even when certain fees were charged on an upfront or limited-term basis. In addition, deficiency fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, (i) revenues continue to be recognized based on the rate in effect when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation, (ii) deficiency fees are estimated and recognized during the performance period as the services are performed for the customer’s delivered volumes, and (iii) timing differences between Service revenues – fee based recognized and amounts billed to customers are recognized as contract assets or contract liabilities, as appropriate, which results in a change in the timing of revenue and changes to net income as a result of the revenue contract’s consideration provisions. In addition, under Topic 606, revenue associated with upfront or limited-term fees is recognized over the expected period of customer benefit, which is generally the life of the related properties. These revenues also include revenues earned for marketing services performed on behalf of the Partnership’s customers, and the expense associated with these marketing activities is recognized in cost of product expense, resulting in no impact to Operating income (loss).

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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

•

Cost of service rate adjustments. Under Topic 605, revenue was recognized based on the amounts billed to customers each period as Service revenues – fee based. Under Topic 606, fixed minimum volume commitment demand fees and variable fees that are also billed on these minimum volumes are recognized as Service revenues – fee based on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and, as a result, a cumulative catch-up revenue adjustment related to the services already provided under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate. Fees received on volumes in excess of the minimum volumes are recognized as Service revenues – fee based as service is provided to the customer based on the billing rate in effect for the performance period. This revenue recognition timing does not affect billings to customers, and differences between amounts billed and revenue recognized are recorded as contract assets or liabilities, as appropriate.

•

Aid in construction. Under Topic 605, aid in construction reimbursements were reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Under Topic 606, reimbursement of capital costs received from customers is reflected as a contract liability (deferred revenue) upon receipt. The contract liability is amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

•

Percent-of-proceeds gathering / processing. Under Topic 605, the Partnership recognized cost of product expense when the product was purchased from a producer to whom it provides services, and the Partnership recognized revenue when the product was sold to Anadarko or a third party. Under Topic 606, in some instances, where all or a percentage of the proceeds from the sale must be returned to the producer, the net margin from the purchase and sale transactions is presented net within Service revenues – product based because the Partnership is acting as the producer’s agent in the product sale.

•

Noncash consideration - keep-whole and percent-of-product agreements. Under Topic 605, the Partnership recognized revenues only upon the sale of the related products. Under Topic 606, (i) Service revenues – product based is recognized for the products received as noncash consideration in exchange for the services provided, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas cost, and (ii) product sales revenue is recognized, along with cost of product expense related to the sale, when the product is sold to Anadarko or a third party. When the product is sold to Anadarko, Anadarko is acting as the Partnership’s agent in the product sale and the Partnership recognizes revenue, along with cost of product expense related to the sale, based on the Anadarko sales price to the third party, resulting in no impact to Operating income (loss).

•

Wellhead purchase / sale incorporated into gathering / processing. Under Topic 605, the natural gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenues. Under Topic 606, the fees charged to the producer under this contract type are recognized as adjustments to the amount recognized in cost of product expense instead of revenues when such fees relate to services performed after control of the product transfers to the Partnership.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The following tables summarize the impact of adopting Topic 606 on the impacted line items within the consolidated statement of operations and the consolidated balance sheet. The differences between revenue as reported following Topic 606 and revenue as it would have been reported under Topic 605 are due to the changes described above.



	Year Ended December 31, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Revenues
Service revenues – fee based	$	1,905,728	$	1,751,242	$	154,486
Service revenues – product based	88,785		—		88,785
Product sales	303,020		1,405,898		(1,102,878		)
Expenses
Cost of product	415,505		1,338,100		(922,595		)
Operation and maintenance	480,861		480,668		193
Depreciation and amortization	389,164		386,179		2,985
Impairments	230,584		230,539		45
Income tax expense (benefit)	58,934		58,804		130
Net income attributable to noncontrolling interest	8,609		8,541		68
Net income (loss) attributable to Western Gas Partners, LP	627,917		568,350		59,567



	December 31, 2018
thousands	As Reported		Without Adoption of Topic 606		Effect of Change Increase / (Decrease)
Assets
Other current assets	$	26,181	$	20,782	$	5,399
Net property, plant and equipment	8,410,353		8,291,554		118,799
Other assets	67,194		24,972		42,222
Liabilities
Accrued liabilities	127,874		121,967		5,907
Deferred income taxes	280,017		254,939		25,078
Other liabilities	132,130		2,741		129,389
Equity and partners’ capital
Total equity and partners’ capital	4,919,597		4,913,551		6,046

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Accounting standards adopted in 2019. ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. This standard is effective for periods beginning after December 15, 2018, and in the first quarter of 2019, the Partnership fully adopted this standard using the modified retrospective method applied to all leases that existed on January 1, 2019. The Partnership made certain elections allowing the Partnership not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements and not to recognize ROU assets or lease liabilities for short-term leases. Upon adoption, the Partnership recognized approximately $10.0 million of ROU assets and corresponding lease liabilities on the consolidated balance sheet. The adoption of this ASU did not have a material impact on the consolidated statement of operations or the consolidated statement of cash flows. The Partnership has implemented the necessary changes to its business processes, systems and controls to support accounting and disclosure requirements under this ASU.

2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes the Partnership’s revenue from contracts with customers:



thousands	Year Ended December 31, 2018
Revenue from customers
Service revenues – fee based	$	1,905,728
Service revenues – product based	88,785
Product sales	310,895
Total revenue from customers	2,305,408
Revenue from other than customers
Net gains (losses) on commodity price swap agreements	(7,875		)
Other	2,125
Total revenues and other	$	2,299,658

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $214.3 million and $244.9 million as of December 31, 2018 and 2017, respectively.

Contract assets primarily relate to accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed and revenue accrued but not yet billed under cost of service contracts with fixed and variable fees. The following table summarizes the current period activity related to contract assets from contracts with customers:



thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	5,950
Amounts transferred to Accounts receivable, net from contract assets recognized in the adoption effect	(4,952		)
Additional estimated revenues recognized	30,519
Cumulative catch up adjustment for change in estimated consideration due to cost of service rate updates	16,104
Balance at December 31, 2018	$	47,621

Contract assets at December 31, 2018
Other current assets	$	5,399
Other assets	42,222
Total contract assets from contracts with customers	$	47,621

Contract liabilities primarily relate to (i) fees that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of customer benefit, (ii) fixed and variable fees under cost of service contracts that are received from customers for which revenue recognition is deferred and (iii) aid in construction payments received from customers that must be recognized over the expected period of customer benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:



thousands
Balance at December 31, 2017	$	—
Cumulative effect of adopting Topic 606	120,309
Cash received or receivable, excluding revenues recognized during the period	55,786
Assets received from customer	12,933
Revenues recognized during the period that were included in the adoption effect ⁽¹⁾	(21,556		)
Cumulative catch up adjustment for change in estimated consideration due to cost of service rate updates	(21,848		)
Balance at December 31, 2018	$	145,624

Contract liabilities at December 31, 2018
Accrued liabilities	$	16,235
Other liabilities	129,389
Total contract liabilities from contracts with customers	$	145,624


⁽¹⁾	Includes $(7.5) million from a performance obligation satisfied in a previous period related to the arbitration against SWEPI LP (see Note 14).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)

Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that are unsatisfied (or partially unsatisfied) as of December 31, 2018, are reflected in the following table. The Partnership applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a portion of expected future revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and, in some cases, variable commodity prices for those volumes.



thousands
2019	$	674,609
2020	847,045
2021	894,706
2022	947,310
2023	913,099
Thereafter	4,565,428
Total	$	8,842,197

3. ACQUISITIONS AND DIVESTITURES

AMA acquisition. In February 2019, the Partnership acquired the following assets from Anadarko (see Note 15), which are collectively referred to as the Anadarko Midstream Assets (“AMA”):


•	Wattenberg processing plant. The Wattenberg processing plant consists of a cryogenic train (with capacity of 190 million cubic feet per day (“MMcf/d”)) and a refrigeration train (with capacity of 100 MMcf/d) located in Adams County, Colorado, now part of the DJ Basin complex.


•	Wamsutter pipeline. The Wamsutter pipeline is a crude oil gathering pipeline located in Sweetwater County, Wyoming and delivers crude oil into Andeavor’s Wamsutter Pipeline System.

•

DJ Basin oil system. The DJ Basin oil system consists of (i) a crude oil gathering system, (ii) a centralized oil stabilization facility (“COSF”), which commenced operation in 2015, and (iii) a 12-mile crude oil pipeline, located in Weld County, Colorado. The COSF consists of Trains I through VI with total capacity of 155 thousand barrels per day (“MBbls/d”) and two storage tanks with total capacity of 500,000 barrels. Train VI, with capacity of 30 MBbls/d, commenced operation in 2018. The pipeline connects the COSF to Tampa Rail.

•

DBM oil system. The DBM oil system consists of (i) a crude oil gathering system, (ii) three central production facilities (“CPFs”), which include ten processing trains with total capacity of 75 MBbls/d, (iii) three storage tanks with total capacity of 30,000 barrels, (iv) a 14-mile crude oil pipeline, and (v) two regional oil treating facilities (“ROTFs”), which include four trains with total capacity of 120 MBbls/d, located in Reeves and Loving Counties, Texas. The ROTFs commenced operation in 2018. The pipeline transports crude oil from the DBM oil system and one third-party CPF into Plains All American Pipeline.

•

APC water systems. The APC water systems consist of one produced-water disposal system (with capacity of 30 MBbls/d), which commenced operation in 2017. Four additional produced-water disposal systems commenced operation in 2018, increasing the total capacity to 565 MBbls/d. The APC water systems are located in Reeves, Loving, Winkler and Ward Counties, Texas, which are now part of the DBM water systems.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. ACQUISITIONS AND DIVESTITURES (CONTINUED)

•

A 20% interest in Saddlehorn. Saddlehorn owns (i) a 600-mile crude oil and condensate pipeline (excluding pipeline capacity leased by Saddlehorn) that originates in Laramie County, Wyoming and terminates in Cushing, Oklahoma, and (ii) four storage tanks with total capacity of 300,000 barrels. The Saddlehorn interest is accounted for under the equity method. The pipeline commenced operation in 2016 and is operated by a third party.


•	A 15% interest in Panola. Panola owns a 248-mile NGLs pipeline that originates in Panola County, Texas and terminates in Mont Belvieu, Texas. The Panola interest is accounted for under the equity method and is operated by a third party.


•	A 50% interest in Mi Vida. Mi Vida owns a cryogenic gas processing plant (with capacity of 200 MMcf/d) located in Ward County, Texas. The interest in Mi Vida is accounted for under the equity method. The processing plant commenced operation in 2015 and is operated by a third party.

•

A 50% interest in Ranch Westex. Ranch Westex owns a processing plant consisting of a cryogenic train (with capacity of 100 MMcf/d) and a refrigeration train (with capacity of 25 MMcf/d), located in Ward County, Texas. In 2017, an additional interest in Ranch Westex was purchased from a third party for a net investment of $22.5 million, increasing the ownership from 33% to 50%. The interest in Ranch Westex is accounted for under the equity method and the processing plant is operated by a third party.

Because the acquisition of AMA was a transfer of net assets between entities under common control, the Partnership’s historical financial statements previously filed with the SEC have been recast in this Form 8-K to include the results attributable to AMA as if the Partnership owned AMA for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of AMA have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned AMA during the periods reported.

The following table presents the impact of AMA on Revenues and other, Equity income, net – affiliates and Net income (loss) as presented in the Partnership’s historical consolidated statements of operations:



	Year Ended December 31, 2018
thousands	Partnership Historical		AMA		Eliminations			Combined
Revenues and other	$	1,990,276	$	343,499	$	(34,117	)	$	2,299,658
Equity income, net – affiliates	153,024		42,445		—			195,469
Net income (loss)	454,384		182,142		—			636,526



	Year Ended December 31, 2017
thousands	Partnership Historical		AMA		Eliminations			Combined
Revenues and other	$	2,248,356	$	192,853	$	(11,595	)	$	2,429,614
Equity income, net – affiliates	85,194		29,947		—			115,141
Net income (loss)	578,218		164,183		—			742,401

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. ACQUISITIONS AND DIVESTITURES (CONTINUED)



	Year Ended December 31, 2016
thousands	Partnership Historical		AMA		Eliminations			Combined
Revenues and other	$	1,804,270	$	138,269	$	(1,209	)	$	1,941,330
Equity income, net – affiliates	78,717		22,975		—			101,692
Net income (loss)	602,294		61,306		—			663,600

Red Bluff Express acquisition. In January 2019, the Partnership acquired a 30% interest in Red Bluff Express Pipeline, LLC (“Red Bluff Express”), which owns a natural gas pipeline operated by a third party (the “Red Bluff Express pipeline”) connecting Reeves County and Loving County, Texas to the WAHA hub in Pecos County, Texas. The Partnership acquired its 30% interest from a third party via an initial net investment of $92.5 million, which represented its share of costs incurred up to the date of acquisition. The initial investment was funded with cash on hand and the interest in Red Bluff Express will be accounted for under the equity method.

Whitethorn LLC acquisition. In June 2018, the Partnership acquired a 20% interest in Whitethorn LLC, which owns a crude oil and condensate pipeline that originates in Midland, Texas and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with its investment in Whitethorn, the Partnership will share proportionally in the commercial activities. The Partnership acquired its 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 10.

Cactus II acquisition. In June 2018, the Partnership acquired a 15% interest in Cactus II, which will own a crude oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline is under construction and is expected to become operational in late 2019. The Partnership acquired its 15% interest from a third party via an initial net investment of $12.1 million, which represented its share of costs incurred up to the date of acquisition. The initial investment was funded with cash on hand and the interest in Cactus II is accounted for under the equity method. See Note 10.

Property exchange. In March 2017, the Partnership acquired an additional 50% interest in the Delaware Basin JV Gathering LLC (“DBJV”) system (the “Additional DBJV System Interest”) from a third party in exchange for (a) the Partnership’s 33.75% non-operated interest in two natural gas gathering systems located in northern Pennsylvania (the “Non-Operated Marcellus Interest”), commonly referred to as the Liberty and Rome systems, and (b) $155.0 million of cash consideration (collectively, the “Property Exchange”). The Partnership previously held a 50% interest in, and operated, the DBJV system.

The Property Exchange was reflected as a nonmonetary transaction whereby the acquired Additional DBJV System Interest was recorded at the fair value of the divested Non-Operated Marcellus Interest plus the $155.0 million of cash consideration. The Property Exchange resulted in a net gain of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributable to the Property Exchange were included in the consolidated statements of operations beginning on the acquisition date in the first quarter of 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. ACQUISITIONS AND DIVESTITURES (CONTINUED)

DBJV acquisition - Deferred purchase price obligation - Anadarko. Prior to the Partnership’s agreement with Anadarko to settle its deferred purchase price obligation early, the consideration that would have been paid by the Partnership for the March 2015 acquisition of DBJV from Anadarko consisted of a cash payment to Anadarko due on March 31, 2020. In May 2017, the Partnership reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.

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



	Deferred purchase price obligation - Anadarko			Estimated future payment obligation ⁽¹⁾
Balance at December 31, 2015	$	188,674		$	282,807
Accretion revision ⁽²⁾	(7,747		)
Revision to Deferred purchase price obligation – Anadarko ⁽³⁾	(139,487		)
Balance at December 31, 2016	41,440			56,455
Accretion expense ⁽⁴⁾	71
Revision to Deferred purchase price obligation – Anadarko⁽³⁾	(4,165		)
Settlement of the Deferred purchase price obligation – Anadarko	(37,346		)
Balance at December 31, 2017	$	—		$	—


⁽¹⁾	Calculated using Level 3 inputs.


⁽²⁾	Financing-related accretion revisions were recorded in Interest expense in the consolidated statements of operations.


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


⁽⁴⁾	Accretion expense was recorded as a charge to Interest expense in the consolidated statements of operations.

Springfield acquisition. In March 2016, the Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system. The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility originally entered into in February 2014, (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 5 for further information regarding the Series A Preferred units.

Newcastle system divestiture. In December 2018, the Newcastle system, located in Northeast Wyoming, was sold to a third party for $3.2 million, resulting in a net gain on sale of $0.6 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. The Partnership previously held a 50% interest in, and operated, the Newcastle system.

Helper and Clawson systems divestiture. In June 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of $16.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

Hugoton system divestiture. In October 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party, resulting in a net loss on sale of $12.0 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. The Partnership allocated $1.6 million in goodwill to this divestiture.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors declared the following cash distributions to the Partnership’s common and general partner unitholders for the periods presented:



thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
2016
March 31	$	0.815	$	158,905	May 2016
June 30	0.830		162,827		August 2016
September 30	0.845		166,742		November 2016
December 31	0.860		170,657		February 2017
2017
March 31	$	0.875	$	188,753	May 2017
June 30	0.890		207,491		August 2017
September 30	0.905		212,038		November 2017
December 31	0.920		216,586		February 2018
2018
March 31	$	0.935	$	221,133	May 2018
June 30	0.950		225,691		August 2018
September 30	0.965		230,239		November 2018
December 31 ⁽¹⁾	0.980		234,787		February 2019

⁽¹⁾

The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2018 of $0.980 per unit, or $234.8 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution was paid on February 13, 2019, to unitholders of record at the close of business on February 1, 2019.

Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments or other agreements; or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. Working capital borrowings may only be those that, at the time of such borrowings, were intended to be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)

Class C unit distributions. The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the earlier of (i) the consummation of the Merger (see Note 15) or (ii) March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date, and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until such event. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a 6% discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value. See Note 5 for further discussion of the Class C units.

Series A Preferred unit distributions. As further described in Note 5, the Partnership issued Series A Preferred units representing limited partner interests in the Partnership to private investors in 2016. The Series A Preferred unitholders received quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis. Such converted common units were entitled to distributions made to common unitholders with respect to the quarter during which the applicable conversion occurred and did not include a prorated Series A Preferred unit distribution. The following table summarizes the Series A Preferred unitholders’ cash distributions for the periods presented:



thousands except per-unit amounts Quarters Ended	Total Quarterly Distribution per Unit		Total Quarterly Cash Distribution		Date of Distribution
2016
March 31 ⁽¹⁾	$	0.68	$	1,887	May 2016
June 30 ⁽²⁾	0.68		14,082		August 2016
September 30	0.68		14,907		November 2016
December 31	0.68		14,908		February 2017
2017
March 31	$	0.68	$	7,453	May 2017


⁽¹⁾	Quarterly per unit distribution prorated for the 18-day period during which 14,030,611 Series A Preferred units were outstanding during the first quarter of 2016.


⁽²⁾	Full quarterly per unit distribution on 14,030,611 Series A Preferred units and quarterly per unit distribution prorated for the 77-day period during which 7,892,220 Series A Preferred units were outstanding during the second quarter of 2016.

General partner interest and incentive distribution rights. As of December 31, 2018, the general partner was entitled to 1.5% of all quarterly distributions that the Partnership makes prior to its liquidation and, as the holder of the incentive distribution rights (“IDRs”), was entitled to incentive distributions at the maximum distribution sharing percentage of 48.0% for all periods presented, after the minimum quarterly distribution and the target distribution levels had been achieved. The maximum distribution sharing percentage of 49.5% does not include any distributions that the general partner may receive on common units that it may acquire.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. In July 2017, the Partnership filed a registration statement with the SEC for the issuance of up to an aggregate of $500.0 million of common units pursuant to a new continuous offering program that has not yet been initiated (the “$500.0 million COP”). Upon the consummation of the Merger (see Note 15), the Partnership will terminate the registration statement relating to the $500.0 million COP and, therefore, common units will no longer be available for issuance thereunder.

Class C units. In November 2014, the Partnership issued 10,913,853 Class C units to APC Midstream Holdings, LLC (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund the acquisition of DBM.

When issued, the Class C units were scheduled to convert into common units on a one-for-one basis on December 31, 2017, and in February 2017, Anadarko elected to extend the conversion date of the Class C units to March 1, 2020. All outstanding Class C units will convert into the Partnership’s common units on a one-for-one basis immediately prior to the closing of the Merger, if consummated. If the Merger is not consummated, the conversion will occur on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date (see Note 15).

The Class C units were issued at a discount to the then-current market price of the common units into which they are convertible. This discount, totaling $34.8 million, represents a beneficial conversion feature, and at issuance, was reflected as an increase in common unitholders’ capital and a decrease in Class C unitholder capital to reflect the fair value of the Class C units at issuance. The beneficial conversion feature is considered a non-cash distribution that is recognized from the date of issuance through the date of conversion, resulting in an increase in Class C unitholder capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature is amortized assuming the extended conversion date of March 1, 2020, using the effective yield method. The impact of the beneficial conversion feature amortization is included in the calculation of earnings per unit.

Series A Preferred units. In 2016, the Partnership issued 21,922,831 Series A Preferred units to private investors, generating proceeds of $686.9 million (net of fees and expenses, but including a 2.0% transaction fee paid to the private investors). The Series A Preferred units were issued at a discount to the then-current market price of the common units into which they were convertible. This discount, totaling $93.4 million, represented a beneficial conversion feature, and at issuance, was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the Series A Preferred units on the date of issuance. The beneficial conversion feature was considered a non-cash distribution that was recognized from the date of issuance through the date of conversion, resulting in an increase in Series A Preferred unitholders’ capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature was amortized using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit. For the year ended December 31, 2017, the amortization for the beneficial conversion feature of the Series A Preferred units was $62.3 million.

Pursuant to an agreement between the Partnership and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and all remaining Series A Preferred units converted into common units on a one-for-one basis on May 2, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Partnership interests. As of December 31, 2018, the Partnership’s common units were listed on the New York Stock Exchange under the symbol “WES.”

The following table summarizes the Partnership’s units issued during the years ended December 31, 2018 and 2017:



	Common Units	Class C Units	Series A Preferred Units		General Partner Units	Total
Balance at December 31, 2016	130,671,970	12,358,123	21,922,831		2,583,068	167,535,992
PIK Class C units	—	885,760	—		—	885,760
Conversion of Series A Preferred units	21,922,831	—	(21,922,831	)	—	—
Long-Term Incentive Plan award vestings	7,304	—	—		—	7,304
Balance at December 31, 2017	152,602,105	13,243,883	—		2,583,068	168,429,056
PIK Class C units	—	1,128,782	—		—	1,128,782
Long-Term Incentive Plan award vestings	7,180	—	—		—	7,180
Balance at December 31, 2018	152,609,285	14,372,665	—		2,583,068	169,565,018

Holdings of Partnership equity. As of December 31, 2018, WGP held 50,132,046 common units, representing a 29.6% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,583,068 general partner units, representing a 1.5% general partner interest in the Partnership, and 100% of the IDRs. As of December 31, 2018, (i) other subsidiaries of Anadarko collectively held 2,011,380 common units and 14,372,665 Class C units, representing an aggregate 9.7% limited partner interest in the Partnership and (ii) the public held 100,465,859 common units, representing the remaining 59.2% limited partner interest in the Partnership.

Net income (loss) per common unit. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the unitholders for purposes of calculating net income (loss) per common unit. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of acquisition of the Partnership assets is allocated as follows:

General partner. The general partner’s allocation is equal to cash distributions plus its portion of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner consistent with actual cash distributions and capital account allocations, including incentive distributions. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner in accordance with its weighted-average ownership percentage during each period.

Series A Preferred unitholders. The Series A Preferred units were not considered a participating security as they only had distribution rights up to the specified per-unit quarterly distribution and had no rights to the Partnership’s undistributed earnings and losses. As such, the Series A Preferred unitholders’ allocation was equal to their cash distribution plus the amortization of the Series A Preferred units beneficial conversion feature (see Series A Preferred units above).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Common and Class C unitholders. The Class C units are considered a participating security because they participate in distributions with common units according to a predetermined formula (see Note 4). The common and Class C unitholders’ allocation is equal to their cash distributions plus their respective allocations of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the common and Class C unitholders consistent with actual cash distributions and capital account allocations. Undistributed earnings or undistributed losses are then allocated to the common and Class C unitholders in accordance with their respective weighted-average ownership percentages during each period. The common unitholder allocation also includes the impact of the amortization of the Series A Preferred units and Class C units beneficial conversion features. The Class C unitholder allocation is similarly impacted by the amortization of the Class C units beneficial conversion feature (see Class C units above).

Calculation of net income (loss) per unit. Basic net income (loss) per common unit is calculated by dividing the net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest in net income (loss) assuming, prior to the actual conversion, conversion of the Series A Preferred units into common units, and (ii) the net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming, prior to the actual conversion, conversion of the Series A Preferred units.

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



	Year Ended December 31,
thousands except per-unit amounts	2018			2017			2016
Net income (loss) attributable to Western Gas Partners, LP	$	627,917		$	731,666		$	652,637
Pre-acquisition net (income) loss allocated to Anadarko	(182,142		)	(164,183		)	(72,632		)
Series A Preferred units interest in net (income) loss ⁽¹⁾	—			(42,373		)	(76,893		)
General partner interest in net (income) loss	(346,538		)	(303,835		)	(236,561		)
Common and Class C limited partners’ interest in net income (loss)	$	99,237		$	221,275		$	266,551
Net income (loss) allocable to common units ⁽¹⁾	$	84,334		$	192,066		$	226,611
Net income (loss) allocable to Class C units ⁽¹⁾	14,903			29,209			39,940
Common and Class C limited partners’ interest in net income (loss)	$	99,237		$	221,275		$	266,551
Net income (loss) per unit
Common units – basic and diluted ⁽²⁾	$	0.55		$	1.30		$	1.74
Weighted-average units outstanding
Common units – basic and diluted	152,606			147,194			130,253
Excluded due to anti-dilutive effect:
Class C units⁽²⁾	13,795			12,776			11,945
Series A Preferred units assuming conversion to common units ⁽²⁾	—			5,406			16,860


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

⁽²⁾

The impact of Class C units would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the years ended December 31, 2017 and 2016. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. TRANSACTIONS WITH AFFILIATES

Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of natural gas, condensate and NGLs to Anadarko. Anadarko sells such natural gas, condensate and NGLs as an agent on behalf of either the Partnership or the Partnership’s customers. When such sales are on the Partnership’s customers’ behalf, the Partnership recognizes associated service revenues and cost of product expense. When such sales are on the Partnership’s behalf, the Partnership recognizes product sales revenues based on the Anadarko sales price to the third party and cost of product expense associated with these sales activities.

In addition, the Partnership purchases natural gas, condensate and NGLs from an affiliate of Anadarko pursuant to gas purchase agreements. Operation and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. A portion of the Partnership’s general and administrative expenses is paid by Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the Partnership’s omnibus agreement. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues.

Merger transactions. As discussed in more detail in Note 15, the Partnership has entered into the Merger Agreement with WGP, Anadarko and certain of their affiliates.

Cash management. Anadarko operates a cash management system whereby excess cash from most of its subsidiaries’ separate bank accounts is generally swept to centralized accounts. Prior to the Partnership’s acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. The outstanding affiliate balances were entirely settled through an adjustment to net investment by Anadarko in connection with the acquisition of the Partnership assets. Subsequent to the acquisition of Partnership assets from Anadarko, transactions related to such assets are cash-settled directly with third parties and with Anadarko affiliates. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

Note receivable - Anadarko. Concurrently with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was $279.6 million and $325.2 million at December 31, 2018 and 2017, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.

APCWH Note Payable. In June 2017, APC Water Holdings 1, LLC (“APCWH”) entered into an eight-year note payable agreement with Anadarko. See Note 13 and Note 15.

Commodity price swap agreements. The Partnership had commodity price swap agreements with Anadarko to mitigate exposure to the commodity price risk inherent in its percent-of-proceeds, percent-of-product and keep-whole contracts. Notional volumes for each of the commodity price swap agreements were not specifically defined. Instead, the commodity price swap agreements applied to the actual volume of natural gas, condensate and NGLs purchased and sold. The commodity price swap agreements did not satisfy the definition of a derivative financial instrument and, therefore, were not required to be measured at fair value. The Partnership’s net gains (losses) on commodity price swap agreements were $(7.9) million, $0.6 million and $28.5 million for the years ended December 31, 2018, 2017 and 2016, respectively, and are reported in the consolidated statements of operations as affiliate Product sales in 2018 and as affiliate Product sales and Cost of product in 2017 and 2016 (see Note 1). These commodity price swap agreements expired without renewal on December 31, 2018.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Swap agreements - DJ Basin complex, Hugoton system and MGR assets. On December 8, 2015, the commodity price swap agreements with Anadarko for the DJ Basin complex and Hugoton system were extended from January 1, 2016, through December 31, 2016. On December 1, 2016, the commodity price swap agreements with Anadarko for the DJ Basin complex and the MGR assets were extended from January 1, 2017 through December 31, 2017. On December 20, 2017, the commodity price swap agreements with Anadarko for the DJ Basin complex and the MGR assets were extended from January 1, 2018 through December 31, 2018.

Revenues or costs attributable to volumes sold and purchased during 2016, 2017 and 2018 for the DJ Basin complex, MGR assets and Hugoton system are recognized in the consolidated statements of operations at the applicable market price in the tables below. The Partnership also records a capital contribution from Anadarko in its consolidated statements of equity and partners’ capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price in the tables below, minus (ii) the amount by which the swap price for product purchases exceeds the applicable market price in the tables below. For the years ended December 31, 2018, 2017 and 2016, the capital contributions from Anadarko were $51.6 million, $58.6 million and $45.8 million, respectively. The tables below summarize the swap prices compared to the forward market prices:



	DJ Basin Complex
per barrel except natural gas	2016 - 2018 Swap Prices		2016 Market Prices⁽¹⁾		2017 Market Prices ⁽¹⁾		2018 Market Prices ⁽¹⁾
Ethane	$	18.41	$	0.60	$	5.09	$	5.41
Propane	47.08		10.98		18.85		28.72
Isobutane	62.09		17.23		26.83		32.92
Normal butane	54.62		16.86		26.20		32.71
Natural gasoline	72.88		26.15		41.84		48.04
Condensate	76.47		34.65		45.40		49.36
Natural gas (per MMBtu)	5.96		2.11		3.05		2.21



	Hugoton System ⁽²⁾
per barrel except natural gas	2016 Swap Prices		2016 Market Prices ⁽¹⁾
Condensate	$	78.61	$	18.81
Natural gas (per MMBtu)	5.50		2.12



	MGR Assets
per barrel except natural gas	2016 - 2018 Swap Prices		2017 Market Prices ⁽¹⁾		2018 Market Prices ⁽¹⁾
Ethane	$	23.11	$	4.08	$	2.52
Propane	52.90		19.24		25.83
Isobutane	73.89		25.79		30.03
Normal butane	64.93		25.16		29.82
Natural gasoline	81.68		45.01		47.25
Condensate	81.68		53.55		56.76
Natural gas (per MMBtu)	4.87		3.05		2.21


⁽¹⁾	Represents the New York Mercantile Exchange forward strip price as of December 8, 2015, December 1, 2016, and December 20, 2017, for the 2016 Market Prices, 2017 Market Prices and 2018 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.


⁽²⁾	The Hugoton system was sold in October 2016. See Note 3.

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6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Gathering and processing agreements. The Partnership has significant gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The combination of the DBM complex and DBJV and Haley systems, effective January 1, 2018, into a single complex now referred to as the “West Texas complex” resulted in natural gas throughput previously reported as “Gathering, treating and transportation” now being reported as “Processing.” The Partnership’s natural gas gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 7%, 34% and 37% for the years ended December 31, 2018, 2017 and 2016, respectively. The Partnership’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 40%, 41% and 53% for the years ended December 31, 2018, 2017 and 2016, respectively. The Partnership’s crude oil, NGLs and produced water gathering, treating, transportation and disposal throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 85%, 81% and 86% for the years ended December 31, 2018, 2017 and 2016, respectively.

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

Acquisitions from Anadarko. On March 14, 2016, the Partnership acquired Springfield from Anadarko (see Note 3).

Omnibus agreement. Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing and midstream administration. Anadarko, in accordance with the partnership and omnibus agreements, determines, in its reasonable discretion, amounts to be reimbursed by the Partnership in exchange for services provided under the omnibus agreement. See Summary of affiliate transactions below.

The following table summarizes the amounts the Partnership reimbursed to Anadarko:



	Year Ended December 31,
thousands	2018		2017		2016
General and administrative expenses	$	35,077	$	31,733	$	29,360
Public company expenses	15,409		9,379		8,410
Total reimbursement	$	50,486	$	41,112	$	37,770

Services and secondment agreement. Pursuant to the services and secondment agreement, specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement expired in May 2018, but was extended for a twelve-month period and will continue to automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination before the applicable twelve-month period expires. The consolidated financial statements include costs allocated by Anadarko for expenses incurred under the services and secondment agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership assets.

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6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Tax sharing agreement. Pursuant to a tax sharing agreement, the Partnership reimburses Anadarko for its estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States. Taxes for which the Partnership reimburses Anadarko include state taxes attributable to the Partnership’s income, which are directly borne by Anadarko through its filing of a combined or consolidated tax return with respect to periods beginning on and subsequent to the acquisition of the Partnership assets from Anadarko. Anadarko may use its own tax attributes to reduce or eliminate the tax liability of its combined or consolidated group, which may include the Partnership as a member. However, under this circumstance, the Partnership nevertheless is required to reimburse Anadarko for its allocable share of taxes that would have been owed had tax attributes not been available to Anadarko.

Allocation of costs. For periods prior to the Partnership’s acquisition of the Partnership assets, the consolidated financial statements include costs allocated by Anadarko in the form of a management services fee. This management services fee was allocated to the Partnership based on its proportionate share of Anadarko’s revenues and expenses or other contractual arrangements. Management believes these allocation methodologies are reasonable.

The employees supporting the Partnership’s operations are employees of Anadarko. Anadarko allocates costs to the Partnership for its share of personnel costs, including costs associated with equity-based compensation plans, non-contributory defined benefit pension and postretirement plans and defined contribution savings plans pursuant to the omnibus agreement and services and secondment agreement. In general, the Partnership’s reimbursement to Anadarko under the omnibus agreement or services and secondment agreement is either (i) on an actual basis for direct expenses Anadarko and the general partner incur on behalf of the Partnership, or (ii) based on an allocation of salaries and related employee benefits between the Partnership, the general partner and Anadarko based on estimates of time spent on each entity’s business and affairs. Most general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, and do not include any mark-up or subsidy component. With respect to allocated costs, management believes the allocation method employed by Anadarko is reasonable. Although it is not practicable to determine what the amount of these direct and allocated costs would be if the Partnership were to directly obtain these services, management believes that aggregate costs charged to the Partnership by Anadarko are reasonable.

WES LTIP. The general partner awards phantom units under the WES LTIP primarily to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized over the vesting period and was $0.4 million for each of the years ended December 31, 2018, 2017 and 2016. As of December 31, 2018, there was $0.1 million of unrecognized compensation expense attributable to the outstanding awards under the WES LTIP, all of which will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 0.4 years.

The following table summarizes WES LTIP award activity for the years ended December 31, 2018, 2017 and 2016:



	2018				2017				2016
	Weighted-Average Grant-Date Fair Value		Units		Weighted-Average Grant-Date Fair Value		Units		Weighted-Average Grant-Date Fair Value		Units
Phantom units outstanding at beginning of year	$	55.73	7,180		$	49.30	7,304		$	68.78	5,477
Vested	55.73		(7,180	)	49.30		(7,304	)	68.78		(5,477	)
Granted	49.88		8,020		55.73		7,180		49.30		7,304
Phantom units outstanding at end of year	49.88		8,020		55.73		7,180		49.30		7,304

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6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

WGP LTIP and Anadarko Incentive Plan. General and administrative expenses included $6.6 million, $4.6 million and $5.2 million for the years ended December 31, 2018, 2017 and 2016, respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the WGP LTIP and Anadarko Incentive Plan. Of these amounts, $5.7 million, $4.6 million and $4.2 million are reflected as contributions to partners’ capital in the Partnership’s consolidated statements of equity and partners’ capital for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, the Partnership estimated that $12.5 million of estimated unrecognized compensation expense attributable to the Anadarko Incentive Plan will be allocated to the Partnership over a weighted-average period of 2.0 years.

Affiliate asset contributions and distributions. The following table summarizes Anadarko’s contributions and distributions of other assets to the Partnership:



	Year Ended December 31,
	2018			2017			2016			2018		2017		2016
thousands	Purchases									Sales
Cash consideration	$	(254	)	$	(3,910	)	$	(3,965	)	$	—	$	—	$	623
Net carrying value	59,089			5,283			3,496			—		—		(605		)
Partners’ capital adjustment	$	58,835		$	1,373		$	(469	)	$	—	$	—	$	18

Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. For periods prior to January 1, 2018, the cash receipts resulting from such reimbursements were presented as “Contributions in aid of construction costs from affiliates” within the investing section of the consolidated statements of cash flows. As discussed in Recently adopted accounting standards in Note 1, upon adoption of Topic 606, affiliate reimbursements of capital costs are reflected as contract liabilities upon receipt, amortized to Service revenues – fee based over the expected period of customer benefit, and presented within the operating section of the consolidated statements of cash flows.

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6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes material affiliate transactions:



	Year ended December 31,
thousands	2018		2017			2016
Revenues and other ⁽¹⁾	$	1,353,711	$	1,539,105		$	1,358,918
Equity income, net – affiliates ⁽¹⁾	195,469		115,141			101,692
Cost of product ⁽¹⁾	168,535		74,560			75,983
Operation and maintenance ⁽²⁾	115,948		82,249			82,133
General and administrative ⁽³⁾	48,819		42,411			41,176
Operating expenses	333,302		199,220			199,292
Interest income ⁽⁴⁾	16,900		16,900			16,900
Interest expense ^{(5) (6)}	6,746		224			(7,747		)
APCWH Note Payable borrowings ⁽⁶⁾	321,780		98,813			—
Settlement of the Deferred purchase price obligation – Anadarko ⁽⁷⁾	—		(37,346		)	—
Proceeds from the issuance of common units, net of offering expenses ⁽⁸⁾	—		—			25,000
Distributions to unitholders ⁽⁹⁾	514,906		452,777			382,711
Above-market component of swap agreements with Anadarko	51,618		58,551			45,820


⁽¹⁾	Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.


⁽²⁾	Represents expenses incurred on and subsequent to the date of the acquisition of Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.

⁽³⁾

Represents general and administrative expense incurred on and subsequent to the date of the acquisition of Partnership assets, as well as a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plan within this Note 6) and amounts charged by Anadarko under the omnibus agreement.


⁽⁴⁾	Represents interest income recognized on the note receivable from Anadarko.


⁽⁵⁾	Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3 and Note 13).


⁽⁶⁾	Includes amounts related to the APCWH Note Payable (see Note 13 and Note 15).


⁽⁷⁾	Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).


⁽⁸⁾	Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 3).


⁽⁹⁾	Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented in the consolidated statements of operations.

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7. INCOME TAXES

The Partnership is not a taxable entity for U.S. federal income tax purposes. For all periods presented, income attributable to AMA was subject to federal and state income tax. Following the adoption of the U.S. Tax Cuts and Jobs Act signed into law on December 22, 2017, AMA recognized a one-time deferred tax benefit of $87.3 million due to the remeasurement of its U.S. deferred tax assets and liabilities based on the reduction of the corporate tax rate from 35% to 21%.

During 2018, the accounting for the income tax effects related to the adoption of the Tax Reform Legislation was completed before the end of the measurement period. No additional adjustments to the provisional amount recorded in 2017 were recognized. The federal tax benefit is included in the Deferred income taxes balance as presented on the consolidated balance sheet.

The components of the Partnership’s income tax expense (benefit) are as follows:



	Year Ended December 31,
thousands	2018			2017			2016
Current income tax expense (benefit)
Federal income tax expense (benefit)	$	(79,264	)	$	(9,207	)	$	(19,480	)
State income tax expense (benefit)	(850		)	2,422			1,257
Total current income tax expense (benefit)	(80,114		)	(6,785		)	(18,223		)
Deferred income tax expense (benefit)
Federal income tax expense (benefit)	133,044			(55,835		)	49,855
State income tax expense (benefit)	6,004			2,697			1,337
Total deferred income tax expense (benefit)	139,048			(53,138		)	51,192
Total income tax expense (benefit)	$	58,934		$	(59,923	)	$	32,969

Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows:



	Year Ended December 31,
thousands except percentages	2018			2017			2016
Income (loss) before income taxes	$	695,460		$	682,478		$	696,569
Statutory tax rate	—		%	—		%	—		%
Tax computed at statutory rate	$	—		$	—		$	—
Adjustments resulting from:
U.S. federal tax reform	—			(87,306		)	—
Federal taxes on income attributable to Partnership assets pre-acquisition	54,243			22,353			30,550
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)	1,745			164			326
Texas margin tax expense (benefit)	2,946			4,866			2,093
Income tax expense (benefit)	$	58,934		$	(59,923	)	$	32,969
Effective tax rate	8		%	(9		)%	5		%

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7. INCOME TAXES (CONTINUED)

The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows:



	December 31,
thousands	2018			2017
Depreciable property	$	(280,377	)	$	(139,902	)
Credit carryforwards	497			448
Other intangible assets	(299		)	(189		)
Other	162			8
Net long-term deferred income tax liabilities	$	(280,017	)	$	(139,635	)

Credit carryforwards, which are available for use on future income tax returns, consist of $0.5 million of state income tax credits that expire in 2026.

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8. PROPERTY, PLANT AND EQUIPMENT

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



		December 31,
thousands	Estimated Useful Life	2018		2017
Land	n/a	$	5,298	$	5,096
Gathering systems and processing complexes	3 to 49 years	10,441,574		7,851,458
Pipelines and equipment	6 to 45 years	172,497		137,644
Assets under construction	n/a	604,265		954,719
Other	3 to 40 years	35,139		30,701
Total property, plant and equipment		11,258,773		8,979,618
Less accumulated depreciation		2,848,420		2,213,718
Net property, plant and equipment		$	8,410,353	$	6,765,900

The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet suitable to be placed into productive service as of the respective balance sheet date.

Impairments. During the year ended December 31, 2018, the Partnership recognized impairments of $230.6 million, including impairments of $125.9 million at the Third Creek gathering system and $8.1 million at the Kitty Draw gathering system. These assets were impaired to their estimated salvage values of $1.8 million and zero, respectively, using the market approach and Level 3 fair value inputs, due to the shutdown of the systems. See Note 1 for further information. Also during 2018, the Partnership recognized impairments of $38.7 million and $34.6 million at the Hilight and MIGC systems, respectively. These assets were impaired to their estimated fair values of $4.9 million and $15.2 million, respectively, using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows. The remaining $23.3 million of impairments was primarily related to (i) a $10.9 million impairment at the GNB NGL pipeline, which was impaired to its estimated fair value of $10.0 million using the income approach and Level 3 fair value inputs, and (ii) a $5.6 million impairment related to an idle facility at the Chipeta complex, which was impaired to its estimated salvage value of $1.5 million using the market approach and Level 3 fair value inputs.

During the year ended December 31, 2017, the Partnership recognized impairments of $180.1 million, including an impairment of $158.8 million at the Granger complex, which was impaired to its estimated fair value of $48.5 million using the income approach and Level 3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. The remaining $21.3 million of impairments was primarily related to (i) an $8.2 million impairment due to the cancellation of a plant project at the Hilight system, (ii) a $3.7 million impairment at the Granger straddle plant, which was impaired to its estimated salvage value of $0.6 million using the income approach and Level 3 fair value inputs, (iii) a $3.1 million impairment of the Fort Union equity investment, (iv) a $2.0 million impairment of an idle facility in northeast Wyoming, which was impaired to its estimated salvage value of $0.4 million using the market approach and Level 3 fair value inputs, and (v) the cancellation of a pipeline project in West Texas.

During the year ended December 31, 2016, the Partnership recognized impairments of $17.8 million, including an impairment of $6.1 million at the Newcastle system, which was impaired to its estimated fair value of $3.1 million, using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows caused by the low commodity price environment. Also during 2016, the Partnership recognized impairments of $11.7 million, primarily related to the cancellation of projects at the DJ Basin complex and at the Springfield, DBJV and DBM oil systems and the abandonment of compressors at the MIGC system.

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9. GOODWILL AND INTANGIBLES

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the Partnership assets acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price paid to a third-party entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s allocated goodwill balance does not represent, and in some cases is significantly different from, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of such net assets on their respective acquisition dates.

Goodwill is evaluated for impairment annually (see Note 1). The Partnership’s annual qualitative goodwill impairment assessment as of October 1, 2018, indicated no impairment. Qualitative factors were also assessed in the fourth quarter of 2018 to review any changes in circumstances subsequent to the annual test, including changes in commodity prices. This assessment also indicated no impairment.

Other intangible assets. The intangible asset balance on the consolidated balance sheets includes the fair value, net of amortization, of (i) contracts assumed in connection with the Platte Valley and Wattenberg processing plant acquisitions in 2011, which are being amortized on a straight-line basis over 38 years, (ii) interconnect agreements at Chipeta entered into in November 2012, which are being amortized on a straight-line basis over 10 years, and (iii) contracts assumed by the Partnership in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years.

The Partnership assesses intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment in Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. No intangible asset impairment has been recognized in these consolidated financial statements.

The following table presents the gross carrying amount and accumulated amortization of other intangible assets:



	December 31,
thousands	2018			2017
Gross carrying amount	$	979,863		$	979,863
Accumulated amortization	(138,455		)	(107,676		)
Other intangible assets	$	841,408		$	872,187

Amortization expense for intangible assets was $30.8 million for the year ended December 31, 2018, and $30.7 million for each of the years ended December 31, 2017 and 2016. Intangible asset amortization recorded in each of the next five years is estimated to be $32.0 million for the years ended December 31, 2019 to December 31, 2022, and $31.7 million for the year ended December 31, 2023.

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10. EQUITY INVESTMENTS

The following tables present the activity in the Partnership’s equity investments for the years ended December 31, 2018 and 2017:



thousands	Balance at December 31, 2016		Impairment expense ⁽¹⁾			Acquisitions		Equity income, net		Contributions		Distributions			Distributions in excess of cumulative earnings ⁽²⁾			Balance at December 31, 2017
Fort Union	$	12,833	$	(3,110	)	$	—	$	3,821	$	—	$	(4,217	)	$	(2,297	)	$	7,030
White Cliffs	47,319		—			—		12,547		277		(11,965		)	(3,233		)	44,945
Rendezvous	46,739		—			—		1,144		—		(3,085		)	(2,270		)	42,528
Mont Belvieu JV	112,805		—			—		29,444		—		(29,482		)	(2,468		)	110,299
TEG	15,846		—			—		3,350		—		(3,317		)	—			15,879
TEP	189,194		—			—		17,387		107		(17,639		)	(10,074		)	178,975
FRP	169,472		—			—		17,501		—		(17,675		)	(2,743		)	166,555
Saddlehorn	107,420		—			—		10,001		2,454		(10,127		)	(521		)	109,227
Panola	24,546		—			—		2,230		46		(2,470		)	(727		)	23,625
Mi Vida	67,738		—			—		10,029		—		(9,161		)	(3,618		)	64,988
Ranch Westex	34,777		—			22,500		7,687		—		(7,955		)	(3,708		)	53,301
Total	$	828,689	$	(3,110	)	$	22,500	$	115,141	$	2,884	$	(117,093	)	$	(31,659	)	$	817,352



thousands	Balance at December 31, 2017		Acquisitions		Equity income, net			Contributions ⁽³⁾		Distributions			Distributions in excess of cumulative earnings ⁽²⁾			Balance at December 31, 2018
Fort Union	$	7,030	$	—	$	(1,433	)	$	—	$	(194	)	$	(3,144	)	$	2,259
White Cliffs	44,945		—		11,841			1,278		(11,259		)	(3,785		)	43,020
Rendezvous	42,528		—		767			—		(2,709		)	(2,745		)	37,841
Mont Belvieu JV	110,299		—		29,200			—		(29,239		)	(5,311		)	104,949
TEG	15,879		—		4,290			3,720		(4,368		)	(163		)	19,358
TEP	178,975		—		37,963			11,980		(33,552		)	(2,168		)	193,198
FRP	166,555		—		23,308			14,980		(23,481		)	(4,926		)	176,436
Saddlehorn	109,227		—		15,833			294		(16,017		)	(830		)	108,507
Panola	23,625		—		2,200			—		(2,200		)	(856		)	22,769
Mi Vida	64,988		—		13,734			—		(14,000		)	(91		)	64,631
Ranch Westex	53,301		—		10,678			—		(10,876		)	(2,201		)	50,902
Whitethorn	—		150,563		47,088			7,069		(39,497		)	(3,365		)	161,858
Cactus II	—		12,052		—			94,308		—			—			106,360
Total	$	817,352	$	162,615	$	195,469		$	133,629	$	(187,392	)	$	(29,585	)	$	1,092,088


⁽¹⁾	Recorded in Impairments in the consolidated statements of operations.


⁽²⁾	Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual investment basis.


⁽³⁾	Includes capitalized interest of $1.4 million related to the construction of the Cactus II pipeline.

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10. EQUITY INVESTMENTS (CONTINUED)

The investment balance in Fort Union at December 31, 2018, is $3.1 million less than the Partnership’s underlying equity in Fort Union’s net assets due to an impairment loss recognized by the Partnership in 2017 for its investment in Fort Union.

The investment balance in Rendezvous at December 31, 2018, includes $34.3 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of Western Gas Resources, Inc. (“WGRI”), the entity that previously owned the interest in Rendezvous, which Anadarko acquired in August 2006. This excess balance is attributable to the difference between the fair value and book value of such gathering and treating facilities (at the time WGRI was acquired by Anadarko) and is being amortized to Equity income, net – affiliates over the remaining estimated useful life of those facilities.

The investment balance in White Cliffs at December 31, 2018, is $6.4 million less than the Partnership’s underlying equity in White Cliffs’ net assets, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference is being amortized to Equity income, net – affiliates over the remaining estimated useful life of the White Cliffs pipeline.

The investment balance in Whitethorn at December 31, 2018, is $39.1 million less than the Partnership’s underlying equity in Whitethorn’s net assets, primarily due to terms of the acquisition agreement which provided the Partnership a share of pre-acquisition operating cash flow. This difference is being amortized to Equity income, net – affiliates over the remaining estimated useful life of Whitethorn.

An impairment loss was recognized by the operator of Fort Union during the year ended December 31, 2016. The Partnership’s 14.81% share of the impairment loss was $3.0 million for the year ended December 31, 2016, recorded in Equity income, net – affiliates in the consolidated statements of operations.

Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.

The following tables present the summarized combined financial information for the Partnership’s equity investments (amounts represent 100% of investee financial information):



	Year Ended December 31,
thousands	2018		2017		2016
Revenues	$	1,300,921	$	877,020	$	806,671
Operating income	876,910		542,390		503,239
Net income	874,587		540,538		502,260



	December 31,
thousands	2018		2017
Current assets	$	297,143	$	214,473
Property, plant and equipment, net	4,251,020		3,366,754
Other assets	81,769		84,522
Total assets	$	4,629,932	$	3,665,749
Current liabilities	101,729		112,143
Non-current liabilities	42,431		45,413
Equity	4,485,772		3,508,193
Total liabilities and equity	$	4,629,932	$	3,665,749

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11. COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:



	December 31,
thousands	2018		2017
Trade receivables, net	$	221,328	$	160,700
Other receivables, net	45		210
Total accounts receivable, net	$	221,373	$	160,910

A summary of other current assets is as follows:



	December 31,
thousands	2018		2017
NGLs inventory	$	6,466	$	10,958
Imbalance receivables	9,035		2,063
Prepaid insurance	1,972		2,388
Contract assets	5,399		—
Other	3,309		—
Total other current assets	$	26,181	$	15,409

A summary of accrued liabilities is as follows:



	December 31,
thousands	2018		2017
Accrued interest expense	$	70,959	$	40,632
Short-term asset retirement obligations	25,938		2,304
Short-term remediation and reclamation obligations	863		833
Income taxes payable	384		2,495
Contract liabilities	16,235		—
Other	13,495		1,635
Total accrued liabilities	$	127,874	$	47,899

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12. ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations:



	Year Ended December 31,
thousands	2018			2017
Carrying amount of asset retirement obligations at beginning of year	$	154,571		$	150,082
Liabilities incurred	34,558			17,932
Liabilities settled	(12,432		)	(10,468		)
Accretion expense	7,909			7,339
Revisions in estimated liabilities	141,356			(10,314		)
Carrying amount of asset retirement obligations at end of year	$	325,962		$	154,571

The liabilities incurred for the year ended December 31, 2018, represented additions in asset retirement obligations primarily due to capital expansions at the West Texas and DJ Basin complexes, the DBM water systems and the DBM oil system. Revisions in estimated liabilities for the year ended December 31, 2018, primarily included (i) $71.8 million related to changes in expected settlement costs and timing, primarily at the DJ Basin and West Texas complexes and the MGR assets, and (ii) $43.4 million related to the shutdown of the Third Creek gathering system during the second quarter of 2018. See Note 1 for further information.

The liabilities incurred for the year ended December 31, 2017, represented additions in asset retirement obligations primarily due to (i) capital expansions at the DJ Basin and DBM complexes and the DBJV system, (ii) the Property Exchange in March 2017 and (iii) the start-up of the DBM water systems in 2017. Revisions in estimated liabilities for the year ended December 31, 2017, were related to (i) changes in expected settlement costs and timing primarily at the Hilight system and the DJ Basin and DBM complexes, and (ii) changes in property lives primarily at the Granger, DJ Basin and DBM complexes and the Hilight and DBJV systems.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. DEBT AND INTEREST EXPENSE

The following table presents the Partnership’s outstanding debt:



	December 31, 2018						December 31, 2017
thousands	Principal		Carrying Value		Fair Value ⁽¹⁾		Principal		Carrying Value		Fair Value ⁽¹⁾
2.600% Senior Notes due 2018	$	—	$	—	$	—	$	350,000	$	349,684	$	350,631
5.375% Senior Notes due 2021	500,000		496,959		515,990		500,000		495,815		530,647
4.000% Senior Notes due 2022	670,000		669,078		662,109		670,000		668,849		684,043
3.950% Senior Notes due 2025	500,000		492,837		466,135		500,000		491,885		500,885
4.650% Senior Notes due 2026	500,000		495,710		483,994		500,000		495,245		520,144
4.500% Senior Notes due 2028	400,000		394,631		377,475		—		—		—
4.750% Senior Notes due 2028	400,000		395,841		384,370		—		—		—
5.450% Senior Notes due 2044	600,000		593,349		522,386		600,000		593,234		637,827
5.300% Senior Notes due 2048	700,000		686,648		605,327		—		—		—
5.500% Senior Notes due 2048	350,000		342,328		311,536		—		—		—
RCF	220,000		220,000		220,000		370,000		370,000		370,000
APCWH Note Payable	427,493		427,493		427,493		98,966		98,966		98,966
Total long-term debt	$	5,267,493	$	5,214,874	$	4,976,815	$	3,588,966	$	3,563,678	$	3,693,143


⁽¹⁾	Fair value is measured using the market approach and Level 2 inputs.

Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2018 and 2017:



thousands	Carrying Value
Balance at December 31, 2016	$	3,091,461
RCF borrowings	370,000
APCWH Note Payable borrowings	98,813
Other	3,404
Balance at December 31, 2017	$	3,563,678
RCF borrowings	540,000
APCWH Note Payable borrowings	321,780
Issuance of 4.500% Senior Notes due 2028	400,000
Issuance of 5.300% Senior Notes due 2048	700,000
Issuance of 4.750% Senior Notes due 2028	400,000
Issuance of 5.500% Senior Notes due 2048	350,000
Repayment of 2.600% Senior Notes due 2018	(350,000		)
Repayments of RCF borrowings	(690,000		)
Other	(20,584		)
Balance at December 31, 2018	$	5,214,874

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. DEBT AND INTEREST EXPENSE (CONTINUED)

Senior Notes. In August 2018, the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 were offered to the public at prices of 99.818% and 98.912%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the senior notes are 4.885% and 5.652%, respectively. Interest is paid on each such series semi-annually on February 15 and August 15 of each year, beginning February 15, 2019. The net proceeds were used to repay the maturing 2.600% Senior Notes due August 2018, repay amounts outstanding under the senior unsecured revolving credit facility (“RCF”) and for general partnership purposes, including to fund capital expenditures.

At December 31, 2018, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.

Revolving credit facility. In February 2018, the Partnership entered into the five-year $1.5 billion RCF by amending and restating the $1.2 billion credit facility that was originally entered into in February 2014. The RCF is expandable to a maximum of $2.0 billion, matures in February 2023, with options to extend maturity by up to two additional one year increments, and bears interest at the London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based upon the Partnership’s senior unsecured debt rating. The Partnership is required to pay a quarterly facility fee ranging from 0.125% to 0.250% of the commitment amount (whether used or unused), also based upon its senior unsecured debt rating.

As of December 31, 2018, the Partnership had $220.0 million in outstanding borrowings and $4.6 million in outstanding letters of credit, resulting in $1.3 billion available borrowing capacity under the RCF. As of December 31, 2018 and 2017, the interest rate on any outstanding RCF borrowings was 3.74% and 2.87%, respectively. The facility fee rate was 0.20% at December 31, 2018 and 2017. At December 31, 2018, the Partnership was in compliance with all covenants under the RCF.

In December 2018, the Partnership entered into an amendment to the RCF for (i) subject to the consummation of the Merger (see Note 15), an increase to the size of the RCF to $2.0 billion, while leaving the $0.5 billion accordion feature of the RCF unexercised, and (ii) effective on February 15, 2019, the exercise of one of the Partnership’s one-year extension options to extend the maturity date of the RCF to February 2024.

All notes and obligations under the RCF are recourse to the Partnership’s general partner. The Partnership’s general partner is indemnified by wholly owned subsidiaries of Anadarko against any claims made against the general partner for the Partnership’s long-term debt and/or borrowings under the RCF.

364-day Facility. In December 2018, the Partnership entered into a $2.0 billion 364-day senior unsecured credit agreement (the “364-day Facility”), the proceeds of which will be used to fund substantially all of the cash portion of the consideration under the Merger Agreement and the payment of related transaction costs (see Note 15). The 364-day Facility will mature on the day prior to the one-year anniversary of the completion of the Merger, and will bear interest at LIBOR, plus applicable margins ranging from 1.000% to 1.625%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case as defined in the 364-day Facility and plus applicable margins currently ranging from zero to 0.625%, based upon the Partnership’s senior unsecured debt rating. The Partnership is also required to pay a ticking fee of 0.175% on the commitment amount beginning 90 days after the effective date of the credit agreement through the date of funding under the 364-day Facility.

Funding of the 364-day Facility is conditioned upon the consummation of the Merger and net cash proceeds received from future asset sales and debt or equity offerings by the Partnership must be used to repay amounts outstanding under the facility. See Note 15.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. DEBT AND INTEREST EXPENSE (CONTINUED)

As of December 31, 2018, the Partnership had $427.5 million in outstanding borrowings under the APCWH Note Payable. As of December 31, 2018 and 2017, the interest rate on outstanding borrowings was 3.04% and 2.09%, respectively. At December 31, 2018, the Partnership was in compliance with all covenants under this agreement.

Interest-rate swaps. In December 2018, the Partnership entered into interest-rate swap agreements to manage interest rate risk associated with anticipated 2019 debt issuances. Pursuant to these swap agreements, the Partnership exchanged a floating interest rate indexed to the three-month LIBOR for a fixed interest rate. Depending on market conditions, liability management actions or other factors, the Partnership may settle or amend certain or all of the currently outstanding interest-rate swaps. The following interest-rate swaps were outstanding as of December 31, 2018:



Notional Principal Amount	Reference Period	Mandatory Termination Date	Fixed Interest Rate
$250.0 million	December 2019 - 2024	December 2019	2.730%
$250.0 million	December 2019 - 2029	December 2019	2.856%
$250.0 million	December 2019 - 2049	December 2019	2.905%

The Partnership does not apply hedge accounting and, therefore, gains and losses associated with the interest-rate swaps are recognized currently in earnings. For the year ended December 31, 2018, the Partnership recognized a non-cash loss of $8.0 million, which is included in Other income (expense), net in the consolidated statements of operations.

Valuation of the interest-rate swaps is based on similar transactions observable in active markets and industry standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry standard models are categorized as Level 2 inputs, because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value include market price curves, contract terms and prices, and credit risk adjustments. The fair value of the interest-rate swaps as of December 31, 2018, was an $8.0 million liability, which is reported in Accrued liabilities on the consolidated balance sheets.

Credit risk considerations. Over-the-counter traded swaps expose the Partnership to counterparty credit risk. The Partnership monitors the creditworthiness of its counterparties, establishes credit limits according to the Partnership’s credit policies and guidelines, and assesses the impact on the fair value of its counterparties’ creditworthiness. The Partnership has the ability to require cash collateral or letters of credit to mitigate its credit risk exposure.

The Partnership’s interest-rate swaps are subject to individually negotiated credit provisions that may require collateral of cash or letters of credit depending on the derivative’s portfolio valuation versus negotiated credit thresholds. These credit thresholds generally require full or partial collateralization of the Partnership’s obligations depending on certain credit risk related provisions. Specifically, the Partnership may be required to post collateral with respect to its interest-rate swaps if its credit ratings decline below current levels, the liability associated with the swaps increases substantially or certain credit event of default provisions occur. For example, based on the derivative positions as of December 31, 2018, if the Partnership’s credit ratings from both Standard and Poor’s and Moody’s Investors Service were below the investment grade thresholds of BBB- and Baa3, respectively, the Partnership would be required to post collateral of up to approximately $2.7 million. The aggregate fair value of interest-rate swaps with credit risk related contingent features for which a net liability position existed was $5.7 million at December 31, 2018.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. DEBT AND INTEREST EXPENSE (CONTINUED)

Interest expense. The following table summarizes the amounts included in interest expense:



	Year Ended December 31,
thousands	2018			2017			2016
Third parties
Long-term debt	$	(199,322	)	$	(142,525	)	$	(121,832	)
Amortization of debt issuance costs and commitment fees	(8,207		)	(6,616		)	(6,398		)
Capitalized interest	32,479			9,074			12,918
Total interest expense – third parties	(175,050		)	(140,067		)	(115,312		)
Affiliates
Deferred purchase price obligation – Anadarko ⁽¹⁾	—			(71		)	7,747
APCWH Note Payable	(6,746		)	(153		)	—
Total interest expense – affiliates	(6,746		)	(224		)	7,747
Interest expense	$	(181,796	)	$	(140,291	)	$	(107,565	)


⁽¹⁾	See Note 3 for a discussion of the Deferred purchase price obligation - Anadarko.

14. COMMITMENTS AND CONTINGENCIES

Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As of December 31, 2018 and 2017, the consolidated balance sheets included $1.7 million and $1.8 million, respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities and the long-term portion of these amounts is included in Other liabilities. The recorded obligations do not include any anticipated insurance recoveries. The majority of payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes its environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership’s overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered. See Note 11 and Note 12.

Litigation and legal proceedings. In February 2017, DBJV, at the time a 50/50 joint venture between a third party and the Partnership, initiated an arbitration against SWEPI LP (“SWEPI”) for breach of a 2007 gas gathering agreement between it and DBJV (the “GGA”). Specifically, DBJV sought to collect certain gathering fees under the GGA for the period January 1, 2016 to July 1, 2017. SWEPI disputed DBJV’s calculation of the cost of service based rate and filed a counterclaim alleging overpayment of fees under the GGA for the years 2013 through 2015. As part of the adoption of Topic 606 (see Note 1), during the first quarter of 2018, the Partnership recorded a $7.5 million contract liability and reduced total equity and partners’ capital related to the counterclaim for the years 2013 through 2015 under the GGA revenue contract. The arbitration hearing concluded on June 27, 2018. On September 14, 2018, the panel issued a binding non-appealable decision awarding no damages to either DBJV or SWEPI. As such, during the third quarter of 2018, the previously recorded contract liability was reversed, resulting in a $7.5 million increase to Service revenues - fee based in the consolidated statements of operations.

In addition, from time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which the final disposition could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. COMMITMENTS AND CONTINGENCIES (CONTINUED)

Other commitments. The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to construction and expansion projects at the DBM oil and DBM water systems and the West Texas and DJ Basin complexes.

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease arrangements for corporate offices, shared field offices, a warehouse and equipment supporting the Partnership’s operations, for which Anadarko charges the Partnership rent. The leases for the corporate offices and shared field offices extend through 2028 and 2033, respectively, and the lease for the warehouse expired in February 2017. Rent expense charged to the Partnership associated with these lease arrangements was $56.5 million, $45.5 million and $37.8 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Operating leases. The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2018, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:



thousands	Operating Leases
2019	$	8,711
2020	2,236
2021	460
2022	467
2023	473
Thereafter	1,547
Total	$	13,894

See Accounting standards adopted in 2019 in Note 1 for a discussion of the expected impact the adoption of ASU 2016-02, Leases (Topic 842) will have on the consolidated financial statements.

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15. SUBSEQUENT EVENTS

On November 7, 2018, WGP, the Partnership, Anadarko and certain of their affiliates entered into a Contribution Agreement and Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, among other things, Clarity Merger Sub, LLC, a wholly owned subsidiary of WGP, merged with and into the Partnership, with the Partnership continuing as the surviving entity and a subsidiary of WGP (the “Merger”). On February 28, 2019, immediately following the Merger, the common units of the Partnership ceased to trade on the NYSE under the symbol “WES.” The common units of WGP began to trade on the NYSE under the symbol “WES.”

Pursuant to the Merger Agreement, the following transactions, among others, occurred immediately prior to the Merger becoming effective in the order as follows: (1) Anadarko E&P Onshore LLC and WGR Asset Holding Company LLC (“WGRAH”) (the “Contributing Parties”) contributed to the Partnership all of their interests in each of Anadarko Wattenberg Oil Complex LLC, Anadarko DJ Oil Pipeline LLC, Anadarko DJ Gas Processing LLC, Wamsutter Pipeline LLC, DBM Oil Services, LLC, Anadarko Pecos Midstream LLC, Anadarko Mi Vida LLC and APCWH to WGR Operating, LP, Kerr-McGee Gathering LLC and DBM (each wholly owned by the Partnership) in exchange for aggregate consideration of $1.814 billion in cash from the Partnership, minus the outstanding amount payable on the APCWH Note Payable assumed by the Partnership in connection with the transaction, and 45,760,201 of the Partnership’s common units; (2) AMH sold to the Partnership its interests in Saddlehorn and Panola in exchange for aggregate consideration of $193.9 million in cash; (3) the Partnership contributed cash in an amount equal to the outstanding balance of the APCWH Note Payable immediately prior to the effective time to APCWH, and APCWH paid such cash to Anadarko in satisfaction of the APCWH Note Payable; (4) Class C units converted into the Partnership’s common units on a one-for-one basis; and (5) the Partnership and its general partner caused the conversion of the IDRs and the 2,583,068 general partner units held by the general partner into a non-economic general partner interest in the Partnership and 105,624,704 of the Partnership’s common units. The 45,760,201 of the common units issued to the Contributing Parties, less 6,375,284 common units retained by WGRAH, converted into the right to receive an aggregate of 55,360,984 WGP common units upon the consummation of the Merger. See Note 13 for additional information.

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SUPPLEMENTAL QUARTERLY INFORMATION

(UNAUDITED)

The following table presents a summary of the Partnership’s operating results by quarter for the years ended December 31, 2018 and 2017. The Partnership’s operating results reflect the operations of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies) from the dates of common control, unless otherwise noted. See Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures.



thousands except per-unit amounts	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
2018
Total revenues and other ⁽¹⁾	$	501,054	$	518,078		$	587,900	$	692,626
Equity income, net – affiliates	30,229		49,430			54,215		61,595
Cost of product ⁽¹⁾	94,318		95,656			101,035		124,496
Operating income (loss)	225,699		114,910			258,245		266,457
Net income (loss)	182,870		68,123			199,519		186,014
Net income (loss) attributable to Western Gas Partners, LP	179,885		65,312			198,529		184,191
Net income (loss) per common unit – basic and diluted ⁽²⁾	0.38		(0.32		)	0.39		0.10
2017
Total revenues and other	$	550,492	$	574,838		$	622,009	$	682,275
Equity income, net – affiliates	25,728		28,975			28,902		31,536
Cost of product	196,297		216,644			251,939		288,912
Gain (loss) on divestiture and other, net	119,487		15,458			72		(2,629		)
Proceeds from business interruption insurance claims	5,767		24,115			—		—
Operating income (loss)	154,586		234,327			204,551		211,106
Net income (loss)	116,566		196,265			167,744		261,826
Net income (loss) attributable to Western Gas Partners, LP	114,464		194,219			163,337		259,646
Net income (loss) per common unit – basic and diluted⁽²⁾	0.01		0.49			0.38		0.39


⁽¹⁾	See Adjustments to previously issued financial statements in Note 1—Summary of Significant Accounting Policies.


⁽²⁾	Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets.

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