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WES Western Midstream Partners

Filed: 26 Feb 21, 12:32pm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020

Or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to       
WESTERN MIDSTREAM PARTNERS, LP
WESTERN MIDSTREAM OPERATING, LP
(Exact name of registrant as specified in its charter)
Commission file number:State or other jurisdiction of incorporation or organization:I.R.S. Employer Identification No.:
Western Midstream Partners, LP001-35753Delaware46-0967367
Western Midstream Operating, LP001-34046Delaware26-1075808
Address of principal executive offices:Zip Code:Registrant’s telephone number, including area code:
Western Midstream Partners, LP9950 Woodloch Forest Drive, Suite 2800The Woodlands,Texas77380(832)636-1009
Western Midstream Operating, LP9950 Woodloch Forest Drive, Suite 2800The Woodlands,Texas77380(832)636-1009
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbolName of exchange
on which registered
Western Midstream Partners, LPCommon unitsWESNew York Stock Exchange
Western Midstream Operating, LPNoneNoneNone
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Western Midstream Partners, LPYesþNo¨
Western Midstream Operating, LPYesþNo¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Western Midstream Partners, LPYes¨Noþ
Western Midstream Operating, LPYes¨Noþ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Western Midstream Partners, LPYesþNo¨
Western Midstream Operating, LPYesþNo¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Western Midstream Partners, LPYesþNo¨
Western Midstream Operating, LPYesþNo¨



Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Western Midstream Partners, LPLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller Reporting CompanyEmerging Growth Company
þ
Western Midstream Operating, LPLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller Reporting CompanyEmerging Growth Company
þ
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Western Midstream Partners, LP¨
Western Midstream Operating, LP¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Western Midstream Partners, LP
Western Midstream Operating, LP
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Western Midstream Partners, LPYesNoþ
Western Midstream Operating, LPYesNoþ
The aggregate market value of the registrant’s common units representing limited partner interests held by non-affiliates of the registrant on June 30, 2020, based on the closing price as reported on the New York Stock Exchange.
Western Midstream Partners, LP$2.0 billion
Western Midstream Operating, LPNone
Common units outstanding as of February 22, 2021:
Western Midstream Partners, LP413,059,211
Western Midstream Operating, LPNone
DOCUMENTS INCORPORATED BY REFERENCE
None
FILING FORMAT

This annual report on Form 10-K is a combined report being filed by two separate registrants: Western Midstream Partners, LP and Western Midstream Operating, LP. Western Midstream Operating, LP is a consolidated subsidiary of Western Midstream Partners, LP that has publicly traded debt, but does not have any publicly traded equity securities. Information contained herein related to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.

Part II, Item 8 of this annual report includes separate financial statements (i.e., consolidated statements of operations, consolidated balance sheets, consolidated statements of equity and partners’ capital, and consolidated statements of cash flows) for Western Midstream Partners, LP and Western Midstream Operating, LP. The accompanying Notes to Consolidated Financial Statements, which are included under Part II, Item 8 of this annual report, and Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part II, Item 7 of this annual report, are presented on a combined basis for each registrant, with any material differences between the registrants disclosed separately.




TABLE OF CONTENTS
ItemPage
1 and 2.
1A.
1B.
3.
4.
5.
7.
7A.
8.
9.
9A.
9B.
3


4

COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, references to “we,” “us,” “our,” “WES,” “the Partnership,” or “Western Midstream Partners, LP” refer to Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP) and its subsidiaries. As used in this Form 10-K, the terms and definitions below have the following meanings:
AESC: Anadarko Energy Services Company, a subsidiary of Occidental.
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.
Anadarko or APC: Anadarko Petroleum Corporation and its subsidiaries, excluding our general partner, which became a wholly owned subsidiary of Occidental upon closing of the Occidental Merger on August 8, 2019.
Anadarko note receivable: The 30-year $260.0 million note established in May 2008 between WES Operating as the lender and Anadarko as the borrower. The note bore interest at a fixed annual rate of 6.50%, payable quarterly. Following the Occidental Merger, Occidental became the ultimate counterparty. On September 11, 2020, the Partnership and Occidental entered into a Unit Redemption Agreement, pursuant to which (i) WES Operating transferred and assigned its interest in the Anadarko note receivable to its limited partners on a pro-rata basis, transferring 98% of its interest in (and accrued interest owed under) the Anadarko note receivable to the Partnership and the remaining 2% to WGRAH, a subsidiary of Occidental, (ii) the Partnership subsequently assigned the 98% interest in (and accrued interest owed under) the Anadarko note receivable to Anadarko, which Anadarko canceled and retired immediately upon receipt, in exchange for which Occidental caused certain of its subsidiaries to transfer an aggregate of 27,855,398 common units of the Partnership to the Partnership, and (iii) the Partnership canceled such common units immediately upon receipt.
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 WES’s 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 compared to drip condensate, mainly composed of propane, butane, pentane, and heavier hydrocarbon fractions.
COSF: Centralized oil stabilization facility.
Cryogenic: The process by 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 as compared to traditional refrigeration methods.
DBM: Delaware Basin Midstream, LLC.
DBM water systems: The produced-water gathering and disposal systems in West Texas.

5

December 2019 Agreements: Certain agreements entered into on December 31, 2019, including (i) agreements between the Partnership and certain of its subsidiaries, including WES Operating and WES Operating GP, and Occidental and/or certain of its subsidiaries, including Anadarko, and (ii) amendments to WES Operating’s debt agreements. For a description of the December 2019 Agreements, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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, Latham 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.
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 this Form 10-K.
End-use markets: The ultimate users/consumers of transported energy products.
Equity-investment throughput: Our share of average throughput from investments accounted for under the equity method of accounting.
Exchange Act: The Securities Exchange Act of 1934, as amended.
Exchange Agreement: That certain Exchange Agreement, dated December 31, 2019, by and among WGRI, the general partner, and WES, pursuant to which (i) WGRI exchanged WES common units for the issuance of a 2.0% general partner interest in WES to the general partner and (ii) WES canceled the non-economic general partner interest in WES.
Fixed-Rate Senior Notes: WES Operating’s fixed-rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050.
Floating-Rate Senior Notes: WES Operating’s floating-rate Senior Notes due 2023.
FERC: The Federal Energy Regulatory Commission.
Fort Union: Fort Union Gas Gathering, LLC.
Fractionation: The process of applying various levels of high pressure and low 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 Midstream Holdings, LLC, the general partner of the Partnership.
Gpm: Gallons per minute, when used in the context of amine-treating capacity.
Hydraulic fracturing: The high-pressure injection of fluids into the wellbore to create fractures in rock formations, stimulating the production of oil or gas.
IDRs: Incentive distribution rights.

6

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: The 33.75% interest in the Larry’s Creek, Seely, and Warrensville gas-gathering systems and related facilities located in northern Pennsylvania.
MBbls/d: Thousand barrels per day.
Mcf: Thousand cubic feet.
Merger: The merger of Clarity Merger Sub, LLC, a wholly owned subsidiary of the Partnership, with and into WES Operating, with WES Operating continuing as the surviving entity and a subsidiary of the Partnership, which closed on February 28, 2019.
Merger Agreement: The Contribution Agreement and Agreement and Plan of Merger, dated November 7, 2018, by and among the Partnership, WES Operating, 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.
MIGC: MIGC, LLC.
Mi Vida: Mi Vida JV 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 pressure and temperature.
NYSE: New York Stock Exchange.
NYMEX: New York Mercantile Exchange.
Occidental: Occidental Petroleum Corporation and, as the context requires, its subsidiaries, excluding our general partner.
Occidental Merger: Occidental’s acquisition by merger of Anadarko pursuant to the Occidental Merger Agreement, which closed on August 8, 2019.

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Occidental Merger Agreement: Agreement and Plan of Merger, dated as of May 9, 2019, by and among Occidental, Baseball Merger Sub 1, Inc., and Anadarko.
OTTCO: Overland Trail Transmission, LLC.
Panola: Panola Pipeline Company, LLC.
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.
Purchase Program: In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.
Ranch Westex: Ranch Westex JV LLC.
Receipt point: The point where hydrocarbons are received by or into a gathering system, processing facility, or transportation pipeline.
RCF: WES Operating’s $2.0 billion senior unsecured revolving credit facility that matures in February 2025.
Red Bluff Express: Red Bluff Express Pipeline, LLC.
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.
Related parties: Occidental and the Partnership’s equity interests in Fort Union (until divested in October 2020, see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), White Cliffs, Rendezvous, the Mont Belvieu JV, TEP, TEG, FRP, Whitethorn LLC, Cactus II, Saddlehorn, Panola, Mi Vida, Ranch Westex, and Red Bluff Express.
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.
Services Agreement: That certain amended and restated Services, Secondment, and Employee Transfer Agreement, dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP.
Springfield system: The Springfield gas-gathering system and Springfield oil-gathering system.
Stabilization: The process to reduce the volatility of a liquid hydrocarbon stream by 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.

8

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.
Term loan facility: WES Operating’s senior unsecured credit facility entered into in connection with the Merger, which was repaid and terminated in January 2020.
Wellhead: The point at which the hydrocarbons and water exit the ground.
WES Operating: Western Midstream Operating, LP, formerly known as Western Gas Partners, LP, and its subsidiaries.
WES Operating GP: Western Midstream Operating GP, LLC, the general partner of WES Operating.
West Texas complex: The DBM complex and DBJV and Haley systems.
WGP RCF: The senior secured revolving credit facility of Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP) that matured in March 2019.
WGRI: Western Gas Resources, Inc., a subsidiary of Occidental.
White Cliffs: White Cliffs Pipeline, LLC.
Whitethorn LLC: Whitethorn Pipeline Company LLC.
Whitethorn: A crude-oil and condensate pipeline, and related storage facilities, owned by Whitethorn LLC.

9

PART I

Items 1 and 2.  Business and Properties

GENERAL OVERVIEW

WES and WES Operating. WES is a Delaware master limited partnership formed in September 2012. Our common units are publicly traded on the NYSE under the symbol “WES.” Our general partner is a wholly owned subsidiary of Occidental. WES Operating is a Delaware limited partnership formed by Anadarko in 2007 to acquire, own, develop, and operate midstream assets. WES owns, directly and indirectly, a 98.0% limited partner interest in WES Operating, and directly owns all of the outstanding equity interests of WES Operating GP, which holds the entire non-economic general partner interest in WES Operating.
    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 our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our customers under certain contracts.

Available information. We electronically file our annual reports 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 with the SEC 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 and Business Conduct, and the charters of the Audit Committee and the Special Committee of our Board of Directors are 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 office is located at 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, TX 77380. Our telephone number is 832-636-1009.

10

BASIS OF PRESENTATION FOR ACQUIRED ASSETS AND RESULTS OF OPERATIONS

Presentation of the Partnership’s assets. Our assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating as of December 31, 2020 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental; therefore, prior asset acquisitions from Anadarko were classified as transfers of net assets between entities under common control. As such, assets acquired from Anadarko initially were recorded at Anadarko’s historic carrying value, which did not equate to the total acquisition price paid by us. Further, subsequent to asset acquisitions from Anadarko, we were required to recast our financial statements to include the activities of acquired assets from the date of common control.
For reporting periods that required recast, the consolidated financial statements for periods prior to the acquisition of assets from Anadarko were prepared from Anadarko’s historical cost-basis accounts and may not be necessarily indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership’s assets prior to the acquisitions from Anadarko as being “our” historical financial results.

Fort Union and Bison facilities. In October 2020, we (i) sold our 14.81% interest in Fort Union, which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility, located in Northeast Wyoming, to a third party, exercisable during the first quarter of 2021. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information.

ASSETS AND AREAS OF OPERATION

wes-20201231_g1.jpg

11

As of December 31, 2020, our assets and investments consisted of the following:
Wholly
Owned and
Operated
Operated
Interests
Non-Operated
Interests
Equity
Interests
Gathering systems (1)
17 
Treating facilities39 — — 
Natural-gas processing plants/trains25 — 
NGLs pipelines— — 
Natural-gas pipelines— — 
Crude-oil pipelines— 
_________________________________________________________________________________________
(1)Includes the DBM water systems.

These assets and investments are located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North-central Pennsylvania. The following table provides information regarding our assets by geographic region, as of and for the year ended December 31, 2020:
AreaAsset Type
Miles of Pipeline (1)
Compression (HP) (1) (2)
Processing or Treating Capacity (MMcf/d) (1)
Processing, Treating, or Disposal Capacity (MBbls/d) (1)
Average Throughput for Natural-Gas Assets
(MMcf/d) (3)
Average Throughput for Crude-Oil and NGLs Assets
 (MBbls/d) (3)
Average Throughput for Produced-Water Assets
(MBbls/d) (3)
Texas / New MexicoGathering, Processing, Treating, and Disposal4,160792,6261,8951,5801,818 267 712 
Transportation2,378 — — — 209 284 — 
Rocky MountainsGathering, Processing, and Treating7,047 609,865 3,675 194 2,163 101 — 
Transportation3,296 — — — 82 60 — 
North-central PennsylvaniaGathering146 9,660 — — 161 — — 
Total17,027 1,412,151 5,570 1,774 4,433 712 712 
_________________________________________________________________________________________
(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 throughput for all assets owned and ownership interests accounted for by us under the equity method of accounting. For further details see Properties below.

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. See Part II, Item 8 of this Form 10-K for disclosure of revenues, operating income (loss), and total assets for the years ended December 31, 2020, 2019, and 2018.

12

STRATEGY

Our primary business objective is to create long-term value for our unitholders through continued delivery of high returns and per-unit cash distributions 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 our customers’ midstream service needs that arise from drilling activity in our areas of operation. We continually pursue economically attractive organic business development and 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.

Controlling our operating, capital, and administrative costs. The establishment of WES as a stand-alone midstream business has generated efficiencies between our commercial, engineering, and operations teams, and we continue to optimize and maximize the operability of our existing assets to realize cost and capital savings. We expect to continue to drive operational efficiencies and sustainable cost savings throughout the organization.

Optimizing the return of cash to stakeholders. We intend to operate our assets and make strategic capital decisions that optimize our leverage levels consistent with investment-grade credits in our sector while returning additional excess cash flow to stakeholders that enhances overall return.

Managing commodity-price exposure. We intend to continue limiting our direct exposure to commodity-price changes and promote cash-flow stability by pursuing fee-based contract structures designed to mitigate direct exposure to commodity prices.


13

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:

Substantial presence in basins with historically strong producer economics. Certain of our systems are in areas, such as the Delaware and DJ Basins, which historically have 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 are capable of servicing hydrocarbon production that contains natural gas, crude oil, condensate, and NGLs. Our systems in the Delaware Basin also include significant produced-water takeaway capacity, which makes us a uniquely positioned, full-service midstream provider in the basin.

Well-positioned and well-maintained assets. We believe that our large-scale asset portfolio, 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 exposure to commodity-price volatility, as 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts for the year ended December 31, 2020. 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, 2020, 79% of our natural-gas throughput, 85% of our crude-oil and NGLs throughput, and 100% of our 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-dated debt maturity profile, long-term relationships, and reasonable access to 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, 2020, there was $2.0 billion in available borrowing capacity under the RCF.

Affiliation with Occidental. We continue to optimize our assets by sizing and planning growth initiatives in a manner that highlights the strength of our asset portfolio vis a vis Occidental’s upstream development plans. Our relationship with Occidental enables us to pursue more capital-efficient projects that enhance the overall value of our business. See WES and WES Operating’s Relationship with Occidental Petroleum Corporation below.

We plan to effectively leverage our competitive strengths to successfully implement our business 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 this Form 10-K.

14

WES AND WES OPERATING’S RELATIONSHIP WITH OCCIDENTAL PETROLEUM CORPORATION

The officers of our general partner manage our operations and activities under the direction and supervision of the Board of Directors of our general partner, which is a wholly owned subsidiary of Occidental. Occidental is among the largest independent oil and gas exploration and production companies in the world. Occidental’s upstream oil and gas business explores for, develops, and produces crude oil and condensate, NGLs, and natural gas.
As of December 31, 2020, Occidental held (i) 214,281,578 of our common units, representing a 50.7% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.1% general partner interest in us, and (iii) a 2.0% limited partner interest in WES Operating through its ownership of WGR Asset Holding Company LLC (“WGRAH”), which is reflected as a noncontrolling interest within the consolidated financial statements.
For the year ended December 31, 2020, 66% of Total revenues and other, 41% of our throughput for natural-gas assets (excluding equity-investment throughput), 88% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications and/or minimum-volume commitments under certain of our contracts.
Historically, we sold a significant amount of our natural gas and NGLs to AESC, Occidental’s marketing affiliate. In addition, we purchased natural gas from AESC pursuant to purchase agreements. While we still have some marketing arrangements with affiliates of Occidental, we began marketing and selling substantially all of our natural gas and NGLs directly to third parties beginning on January 1, 2021.
Pursuant to the Services Agreement entered into as part of the December 2019 Agreements, Occidental (i) seconded certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP paid a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees and (ii) continues to provide certain administrative and operational services to us for up to a two-year transition period. In late March 2020, seconded employees’ employment was transferred to the Partnership.
Although we believe our relationship with Occidental enables us to pursue more capital-efficient projects that enhance the overall value of our business, it is also a source of potential conflicts. For example, Occidental is not restricted from competing with us. See Risk Factors under Part I, Item 1A and Certain Relationships and Related Transactions, and Director Independence under Part III, Item 13 of this Form 10-K for more information.

15

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 these 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:

wes-20201231_g2.jpg
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, adding heat, or by reducing the pressure and allowing the more volatile components to flash from the liquid phase to the gas phase.

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 or sulfur compounds, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide or sulfur compounds from the gas stream.

Processing. The principal components of natural gas are methane and ethane, but often the 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 downstream 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

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

Gathering. Produced water often accounts for the largest byproduct stream associated with the onshore 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 to maintain production. Produced-water disposal systems remove hydrocarbon products and other sediments from the produced water and re-inject the produced water utilizing permitted disposal wells in compliance with applicable regulations.

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Contractual Arrangements

Midstream services, other than transportation, are usually provided under contractual arrangements that vary in terms of exposure to commodity-price risk. Three typical contract types, or combinations thereof, include the following:

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 per-unit price received by the service provider does not vary with commodity-price changes, thereby 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 types of arrangements expose the service provider to commodity-price exposure associated with the cost of purchased keep-whole volumes and the sales value of the retained NGLs.

See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-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, 2020.

GATHERING, PROCESSING, TREATING, AND DISPOSAL

Overview - Texas and New Mexico
LocationAssetTypeProcessing / 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, & Treating14 1,370 44 336 538,390 1,802 
West Texas
DBM oil system (5)
Gathering & Treating16 — 256 66 13,473 642 
West TexasDBM water systemsGathering & Disposal— — 1,020 109 46,000 782 
West Texas
Mi Vida (6)
Processing200 — 20,000 — — 
West Texas
Ranch Westex (7)
Processing125 — 10,090 — 12 
East Texas
Mont Belvieu JV (8)
Processing— 170 — — — — 
South TexasBrasada complexGathering, Processing, & Treating200 15 14 30,450 58 
South Texas
Springfield system (9)
Gathering and Treating— 75 80 134,223 864 
Total411,8951,580611792,626124,160
_________________________________________________________________________________________
(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 19 miles of transportation related to the Ramsey Residue Lines (regulated by FERC) at the West Texas complex and 15 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 and New Mexico
wes-20201231_g3.jpg

West Texas gathering, processing, and treating complex

Customers. For the year ended December 31, 2020, Occidental’s production represented 47% of the West Texas complex throughput, and the largest third-party customer provided 10% 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.

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 ET’s Oasis pipeline (the “Oasis pipeline”). Residue gas from the West Texas complex is delivered to the 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.

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DBM oil-gathering system, treating facilities, and storage

Customers. As of December 31, 2020, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2020, Occidental’s production represented 96% of the total DBM oil system throughput and is subject to the Texas Railroad Commission tariff.

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 is delivered into Plains All American Pipeline.

DBM produced-water disposal systems

Customers. As of December 31, 2020, DBM water systems throughput was from Occidental and numerous third-party producers. Occidental’s production represented 87% of the throughput for the year ended December 31, 2020.

Supply. Supply of produced water for the systems comes from crude-oil 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, 2020, Mi Vida plant throughput was from Occidental 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 to the Oasis pipeline or Transwestern Pipeline Company LLC’s pipeline (“Transwestern pipeline”). NGLs production is delivered to the Lone Star pipeline.

Ranch Westex processing plant

Customers. As of December 31, 2020, Ranch Westex plant throughput was from Occidental 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 to the Oasis pipeline or Transwestern pipeline, and NGLs production is delivered to the Lone Star pipeline.

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East Texas
wes-20201231_g4.jpg

Mont Belvieu JV fractionation trains

Customers. The Mont Belvieu JV does not contract with customers directly but 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, 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 terminals.

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South Texas
wes-20201231_g5.jpg

Brasada gathering, stabilization, treating, and processing complex

Customers. Brasada complex throughput was from one third-party customer as of December 31, 2020.

Supply. Supply of gas and NGLs is sourced from throughput gathered by the Springfield system.

Delivery points. The facility delivers residue gas to the Eagle Ford Midstream system operated by NET Midstream, LLC. Stabilized condensate is delivered to Plains All American Pipeline, and NGLs are delivered to the Enterprise-operated South Texas NGL Pipeline System.

Springfield gathering system, stabilization facility, and storage

Customers. Springfield system throughput was from numerous third-party customers as of December 31, 2020.

Supply. Supply of gas and oil is sourced from third-party production in the Eagle Ford Shale Play.

Delivery points. The gas-gathering system delivers rich gas to our Brasada complex, the Raptor processing plant owned by Carnero G&P LLC and operated by Targa Resources Corp., Sanchez Midstream Partners LP, and to processing plants operated by ET. 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 - Rocky Mountains - Colorado and Utah
LocationAssetTypeProcessing / Treating Plants
Processing / Treating Capacity (MMcf/d) (1)
Processing / Treating Capacity (MBbls/d)CompressorsCompression HorsepowerGathering Systems
Pipeline Miles (2)
Colorado
DJ Basin complex (3)
Gathering, Processing, & Treating15 1,730 39 153 379,702 3,185 
ColoradoDJ Basin oil systemGathering & Treating— 155 21 6,095 433 
Utah
Chipeta (4)
Processing790 — 15 77,784 — 18 
Total242,520194189463,58133,636
_________________________________________________________________________________________
(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, Hambert JT (currently inactive), Wattenberg, Lancaster Trains I and II, and Latham Trains I and II processing plants, and the Wattenberg gathering system. Excludes 3,220 gpm of amine-treating capacity.
(4)We are the managing member of and own a 75% interest in Chipeta, which owns the Chipeta processing complex.

Colorado
wes-20201231_g6.jpg
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DJ Basin gathering, treating, and processing complex

Customers. For the year ended December 31, 2020, Occidental’s production represented 65% of the DJ Basin complex throughput, and the two largest third-party customers provided 19% of the throughput.

Supply. The DJ Basin complex is supplied primarily by the Wattenberg field.

Delivery points. As of December 31, 2020, 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”), Tallgrass Energy’s Cheyenne Connector pipeline, and Xcel Energy’s residue pipelines for natural-gas residue takeaway and to Overland Pass Pipeline Company LLC’s pipeline, FRP’s pipeline, and DCP’s Wattenberg NGL 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. For the year ended December 31, 2020, all of the DJ Basin oil system throughput was from Occidental’s production.

Supply. The DJ Basin oil system, which is supplied primarily 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 Energy Transfer LP (“ET”).

Delivery points. The COSF has market access to the White Cliffs pipeline, Saddlehorn pipeline, Tallgrass Energy’s Pony Express pipeline and rail-loading facilities in Tampa, Colorado, and local markets.

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Utah
wes-20201231_g7.jpg

Chipeta processing complex

Customers. For the year ended December 31, 2020, Occidental’s production represented 47% of the Chipeta complex throughput and the two largest third-party customers provided 45% of the throughput.

Supply. The Chipeta complex is well positioned to access third-party production in the Uinta Basin. Chipeta’s inlet is connected to Caerus Oil and Gas LLC’s Greater Natural Buttes gathering system, the Dominion Energy Questar Pipeline, LLC system (“Questar pipeline”), and Three Rivers Gathering, LLC’s system, which is owned by MPLX LP (“MPLX”).

Delivery points. The Chipeta plant delivers NGLs via the GNB NGL pipeline 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 that deliver residue gas 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
LocationAssetTypeProcessing / Treating PlantsProcessing / Treating Capacity (MMcf/d)CompressorsCompression HorsepowerGathering SystemsPipeline Miles
Northeast Wyoming
Bison (1)
Treating450 3,550 — — 
Northeast WyomingHilightGathering & Processing60 32 40,361 1,215 
Southwest Wyoming
Granger complex (2)
Gathering & Processing520 35 44,940 783 
Southwest Wyoming
Red Desert complex (3)
Gathering & Processing125 26 49,948 1,127 
Southwest Wyoming
Rendezvous (4)
Gathering— — 7,485 286 
Total101,155100146,28443,411
_________________________________________________________________________________________
(1)See the Basis of Presentation for Acquired Assets and Results of Operations section within these Items 1 and 2.
(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 currently is 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.

wes-20201231_g8.jpg
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Northeast Wyoming

Bison treating facility

Customers. Bison treating facility throughput was from one third-party customer as of December 31, 2020. See the Basis of Presentation for Acquired Assets and Results of Operations section within these Items 1 and 2.

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.

Hilight gathering system and processing plant

Customers. As of December 31, 2020, gas gathered and processed at the Hilight system was from third-party customers. The two largest third-party producers provided 59% of the system throughput for the year ended December 31, 2020.

Supply. The Hilight 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 gas to 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, 2020, Granger complex throughput was from third-party customers, with the three largest third-party customers providing 81% of the Granger complex throughput for the year ended December 31, 2020.

Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields.

Delivery points. Residue gas 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 MPLX’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, and other local markets.

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Red Desert gathering and processing complex

Customers. For the year ended December 31, 2020, 66% of the Red Desert complex throughput was from the three largest third-party customers.

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 and to truck- and rail-loading facilities.

Rendezvous gathering system

Customers. As of December 31, 2020, Rendezvous system throughput primarily was from two shippers that have dedicated acreage to the system.

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

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Overview - North-central Pennsylvania
LocationAssetTypeCompressorsCompression HorsepowerGathering SystemsPipeline Miles
North-central Pennsylvania
Marcellus (1)
Gathering9,660 146 
_________________________________________________________________________________________
(1)We own a 33.75% interest in the Marcellus Interest gathering systems.

wes-20201231_g9.jpg

Marcellus gathering systems

Customers. As of December 31, 2020, the Marcellus Interest gathering systems had two priority shippers. The largest producer provided 80% of the throughput for the year ended December 31, 2020. 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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TRANSPORTATION
wes-20201231_g10.jpg
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LocationAssetTypeOwnership InterestPipeline Miles
Colorado, Kansas, Oklahoma
White Cliffs (1) (2)
Oil & NGLs10.00 %2,108 
Wyoming, Colorado, Kansas, Oklahoma
Saddlehorn (1) (2)
Oil20.00 %600 
Utah
GNB NGL (1)
NGLs100.00 %33 
Northeast Wyoming
MIGC (1)
Gas100.00 %243 
Southwest WyomingOTTCOGas100.00 %233 
Southwest WyomingWamsutterOil100.00 %79 
Colorado, Oklahoma, Texas
FRP (1) (2)
NGLs33.33 %447 
Texas, Oklahoma
TEG (2)
NGLs20.00 %138 
Texas
TEP (1) (2)
NGLs20.00 %594 
Texas
Whitethorn LLC (2)
Oil20.00 %416 
Texas
Panola (1) (2)
NGLs15.00 %249 
Texas
Cactus II (1) (2)
Oil15.00 %454 
Texas
Red Bluff Express (1) (2)
Gas30.00 %80 
Total5,674 
_________________________________________________________________________________________
(1)Regulated by FERC.
(2)Operated by a third party.

Rocky Mountains - Colorado

White Cliffs pipeline

Customers. The White Cliffs pipeline had multiple committed shippers, including Occidental, as of December 31, 2020. Other parties may also ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual-pipeline system provides crude-oil and NGL takeaway capacity of approximately 190 MBbls/d from Platteville, Colorado, to Cushing, Oklahoma.

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 ET’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 Occidental, as of December 31, 2020. Other parties may also 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. There were two primary shippers on the GNB NGL pipeline as of December 31, 2020. The GNB NGL pipeline provides capacity at the posted FERC-based rates.

Supply. The GNB NGL pipeline receives NGLs from Chipeta’s gas-processing facility and MPLX’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. Occidental was the largest firm shipper on the MIGC system, with 39% of the throughput for the year ended December 31, 2020. The remaining throughput on the MIGC system was from numerous third-party shippers. MIGC is certificated for 175 MMcf/d of firm-transportation capacity. All parties on the MIGC system ship pursuant to a tariff on file with FERC.

Supply. MIGC receives gas from the Hilight system, Evolution Midstream’s Jewell plant, various coal-bed methane gathering systems in the Powder River Basin, and from WBI Energy Transmission, Inc.

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, 2020, 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 25 active 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.

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Wamsutter pipeline

Customers. For the year ended December 31, 2020, 94% of the Wamsutter pipeline throughput was from one third-party shipper, with the remaining throughput from Occidental. 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 active receipt points in Sweetwater County, Wyoming, and delivers crude oil to MPLX LP’s SLC Core Pipeline System.

Texas

TEFR Interests

Front Range Pipeline. FRP provides NGLs takeaway capacity from the DJ Basin in Northeast Colorado. FRP has receipt points at gas plants in Weld and Adams Counties, Colorado (including 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, 2020, FRP had multiple committed shippers, including Occidental. FRP provides capacity to other shippers at the posted FERC tariff rate. In 2018, we elected to participate in the expansion of FRP, which was completed during the second quarter of 2020. The expansion of FRP increased its capacity by 100 MBbls/d, to a total capacity of approximately 250 MBbls/d.

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, 2020.

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, 2020, TEP had multiple committed shippers, including Occidental. TEP provides capacity to other shippers at the posted FERC tariff rates. An expansion of TEP was completed in the second quarter of 2020 that increased capacity by 90 MBbls/d, to a total capacity of approximately 366 MBbls/d.

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, and Enterprise’s crude-oil export facilities.

Panola pipeline

    Supply and delivery points. The Panola pipeline transports NGLs from Panola County, Texas, to Mont Belvieu, Texas. As of December 31, 2020, the Panola pipeline had multiple committed shippers. The Panola pipeline provides capacity to other shippers at the posted FERC-based rates.

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Cactus II pipeline

Customers. As of December 31, 2020, the Cactus II pipeline had multiple committed shippers, including Occidental. The Cactus II pipeline also provides capacity to other shippers at the posted FERC-based rates.

Supply. The Cactus II pipeline is supplied by production from McCamey, Texas, and leases capacity on Plains All American Pipeline, L.P.’s intra-Delaware Basin pipelines to allow for origin points in Orla, Wink, Midland, and Crane, Texas.

Delivery points. The Cactus II pipeline transports crude oil from West Texas to the Corpus Christi, Texas, area. Primary delivery points in Corpus Christi include the Plains All American Pipeline; Nustar Energy, L.P.; Moda Ingleside Energy Center; and Buckeye Partners, L.P.’s export terminals.

Red Bluff Express pipeline

Customers. As of December 31, 2020, the Red Bluff Express pipeline had multiple committed shippers, including Occidental. The Red Bluff Express pipeline also provides capacity to other shippers at the posted FERC-based rates. In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline.
    
Supply and delivery points. The Red Bluff Express pipeline is supplied by production from our DBM complex and other third-party plants. The Red Bluff Express pipeline transports natural gas from Reeves and Loving Counties, Texas, to the WAHA hub in Pecos County, Texas.

COMPETITION

    The midstream services business is extremely competitive, and our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition primarily is based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures, and fuel efficiencies. Competition levels vary in our geographic areas of operation and is greatest in areas experiencing heightened producer activity and during periods of high commodity prices. Notwithstanding, Occidental and third-party producers provide certain dedications and/or minimum-volume commitments in our significant areas of operation. We believe that our assets located outside of dedicated areas, whether in or out of the aforementioned significant areas of operation, are geographically well-positioned to retain and attract both Occidental and third-party volumes.
    We believe the primary advantages of our assets include proximity to established and/or future production and the available service flexibility provided to producers. We believe we can efficiently, and at competitive and flexible contract terms, provide services that customers require to gather, compress, treat, process, and transport natural gas; gather, stabilize, and transport condensate, NGLs, and crude oil; and gather and dispose of produced water.

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REGULATION OF OPERATIONS

Pipeline Safety and Maintenance
Many of the pipelines we use to gather and transport oil, natural gas, and NGLs are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency under the U.S. Department of Transportation, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”), with respect to NGLs and oil. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement, and management of natural-gas, crude-oil, NGLs, and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline wall thicknesses, design pressures, maximum operating pressures (“MOP”), pipeline patrols and leak surveys, minimum depth requirements, emergency procedures, and other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity-management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. Past operation of our pipelines with respect to these NGPSA and HLPSA requirements has not resulted in the incurrence of material costs; however, the possibility of new or amended laws and regulations or reinterpretation of PHMSA enforcement practices or other guidance with respect thereto exists, and future compliance with the NGPSA, HLPSA, and new or amended PHMSA regulations could result in increased costs that could have a material adverse effect on our results of operations or financial position.
For example, in October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on (i) the safety of gas-transmission pipelines (i.e., the first of the three parts of the Mega Rule), (ii) the safety of hazardous liquid pipelines, and (iii) enhanced emergency-order procedures. The gas-transmission rule requires operators of gas-transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the MOP. In addition, the rule updates reporting and records-retention standards for gas-transmission pipelines. This rule took effect on July 1, 2020. PHMSA is expected to issue the second part of the Mega Rule focusing on repair criteria in HCAs and creating new repair criteria for non-HCAs, requirements for inspecting pipelines following extreme events, updates to pipeline-corrosion control requirements, and various other integrity-management requirements. PHMSA is subsequently expected to issue the final part of the gas Mega Rule, the Gas Gathering Rule, focusing on requirements relating to gas-gathering lines in low-population-density areas.
The safety of hazardous liquid pipelines rule (submitted by PHMSA in October 2019) extended leak-detection requirements to all non-gathering hazardous liquid pipelines and requires operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. This rule also took effect on July 1, 2020. Finally, the enhanced emergency-order procedures rule focuses on increased emergency-safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. Unlike the other two rules submitted in October 2019, this rule took effect on December 2, 2019.
New laws or regulations adopted by PHMSA, like those summarized above, may impose more stringent requirements applicable to integrity-management programs and other pipeline-safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In addition, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Historically, our intrastate pipeline-safety compliance costs have not had a material adverse effect on our operations; however, there can be no assurance that such costs will remain immaterial in the future.
See risk factor, “Federal and state legislative and regulatory initiatives relating to pipeline safety and integrity management that require the performance of ongoing assessments and implementation of preventive measures, the use of new or more-stringent safety controls or result in more-stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays, and costs of operation” under Part I, Item 1A of this Form 10-K for further discussion on pipeline safety standards.


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Interstate Natural-Gas Pipeline Regulation
Regulation of pipeline-transportation services may affect certain aspects of our business and the market for our products and services. The operations of our MIGC pipeline and the Ramsey Residue Lines are subject to regulation by FERC under the Natural Gas Act of 1938 (the “NGA”). Under the NGA, FERC has authority to regulate natural-gas companies that provide natural-gas pipeline-transportation services in interstate commerce. Federal regulation extends to such matters as the following:
rates, services, and terms and conditions of service;
types of services that may be offered to customers;
certification and construction of new facilities;
acquisition, extension, disposition, or abandonment of facilities;
maintenance of accounts and records;
internet posting requirements for available capacity, discounts, and other matters;
pipeline segmentation to allow multiple simultaneous shipments under the same contract;
capacity release to create a secondary market for transportation services;
relationships between affiliated companies involved in certain aspects of the natural-gas business;
initiation and discontinuation of services;
market manipulation in connection with interstate sales, purchases, or transportation of natural gas and NGLs; and
participation by interstate pipelines in cash management arrangements.

Natural-gas companies are prohibited from charging rates that have not been determined to be just and reasonable by FERC. In addition, FERC prohibits natural-gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
The rates and terms and conditions for our interstate-pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint or by action of FERC under Section 5 of the NGA, and proposed rate increases may be challenged by protest. The outcome of any successful complaint or protest against our rates could have an adverse impact on revenues associated with providing transportation service.
For example, one such matter relates to FERC’s policy regarding allowances for income taxes in determining a regulated entity’s cost of service. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum-products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On March 15, 2018, as clarified on July 18, 2018, in a set of related issuances, FERC addressed treatment of federal income tax allowances in regulated entity rates. To the extent a regulated entity is permitted to include an income tax allowance in its cost of service, FERC directed entities to calculate the income tax allowance at the reduced 21% maximum corporate tax rate established by the Tax Cuts and Jobs Act of 2017. FERC also issued the Revised Policy on Treatment of Income Taxes (“Revised Policy Statement”), stating that it will no longer permit MLPs to recover an income tax allowance in their cost of service rates. FERC has noted that to the extent an entity does not include an income tax allowance in their cost of service rates, such entity may elect to also exclude the accumulated deferred income tax balance from the rate calculation. FERC's Revised Policy Statement may result in an adverse impact on revenues associated with the cost of service rates of our FERC-regulated interstate pipelines.

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Interstate natural-gas pipelines regulated by FERC also are required to comply with numerous regulations related to standards of conduct, market transparency, and market manipulation. FERC’s standards of conduct regulate the manner in which interstate natural-gas pipelines may interact with their marketing affiliates (unless FERC has granted a waiver of such standards). FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes. FERC’s market manipulation regulations make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to engage in fraudulent conduct. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. FERC and CFTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by FERC and CFTC, we could be subject to substantial penalties and fines.
Interstate Liquids-Pipeline Regulation
Regulation of interstate liquids-pipeline services may affect certain aspects of our business and the market for our products and services. Our GNB NGL pipeline provides interstate service as a FERC-regulated common carrier under the Interstate Commerce Act, the Energy Policy Act of 1992, and related rules and orders. We also own interests in FRP, TEP, Saddlehorn, Panola, Cactus II, and White Cliffs, each of which provides interstate services as a FERC-regulated common carrier. FERC regulation requires that interstate liquid-pipeline rates, including rates for transportation of NGLs, be filed with FERC and that these rates be “just and reasonable” and not unduly discriminatory. Rates of interstate NGLs pipelines are currently regulated by FERC, primarily through an annual indexing methodology, under which pipelines increase or decrease rates in accordance with an index adjustment specified by FERC. For the five-year period beginning July 2, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This index adjustment is subject to review every five years, and in December 2020, FERC issued an order establishing an index level of PPI-FG plus 0.78% for a five-year period beginning July 1, 2021. Under FERC’s regulations, an NGLs pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. White Cliffs has a pending request before FERC for authorization to charge market-based rates. On September 12, 2019, the Administrative Law Judge presiding over the case issued an Initial Decision that determined White Cliffs lacks market power and therefore would be permitted to charge market-based rates. On November 19, 2020, FERC issued an order affirming the initial decision findings that White Cliffs lacks market power and is granted market-based rate authority.
The Interstate Commerce Act permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months pending an investigation. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. The just-and-reasonable rate used to calculate refunds cannot be lower than the last tariff rate approved as just and reasonable. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for charges in excess of a just-and-reasonable rate for a period of up to two years prior to the filing of a complaint. FERC’s Revised Policy Statement, discussed above, that no longer permits MLPs to recover an income tax allowance in cost-of-service rates, also applies to our pipelines regulated under the Interstate Commerce Act. The Revised Policy Statement may result in an adverse impact on revenues associated with the cost-of-service rates of our FERC-regulated interstate pipelines.
As discussed above, the CFTC holds authority to monitor certain segments of the physical and futures energy commodities market. The Federal Trade Commission (the “FTC”) has authority to monitor petroleum markets in order to prevent market manipulation. The CFTC and FTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by the CFTC and FTC, we could be subject to substantial penalties and fines.


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Natural-Gas Gathering Pipeline Regulation
Regulation of gas-gathering pipeline services may affect certain aspects of our business and the market for our products and services. Natural-gas gathering facilities are exempt from the jurisdiction of FERC. We believe that our gas-gathering pipelines meet the traditional tests that FERC has used to determine that a pipeline is not subject to FERC jurisdiction, although FERC has not made any determinations with respect to the jurisdictional status of any of our gas pipelines other than MIGC and the Ramsey Residue Lines. However, the distinction between FERC-regulated gas-transmission services and federally unregulated gathering services has been the subject of substantial litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. State regulation of gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. FERC makes jurisdictional determinations on a case-by-case basis. Our natural-gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural-gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Our natural-gas gathering operations are subject to ratable-take and common-purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural-gas gathering activities, which allows natural-gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil, and criminal remedies. To date, there has been no adverse effect to our systems resulting from these regulations.
FERC’s anti-manipulation rules apply to non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to FERC jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. In addition, FERC’s market oversight and transparency regulations also may apply to otherwise non-jurisdictional entities to the extent annual purchases and sales of natural gas reach a certain threshold. FERC’s civil penalty authority, described above, would apply to violations of these rules.
Intrastate-Pipeline Regulation
Regulation of intrastate pipeline services may affect certain aspects of our business and the market for our products and services. Intrastate natural-gas and liquids transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural-gas transportation and the degree of regulatory oversight and scrutiny given to intrastate pipeline rates and services varies from state to state. Regulations within a particular state generally will affect all intrastate pipeline operators within the state on a comparable basis; thus, we believe that the regulation of intrastate transportation in any state in which we operate will not disproportionately affect our operations.
We own an interest in Red Bluff Express, which offers natural-gas transportation services under Section 311 of the Natural Gas Policy Act of 1978. Such pipelines are required to meet certain quarterly reporting requirements, providing detailed transaction information that could be made public. Such pipelines also will be subject to periodic rate review by FERC. In addition, FERC’s anti-manipulation, market-oversight, and market-transparency regulations may extend to intrastate natural-gas pipelines, although they may otherwise be non-jurisdictional, and FERC’s civil penalty authority, described above, would apply to violations of these rules.
Financial-Reform Legislation
For a description of financial reform legislation that may affect our business, financial condition, and results of operations, read Risk Factors under Part I, Item 1A of this Form 10-K for more information.

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ENVIRONMENTAL MATTERS AND OCCUPATIONAL HEALTH AND SAFETY REGULATIONS

Our business operations are subject to numerous federal, regional, state, tribal, and local environmental and occupational health and safety laws and regulations. The more significant of these existing environmental laws and regulations include the following legal standards that exist currently in the United States, as amended from time to time:
the Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, operational, monitoring, and reporting requirements, and that the U.S. Environmental Protection Agency (the “EPA”) has relied on as the authority for adopting climate-change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;
the Federal Water Pollution Control Act, also known as the Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
the Oil Pollution Act of 1990, which subjects, among others, owners and operators of onshore facilities and pipelines to liability for removal costs and damages arising from an oil spill in waters of the United States;
regulations imposed by the Bureau of Land Management (the “BLM”) and the Bureau of Indian Affairs, agencies under the authority of the U.S. Department of the Interior, which govern and restrict aspects of oil and natural-gas operations on federal and Native American lands, including the imposition of liabilities for pollution damages and pollution clean-up costs resulting from such operations;
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
the Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;
the Safe Drinking Water Act, which regulates the quality of the nation’s public drinking water through adoption of drinking-water standards and control over the injection of waste fluids into non-producing geologic formations that may adversely affect drinking water sources;
the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety-hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;
the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potentially harmful effects of these substances, and appropriate control measures;
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment; and
U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency response preparedness.


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Additionally, regional, state, tribal, and local jurisdictions exist in the United States where we operate that also have, or are developing or considering developing, similar environmental laws and regulations governing many of these same types of activities. While the legal requirements imposed under state law may be similar in form to federal laws and regulations, in some cases, the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the permitting, development, or expansion of a project or substantially increase the cost of doing business. These federal and state environmental laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental concerns such as air and water impacts and oil and natural-gas development in close proximity to specific occupied structures and/or certain environmentally sensitive or recreational areas, are expected to continue to have a considerable impact on our operations.
In connection with our operations, we have acquired certain properties supportive of oil and natural-gas activities from third parties whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances, or wastes were not under our control. Under environmental laws and regulations, we could incur strict joint and several liability for remediating hydrocarbons, hazardous substances, or wastes disposed of or released by prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or recycling, and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.
These federal and state laws and their implementing regulations generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals, or other releases, to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective-action obligations or the incurrence of capital expenditures; the occurrence of delays or cancellations in the permitting, development, or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Moreover, there exist environmental laws that provide for citizen suits, which allow individuals and environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. See the following Risk Factors under Part I, Item 1A of this Form 10-K for further discussion on environmental matters such as ozone standards, climate change, including methane or other GHG emissions, hydraulic fracturing, and other regulatory initiatives related to environmental protection: “We are subject to stringent and comprehensive environmental laws and regulations that may expose us to significant costs and liabilities,” “Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could result in increased operating costs and reduced demand for the gathering, processing, compressing, treating, and transporting services we provide,” “Changes in laws or regulations regarding hydraulic fracturing could result in increased costs, operating restrictions, or delays in the completion of oil and natural-gas wells, which could decrease the need for our gathering and processing services,” and “Adoption of new or more stringent legal standards relating to induced seismic activity associated with produced-water disposal could affect our operations.” The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable, as existing standards are subject to change and new standards continue to evolve.
We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not have a material adverse effect on our business, financial condition, results of operations, or cash flows in the future, or that new or more stringently applied existing laws and regulations will not materially increase our costs of doing business. Although we are not fully insured against all environmental risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage that we believe sufficient based on our assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, and claims for damages to property or persons or imposition of penalties resulting from our operations, could have a material adverse effect on our results of operations.
Uncertainty about the future course of regulation exists because of the recent change in U.S. presidential administrations. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working
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Group on the Social Cost of Greenhouse Gases (the “Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide,” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas. Also in January 2021, the administration issued an executive order focused on addressing climate change. Among other things, the climate change executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directs the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending.
The following are examples of proposed and/or final regulations or other regulatory initiatives that could have a potentially material impact on us:

Ground-Level Ozone Standards. In 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion under the primary standard to 70 parts per billion under the secondary standard to provide requisite protection of public health and welfare. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable,” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. By law, the EPA must review each NAAQS every five years. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. However, as noted above, the January 2021 executive order directed federal agencies to review and take action to address any federal regulations or similar agency actions during the prior administration that may be inconsistent with the current administration’s stated priorities. The EPA was specifically ordered to, among other things, propose a Federal Implementation Plan for ozone standards for California, Connecticut, New York, Pennsylvania, and Texas by January 2022. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

Reduction of Methane Emissions by the Oil and Gas Industry. In 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural-gas production and natural-gas processing and transmission facilities. The EPA’s rule is comprised of New Source Performance Standards (“NSPS”), known as Subpart OOOOa, which require certain new, modified, or reconstructed facilities in the oil and natural-gas sector to reduce methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS to, among other things, hydraulically fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural-gas processing plants and pneumatic pumps. In September 2020, the EPA finalized amendments to the NSPS that removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, as discussed above, the current administration issued an executive order in January 2021 calling on the EPA to, among other things, consider a proposed rule suspending, revising, or rescinding the deregulatory amendments by September 2021. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. In a separate rulemaking, the BLM published a final rule in late 2016 that requires a reduction in methane emissions by regulating venting, flaring, and leaking from oil and natural-gas operations on public lands (the “2016 Waste Prevention Rule”). However, in September 2018, the BLM published a final rule that, among other things, rescinded many of the new requirements of the 2016 Waste Prevention Rule (the “2018 Revised Waste Prevention Rule”). Both rules were challenged in federal court and, in July and October 2020, federal courts struck down both the 2016 Waste Prevention Rule and the 2018 Revised Waste Prevention Rule, effectively reinstating the BLM’s prior approach to venting and flaring. Notwithstanding the aforementioned uncertainty regarding the 2016 and 2018 rules, we have taken measures to enter into a voluntary regime, together with certain other oil and natural-gas exploration and production operators, to
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reduce methane emissions. At the state level, some states where we conduct operations, including Colorado, have issued requirements for the performance of leak detection programs that identify and repair methane leaks at certain oil and natural-gas sources. Compliance with these rules or with any future federal or state methane regulations could, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs.

Reduction of GHG Emissions. The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG-reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. Additionally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually determined reduction goals every five years beginning in 2020. Although the United States withdrew from the Paris Agreement, effective November 4, 2020, the Biden administration issued the aforementioned climate change executive order in January 2021, that, among other things, resulted in the U.S. reentering the Paris Agreement, although the emissions pledges in connection with that effort have not yet been updated. The January 2021 climate change executive order also set a goal of a carbon pollution free power section by 2035 and a net zero economy by 2050. Additionally, in Colorado, the Colorado Department of Public Health and Environment convened a stakeholder process and proposed a timeline for GHG emission reduction rulemaking in December 2021. Under HB 19-1261, Colorado adopted aggressive statewide goals to reduce greenhouse gas emissions, with reductions from a 2005 baseline and targets set for 2025 (26%), 2030 (50%), and 2050 (90%). The implementation of substantial limitations on GHG emissions in areas where we conduct operations could result in increased compliance costs to acquire emissions allowances or comply with new regulatory or reporting requirements, which developments could adversely affect demand for oil and natural gas that our customers produce, reduce demand for our services, and have a material adverse effect on our business, financial condition, and results of operations.

We also dispose of produced water generated from oil and natural-gas production operations. The legal standards related to the disposal of produced water into non-producing geologic formations by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to seismic events near injection wells used for the disposal of produced water. In response to such concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced-water disposal wells or are otherwise investigating the existence of a relationship between seismicity and the use of such wells. For example, Colorado developed and follows guidance when issuing underground injection-control permits to limit the maximum injection pressure, rate, and volume of water. Oklahoma has issued rules for wastewater disposal wells that impose certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults, and also is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal-well operations. The Texas Railroad Commission also has adopted similar permitting, operating, and reporting rules for disposal wells. Another consequence of seismic events near produced-water disposal wells is the introduction of class action lawsuits, which allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. One or more of these developments could result in additional regulation and restrictions on our use of injection wells to dispose of produced water, which could have a material adverse effect on our results of operations, capital expenditures and operating costs, and financial condition.

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TITLE TO PROPERTIES AND RIGHTS-OF-WAY

Our real property is classified into two categories: (i) parcels that we own in fee title and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located is held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessor. We or our affiliates have leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit, or license held by us or to our title to any material lease, easement, right-of-way, permit, or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits, and licenses.
Some of the leases, easements, rights-of-way, permits, and licenses transferred to us by Occidental required the consent of the grantor of such rights, which in certain instances was a governmental entity. We believe we have obtained sufficient third-party consents, permits, and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects. With respect to any remaining consents, permits, or authorizations that have not been obtained, we have determined these will not have a material adverse effect on the operation of our business should we fail to obtain such consents, permits, or authorization in a reasonable time frame.
Occidental may hold record title to portions of certain assets as we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals as needed. Such consents and approvals would include those required by federal and state agencies or other political subdivisions. In some cases, Occidental temporarily holds record title to property as nominee for our benefit and in other cases may, on the basis of the expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from Occidental holding the title to any part of such assets subject to future conveyance or as our nominee.

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HUMAN CAPITAL RESOURCES

In March 2020, seconded employees’ employment was transferred to WES. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information. The officers of our general partner manage our operations and activities under the direction and supervision of the Board of Directors. As of December 31, 2020, WES employed 1,045 persons, all of whom reside in the United States. None of these employees are covered by collective bargaining agreements, and WES considers its employee relations to be satisfactory.
Our ability to provide exceptional customer service and generate value for our stakeholders is dependent on our success in recruiting and retaining top talent. To that end, we offer our employees competitive compensation packages and incentive-based awards, as well as a comprehensive offering of health and retirement benefits. In addition, we offer our employees a wide range of programs to help foster work-life balance and support working families, including flexible work schedules and a generous paid-time-off program. To further support our people and the communities in which we live and work, we created the Community Betterment Task Force, comprised of WES senior leadership, to lead and implement our diversity and inclusion efforts, social involvement, and volunteering efforts.
Through regular training and orientation for employees and contractors and the inclusion of safety metrics in our incentive compensation program, we endeavor to create a culture in which safety underpins all decision making throughout the organization. As our employees continue to provide essential services during the COVID-19 crisis, we have developed and implemented a COVID-19 mitigation plan based on the Centers for Disease Control and Prevention (“CDC”) and state health guidelines. This plan includes the implementation of employee health-screening protocols, elevated cleaning measures, reducing shared spaces, purchasing masks for all personnel to be used when social-distancing measures are not possible, and providing work-from-home support to facilitate remote working. Additionally, to ensure employees take adequate care of themselves and protect their coworkers’ health, employees receive additional paid sick leave until they are cleared to return to work.

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Item 1A.  Risk Factors

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made in this Form 10-K, and may from time to time make in other public filings, press releases, and statements by management, forward-looking statements concerning our operations, economic performance, and financial condition. These forward-looking statements include statements preceded by, followed by, or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition, or include other “forward-looking” information.
Although we and our general partner believe that the expectations reflected in our forward-looking statements are reasonable, neither we nor our general partner can provide any assurance that such expectations will prove correct. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following:

our ability to pay distributions to our unitholders;

our assumptions about the energy market;

future throughput (including Occidental production) that is gathered or processed by, or transported through our assets;

our operating results;

competitive conditions;

technology;

the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, and our ability to access financing through the debt or equity capital markets;

the supply of, demand for, and price of, oil, natural gas, NGLs, and related products or services;

commodity-price risks inherent in percent-of-proceeds, percent-of-product, and keep-whole contracts;

weather and natural disasters;

inflation;

the availability of goods and services;

general economic conditions, internationally, domestically, or in the jurisdictions in which we are doing business;

federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit producers’ hydraulic-fracturing activities or other oil and natural-gas development or operations;

environmental liabilities;

legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes;

changes in the financial or operational condition of Occidental;
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the creditworthiness of Occidental or our other counterparties, including financial institutions, operating partners, and other parties;

changes in Occidental’s capital program, corporate strategy, or other desired areas of focus;

our commitments to capital projects;

our ability to access liquidity under the RCF;

our ability to repay debt;

conflicts of interest among us, our general partner and its related parties, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities;

our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

our ability to acquire assets on acceptable terms from third parties;

non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements;

the timing, amount, and terms of future issuances of equity and debt securities;

the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as we and our customers comply with any regulatory orders or other state or local changes in laws or regulations; and

other factors discussed below and elsewhere in this Item 1A, under the caption Critical Accounting Estimates included under Part II, Item 7 of this Form 10-K, and in our other public filings and press releases.

Risk factors and other factors noted throughout this Form 10-K could cause actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
Common units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this Form 10-K in evaluating an investment in our common units.
If any of the following risks were to occur, our business, financial condition, or results of operations could be materially and adversely affected. In such a case, the common units’ trading price could decline, and you could lose part or all of your investment.

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RISKS INHERENT IN OUR BUSINESS

We are dependent on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, treat, process, transport, and/or dispose. A material reduction in Occidental’s production that is gathered, treated, processed, or transported by our assets would result in a material decline in our revenues and cash available for distribution.
We rely on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, treat, process, transport, and/or dispose. For the year ended December 31, 2020, 66% of Total revenues and other, 41% of our throughput for natural-gas assets (excluding equity-investment throughput), 88% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. Occidental may decrease its production in the areas serviced by us and is under no contractual obligation to maintain its production volumes dedicated to us pursuant to the terms of our applicable gathering agreements. The loss of a significant portion of production volumes supplied by Occidental would result in a material decline in our revenues and our cash available for distribution. In addition, Occidental may determine that drilling activity in areas other than our areas of operation is strategically more attractive. A shift in Occidental’s focus away from our areas of operation could result in reduced throughput on our systems and a material decline in our revenues and cash available for distribution.
Because we are dependent on Occidental as our largest customer and the owner of our general partner, any development that materially and adversely affects Occidental’s operations, financial condition, or market reputation could have a material and adverse impact on us. Material adverse changes at Occidental could restrict our access to capital, make it more expensive to access the capital markets, or increase the costs of our borrowings.
We are dependent on Occidental as our largest customer and the owner of our general partner, and we expect to derive significant revenue from Occidental for the foreseeable future. As a result, any event, whether in our area of operations or otherwise, that adversely affects Occidental’s production, financial condition, leverage, market reputation, liquidity, results of operations, or cash flows may adversely affect our revenues and cash available for distribution. Accordingly, we are indirectly subject to the business risks of Occidental, including, but not limited to, the volatility of oil and natural-gas prices, the availability of capital on favorable terms to fund Occidental’s exploration and development activities, the political and economic uncertainties associated with Occidental’s foreign operations, transportation-capacity constraints, and shareholder activism.
Further, we are subject to the risk of non-payment or non-performance by Occidental, including with respect to our gathering and transportation agreements. We cannot predict the extent to which Occidental’s business would be impacted if conditions in the energy industry were to deteriorate further, nor can we estimate the impact such conditions would have on Occidental’s ability to perform under our gathering and transportation agreements. Accordingly, any material non-payment or non-performance by Occidental could reduce our ability to make distributions to our unitholders.
Any material limitations to our ability to access capital as a result of adverse changes at Occidental could limit our ability to obtain future financing on favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Occidental could impact our unit price adversely, thereby limiting our ability to raise capital through equity issuances or debt financing, or adversely affect our ability to engage in or expand or pursue our business activities, and also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
See Occidental’s Exchange Act reports filed with the Securities and Exchange Commission (which are not, and shall not be deemed to be, incorporated by reference herein), for a full discussion of the risks associated with Occidental’s business.
Occidental’s ownership of our general partner may result in conflicts of interest.
Following the closing of the Occidental Merger, Occidental owns our general partner. Occidental’s ownership of our general partner may result in conflicts of interest. The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to Occidental. At the same time, our general partner has duties to manage us in a manner that is beneficial to our unitholders. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to Occidental. As a result of these conflicts of interest, our general partner may favor the interests of Occidental or its owners or affiliates over the interest of our unitholders.
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Our future prospects depend on Occidental’s growth strategy, midstream operational philosophy, and drilling program, including the level of drilling and completion activity by Occidental on acreage dedicated to us. Additional conflicts also may arise in the future associated with future business opportunities that are pursued by Occidental and us. For example, Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us.
On December 31, 2019, we entered into a set of agreements that will facilitate our ability to operate more independently from Occidental. Our separation from Occidental entails risks and uncertainties that may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.
The difficulties of creating a stand-alone structure include, among other things, implementing operational and administrative technology systems, maintaining effective internal controls, replicating a regulatory compliance infrastructure, and hiring, training and retaining qualified personnel, the loss of which could reduce our competitiveness and prospects for future success. Attention to such organizational activities could also divert management’s attention from our existing business.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from our efforts to become independent from Occidental may not materialize. Such difficulties may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.
Any future credit-rating downgrade could negatively impact our cost of and ability to access capital.
Our costs of borrowing and ability to access the capital markets are affected by market conditions and the credit rating assigned to WES Operating’s debt by the major credit rating agencies. As of December 31, 2020, WES Operating’s long-term debt was rated “BB” by Standard and Poor’s (“S&P”), “BB” by Fitch Ratings, and “Ba2” by Moody’s Investors Service (“Moody’s”). In 2020, WES Operating’s credit ratings were downgraded below investment grade by Fitch, S&P, and Moody’s. As a result of these downgrades, financing costs under the RCF increased. Additionally, WES Operating currently has $3.4 billion of outstanding senior notes that provide for increased interest rates following downgrade events. For example, the 2020 downgrades to WES Operating’s credit ratings resulted in a $43.0 million increase to WES Operating’s annualized borrowing costs attributable to the aforementioned senior notes. Additional downgrades to WES Operating’s credit ratings will further increase its borrowing costs.
Any future downgrades in WES Operating’s credit ratings could adversely affect WES Operating’s ability to issue debt in the public debt markets and negatively impact our cost of capital, future interest costs, and ability to effectively execute aspects of our business strategy. Future credit-rating downgrades also could trigger obligations to provide financial assurance of our performance under certain contractual arrangements. We may be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements, such as pipeline transportation contracts and NGLs and gas-sales contracts. At December 31, 2020, there were $5.1 million in letters of credit or cash-provided assurance of our performance under contractual arrangements with credit-risk-related contingent features.
Sustained low natural-gas, NGLs, or oil prices could adversely affect our business.
Sustained low natural-gas, NGLs, or oil prices impact natural-gas and oil exploration and production activity levels and can result in a decline in the production of hydrocarbons over the medium to long term, resulting in reduced throughput on our systems. Such declines also potentially affect the ability of our vendors, suppliers, and customers to continue operations. As a result, sustained lower natural-gas and crude-oil prices could have a material adverse effect on our business, results of operations, financial condition, and our ability to pay cash distributions to our unitholders.
In general terms, the prices of natural gas, oil, condensate, NGLs, and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control. For example, market prices for natural gas have declined substantially from the highs achieved in 2008 and have remained depressed for several years. More recently, the COVID-19 pandemic and resulting mitigation measures also are having an adverse impact on global economic conditions, and are contributing to a significant decline in demand for oil, NGLs, and natural gas, resulting in lower commodity prices that will negatively impact our and our customers’ financial outlooks and activity levels.
Because of the natural decline in production from existing wells, our success depends on our ability to compete for new sources of oil and natural-gas throughput, which is dependent on certain factors beyond our control. Any decrease in the volumes that we gather, process, treat, and transport could affect our business and operating results adversely.
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The volumes that support our business are dependent on, among other things, the level of production from natural-gas and oil wells connected to our gathering systems and processing and treating facilities. This production will naturally decline over time. As a result, our cash flows associated with production from these wells also will decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of oil and natural-gas throughput. The primary factors affecting our ability to obtain sources of oil and natural-gas throughput include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells to the extent such wells are not dedicated to our systems, and (iii) our ability to capture volumes currently gathered or processed by third parties. Our industry is highly competitive, and we compete with similar companies in our areas of operation. In addition, our customers, including Occidental, may develop their own midstream systems in lieu of using ours.
While Occidental has dedicated production from certain of its properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production declines. We also have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected commodity prices, demand for hydrocarbons, levels of reserves, geological considerations, governmental regulations, the availability of drilling rigs, and other production and development costs. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering, processing, and treating assets.
Because of these factors, producers (including Occidental) may be deterred from developing known oil and natural-gas reserves existing in areas served by our assets. Moreover, Occidental may not develop the acreage it has dedicated to us. If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.
The global outbreak of COVID-19 may have an adverse impact on our operations and financial results.
The global outbreak of COVID-19 poses significant risks to our business and to the markets in which we operate. Many of our facilities require our field personnel to be on location to ensure safe and efficient operations. If a significant percentage of our workforce is unable to work, due to illness or travel or other COVID-19-related restrictions, we may experience significant operational disruptions or inefficiencies and a heightened risk of safety and environmental incidents. Any such developments could materially and adversely affect our earnings, cash flows, and ability to make cash distributions to our unitholders.
Additionally, many of our employees have been and may in the future be subject to pandemic-related work-from-home requirements, which stress the capabilities of our information technology systems, including those relating to system security; disrupt normal channels of intracompany communications and key business processes; and heighten the risk of cyber-security threats and operational, health, or safety-related incidents at our facilities. For these reasons, limited working arrangements and other related restrictions may impact our operations and management effectiveness and may introduce, or increase the likelihood of, material risks to our business, operations, productivity, and results of operations.
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flows rather than on our profitability, and we may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay distributions at previously announced levels to holders of our common units, or at all, even during periods in which we record net income.
The amount of cash we have available for distribution primarily depends on our cash flows and not solely on profitability as determined by GAAP, which will be affected by non-cash items. As a result, we may make cash distributions for periods in which we record losses for financial accounting purposes and may not make cash distributions for periods in which we record net earnings for financial accounting purposes.
To pay the announced fourth-quarter 2020 distribution of $0.31100 per unit per quarter, or $1.24400 per unit per year, we require per-quarter available cash of $131.3 million, or $525.1 million per year, based on the number of common units outstanding at February 1, 2021. We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions at currently announced levels. The amount of cash we can distribute on our units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter.
During 2020, we significantly reduced the quarterly cash distribution on our common units and also took measures to reduce full-year 2020 capital expenditures. These cash-preservation measures are intended to enhance our
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financial strength for the duration of the COVID-19 macroeconomic disruption and the weakened commodity-price environment; however, the duration and severity of this pandemic and concomitant economic downturn remains uncertain. There can be no assurance that these announced actions will be adequate to preserve our financial health for the required duration and additional actions, including additional per-unit distribution reductions, may be necessary to manage through the current environment. Furthermore, any cash we preserve from delaying or abandoning capital projects will necessarily delay or eliminate future returns we hoped to generate from previously planned projects, which may meaningfully impact our ability to generate long-term revenue and cash-flow growth. Also, our decision to preserve cash by reducing our quarterly distribution to common unitholders may diminish the long-term value of our units and limit our ability, or increase the cost of, accessing future equity capital necessary to fund our business or to preserve our balance sheet.
We are exposed to the credit risk of third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing, transportation, and disposal agreements, could reduce our ability to make distributions to our unitholders.
On some of our systems, we rely on third-party customers for substantially all of our revenues related to those assets. The loss of a portion or all of these customers’ contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions, replacements of contracts, or otherwise, could reduce our ability to make cash distributions to our unitholders. Further, to the extent any of our third-party customers is in financial distress or enters bankruptcy proceedings, the related customer contracts may be renegotiated at lower rates or altogether rejected. For example, on April 29, 2020, we received notice that Sanchez is attempting to reject a number of midstream and downstream agreements with commercial counterparties, including Sanchez’s Springfield gathering agreements and agreements obligating Sanchez to deliver the gas volumes gathered by the Springfield system to our Brasada processing plant. If the attempted rejection is successful, our South Texas assets could be impaired and our earnings, cash flows from operations, and ability to make cash distributions to our unitholders could be materially and adversely impacted.
Implementation of Colorado Senate Bill 19-181 may increase costs and limit oil and natural-gas exploration and production operations in the state, which could have a material adverse effect on our customers in Colorado and significantly reduce demand for our services in the state.
On April 16, 2019, Senate Bill 19-181 was signed into law in Colorado. The new legislation reforms oversight of oil and natural-gas exploration and production activities in the state. The mission of the Colorado Oil and Gas Conservation Commission (“COGCC”) has changed from fostering energy development in the state to regulating the industry in a manner that is protective of public health and safety and the environment. The new legislation also authorizes Colorado cities and counties to assume an increased role in regulating oil and natural-gas operations within their jurisdictions in a manner that may be more stringent than state-level rules, and a few local governments have passed temporary moratoria on new oil and natural-gas projects until local governments have passed their own rules implementing the new law. The composition of the COGCC commissioners also has been changed under the new law, with the COGCC adding a commissioner with public health expertise. On November 23, 2020, the COGCC finalized sweeping new rules to align the commission’s new mission set forth in Senate Bill 19-181. Some of the changes include doubling setbacks to a minimum of 2,000 feet for schools or childcare centers, enacting a prohibition on routine flaring or venting, and increased protections for wildlife. The COGCC also approved measures to address cumulative impacts by developing a new program with the Colorado Department of Public Health and Environment, and the complete overhaul of the existing permitting procedures to create a unified permitting process. The new rules went into effect on January 15, 2021. Implementation of this new law and the COGCC’s new rules could limit operations as a result of delays by the state in issuing new drilling permits, and result in increased operational costs, which could have a material adverse effect on our customers in Colorado, which in turn could reduce statewide demand for our midstream services significantly.
Changes in laws or regulations regarding hydraulic fracturing could result in increased costs, operating restrictions, or delays in the completion of oil and natural-gas wells, which could decrease the need for our gathering and processing services.
While we do not conduct hydraulic fracturing, our oil and natural-gas exploration and production customers do conduct such activities. Hydraulic fracturing is an essential and common practice used by many of our customers to stimulate production of natural gas and oil from dense subsurface rock formations such as shales. Hydraulic fracturing is typically regulated by state oil and natural-gas commissions, but several federal agencies, including the EPA and the BLM, also have asserted regulatory authority over, proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the hydraulic-fracturing process.
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At the state level, some states have adopted, and others are considering adopting, legal requirements that could impose more stringent disclosure, permitting, or well-construction requirements on hydraulic-fracturing operations, and states could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic-fracturing activities in particular. If new or more-stringent federal, state, or local legal restrictions, prohibitions or regulations, or ballot initiatives relating to the hydraulic-fracturing process are adopted in areas where our oil and natural-gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development, or production activities, which could reduce demand for our gathering and processing services. Moreover, increased regulation of the hydraulic-fracturing process also could lead to greater opposition to, and litigation over, oil and natural-gas production activities using hydraulic-fracturing techniques. Any one or more of these developments could have a material adverse effect on our business, financial condition, and results of operations.
Adoption of new or more stringent legal standards relating to induced seismic activity associated with produced-water disposal could affect our operations.
We dispose of produced water generated from oil and natural-gas production operations. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to recent seismic events near injection wells used for the disposal of produced water. In response to such concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced-water disposal wells or are otherwise investigating the existence of a relationship between seismicity and the use of such wells. These developments could result in additional regulation and restrictions on our use of injection wells to dispose of produced water, including a possible shut down of wells, which could have a material adverse effect on our business, financial condition, and results of operations.
Adverse developments in our geographic areas of operation could disproportionately impact our business, results of operations, financial condition, and ability to make cash distributions to our unitholders.
Our business and operations are concentrated in a limited number of producing areas. Due to our limited geographic diversification, adverse operational developments, regulatory or legislative changes, or other events in an area in which we have significant operations could have a greater impact on our business, results of operations, financial condition, and ability to make cash distributions to our unitholders than if our operations were more diversified.
Our indebtedness may limit our ability to capitalize on acquisitions and other business opportunities or our flexibility to obtain financing.
The operating and financial restrictions and covenants in the indentures governing our publicly traded notes, (collectively, the “Notes”) or the RCF, and any future financing arrangements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments. See Part II, Item 7 of this Form 10-K for a further discussion of the terms of the RCF and Notes.
Furthermore, our indebtedness and related debt-service costs could impair our ability to obtain additional financing, reduce funds available for operations and business opportunities, make us more vulnerable to competitive pressures or market downturns, and limit our financial and operational flexibility.
Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. If our operating results are not sufficient to service indebtedness in the future, we will be forced to take actions such as reducing distributions; reducing or delaying our business activities, acquisitions, investments, or capital expenditures; selling assets; or seeking additional equity capital. We may not be able to execute any of these actions on satisfactory terms or at all.
We may not be able to obtain funding on acceptable terms or at all. This may hinder or prevent us from meeting our future capital needs.
Global financial markets and economic conditions have been, and continue to be, volatile, especially for companies involved in the oil and gas industry. The repricing of credit risk and the recent relatively weak industry conditions have made, and will likely continue to make, it difficult for some entities to obtain funding. In addition, as a result of concerns about the stability and solvency of some of our counterparties, the cost of obtaining financing from
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the credit markets generally has increased as many lenders and institutional investors have increased required rates of return, enacted tighter lending standards, refused to provide funding on terms similar to the borrower’s current debt, and reduced, or in some cases, ceased to provide funding to borrowers. Further, we may be unable to obtain adequate funding under the RCF if our lending counterparties become unable to meet their funding obligations. Due to these factors, we cannot be certain that funding will be available if needed and to the extent required on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our financial condition, results of operations, cash flows, and ability to make cash distributions to our unitholders.
Our failure to maintain an adequate system of internal control over financial reporting could adversely affect our ability to accurately report our results.
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. A material weakness is a deficiency, or a combination of deficiencies, in our internal controls that result in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Effective internal control is necessary for us to provide reliable financial reports and deter and detect any material fraud. If we cannot provide reliable financial reports or prevent material fraud, our reputation and operating results will be harmed. Our efforts to develop and maintain our system of internal controls and to remediate material weaknesses in our controls may not be successful, and we may be unable to maintain adequate control over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls, could harm our operating results. Ineffective internal control also could cause investors to lose confidence in our reported financial information.
Our business could be negatively affected by security threats, including cyber-threats, and other disruptions.
We face various security threats, including cyber-threats to the security of our facilities and infrastructure, attempts to gain unauthorized access to sensitive information or to render data or systems unusable, and terrorist acts. Additionally, destructive forms of protests by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural-gas-related activities could potentially result in damage or injury to persons, property, or the environment, or lead to extended interruptions of our or our customers’ operations. Our implementation of procedures and controls to monitor and mitigate security threats and to increase security for our facilities, infrastructure, and information may result in increased costs. There can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring.
Cyber-attacks, in particular, are becoming more sophisticated and include malicious software intended to gain unauthorized access to data and systems, electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. For example, the gathering, processing, treating, and transportation of natural gas from our gathering systems, processing facilities, and pipelines are dependent on communications among our facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from our facilities. Disruption of those communications, whether caused by cyber-attacks or otherwise, may disrupt our ability to deliver natural gas and control these assets.
There is no assurance that we will not suffer material losses from future cyber-attacks, and as such threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cyber vulnerabilities. Any terrorist or cyber-attack against, or other disruption of, our assets or computer systems could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.
We typically do not obtain independent evaluations of hydrocarbon reserves connected to our systems. Therefore, in the future, throughput on our systems could be less than we anticipate.
We typically do not obtain independent evaluations of hydrocarbon reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate, or the timeline for the development of reserves is greater than we anticipate, and we are unable to secure additional sources of oil and natural gas, there could be a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.
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Our results of operations could be adversely affected by asset impairments.
If commodity prices remain depressed or decline further, and producer activity reduces accordingly, we may be required to write down the value of our midstream properties if the estimated future cash flows from these properties fall below their respective net book values. Because we are a related party of Occidental, the assets we previously acquired from Anadarko were recorded at Anadarko’s carrying value prior to the transaction. Accordingly, we may be at an increased risk for impairments because the initial book values of a substantial portion of our assets do not have a direct relationship with, and in some cases could be significantly higher than, the consideration paid to acquire such assets. See the discussion of material impairments in Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
If third-party pipelines or other facilities interconnected to our gathering, transportation, treating, or processing systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
Our gathering, transportation, treating, and processing systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat, store, or process crude oil, natural gas, or NGLs, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected. For example, during the market disruptions caused by the outbreak of COVID-19, there were concerns that domestic oil-storage capacity could reach operational limits. If such an event had occurred, our customers might have shut-in field production due to limited downstream-takeaway alternatives or resulting wellhead economics. If production is shut-in for these or for other reasons, affected producers may become insolvent or seek to avoid their contractual obligations with us, in which case, our earnings, cash flows from operations, and ability to make cash distributions to our unitholders could be materially and adversely impacted.
A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.
We believe that our gas-gathering systems meet the traditional tests FERC has used to determine if a pipeline is a gas-gathering pipeline and is, therefore, not subject to FERC jurisdiction. FERC, however, has not made any determinations with respect to the jurisdictional status of any of these gas-gathering systems. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of ongoing litigation and, over time, FERC policy concerning which activities it regulates and which activities are excluded from its regulation has changed. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has regulated the gas-gathering activities of interstate pipeline transmission companies more lightly, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural-gas gathering may begin to receive greater regulatory scrutiny at the state and federal levels.
FERC makes jurisdictional determinations for natural-gas gathering and liquids lines on a case-by-case basis. The classification and regulation of our pipelines are subject to change based on future determinations by FERC, the courts, or Congress. A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase. For additional information, read Regulation of Operations–Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K.
Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could negatively impact us, our producer customers, or downstream customers by increasing operating costs and reducing volumetric throughput on our systems due to reduced demand for the gathering, processing, compressing, treating, and transporting services we provide.
The threat of climate change continues to attract considerable attention in the United States and foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs, as well as to restrict or eliminate such future emissions. Further, new legislation, policies, or regulations may inhibit development plans of our producer customers, which could result in lower volumes transported across our assets. Changes to climate-change or other air-emissions
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laws and regulations, or reinterpretations of enforcement or other guidance with respect thereto, that govern the areas in which we operate may impact our operations negatively by increasing our compliance costs and the compliance costs of our customers. In addition, in response to concerns related to climate change, companies in the fossil fuel sector may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. A material reduction in capital available to the energy industry could make it more difficult to secure funding for exploration, development, production, and transportation activities, which could result in decreased demand for our services, or difficulty in securing capital for new construction projects. For additional information read, “Environmental Matters” under Items 1 and 2 of this Form 10-K.
Federal and state legislative and regulatory initiatives relating to pipeline safety and integrity management that require the performance of ongoing assessments and implementation of preventive measures, the use of new or more-stringent safety controls or result in more-stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays, and costs of operation.
Legislation adopted in recent years has resulted in more-stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline-safety requirements on pipeline operators. For instance, pursuant to its authority under federal law, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity-management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs, which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require the operators of covered pipelines to, among other things, perform ongoing assessments of pipeline integrity and implement preventive and mitigating actions. The imposition of new pipeline safety or integrity management requirements pursuant to existing federal laws or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which could result in our incurring increased capital expenditures and operating costs that could have a material adverse effect on our results of operations or financial position. For additional information regarding PHMSA regulations, read Regulation of Operations—Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K.
Additionally, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Moreover, PHMSA and one or more state regulators, including the Texas Railroad Commission, have expanded the scope of their regulatory inspections in recent years to include certain in-plant equipment and pipelines found within NGLs fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, midstream operators of NGLs fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA and EPA requirements, where such changes or modifications may result in additional capital costs, possible operational delays, and increased costs of operation that, in some instances, may be significant.
Some portions of our pipeline systems have been in service for several decades, and we have a limited ownership history with respect to certain of our assets. There could be unknown events or conditions, or increased maintenance or repair expenses, and downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
Some portions of the pipeline systems that we operate were in service for many decades, prior to our purchase of these systems. Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems also could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations.
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We are subject to stringent and comprehensive environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and comprehensive federal, tribal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These environmental laws and regulations may impose numerous obligations that are applicable to our operations, including: (i) the acquisition of permits to conduct regulated activities; (ii) restrictions on the types, quantities, and concentrations of materials that can be released into the environment; (iii) limitations on the generation, management, and disposal of wastes; (iv) limitations or prohibitions of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions, and other protected areas; (v) requiring capital expenditures to limit or prevent releases of materials from our pipelines and facilities; and (vi) imposition of substantial restoration and remedial liabilities and obligations with respect to abandonment of facilities and for pollution resulting from our operations or existing at our owned or operated facilities. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly remedial or corrective actions. Failure to comply with these laws, regulations, and permits or any newly adopted legal requirements may result in the assessment of sanctions, including administrative, civil, and criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the incurrence of capital expenditures, the occurrence of delays or cancellations in the permitting, development or expansion of projects, and the issuance of injunctions limiting or preventing some or all of our operations in particular areas.
We may incur significant environmental costs and liabilities in connection with our operations due to our handling of natural gas, crude oil, NGLs, and other petroleum products, because of pollutants from our operations emitted into ambient air or discharged or released into surface water or groundwater, and as a result of historical industry operations and waste-disposal practices. For example, an accidental release as a result of our operations could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by owners of the properties through which our gathering or transportation systems pass, neighboring landowners, and other third parties for personal injury, natural-resource and property damages, and fines or penalties for related violations of environmental laws or regulations. Joint and several strict liabilities may be incurred, without regard to fault, under certain of these environmental laws and regulations. In addition, stricter laws, regulations, or enforcement policies could increase our operational or compliance costs and the costs of any restoration or remedial actions that may become necessary, which could have a material adverse effect on our results of operations or financial condition. The adoption of any laws, regulations, or other legally enforceable mandates could increase our oil and natural-gas exploration and production customers’ operating and compliance costs and reduce the rate of production of oil or natural gas by operators with whom we have a business relationship, which could have a material adverse effect on our results of operations and cash flows.
Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal, and economic risks, which could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, and legal uncertainties that are beyond our control. These uncertainties also could affect downstream assets, which we do not own or control, but which are critical to certain of our growth projects. Delays in the completion of new downstream assets, or the unavailability of existing downstream assets, due to environmental, regulatory, or political considerations, could have an adverse impact on the completion or utilization of our growth projects. In addition, construction activities could be subject to state, county, and local ordinances that restrict the time, place, or manner in which those activities may be conducted. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize.
We have partial ownership interests in several joint-venture legal entities that we do not operate or control. As a result, among other things, we may be unable to control the amount of cash we receive or retain from the operation of these entities, and we could be required to contribute significant cash to fund our share of joint-venture operations, which could affect our ability to distribute cash to our unitholders adversely.
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Our inability, or limited ability, to control the operations and/or management of joint-venture legal entities in which we have a partial ownership interest may result in our receiving or retaining less cash than we expect. We also may be unable, or limited in our ability, to cause any such entity to effect significant transactions such as large expenditures or contractual commitments, the construction or acquisition of assets, or the borrowing of money.
In addition, for the equity investments in which we have a minority ownership interest, we are unable to control ongoing operational decisions, including the incurrence of capital expenditures or additional indebtedness that we may be required to fund. Further, the other owners of our equity investments may establish reserves for working capital, capital projects, environmental matters, and legal proceedings, that would similarly reduce the amount of cash available for distribution. Any of the above could impact our ability to make cash distributions to our unitholders adversely.
Further, in connection with the acquisition of our membership interest in Chipeta, we became party to the Chipeta LLC agreement. Among other things, the Chipeta LLC agreement provides that to the extent available, Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, to its members quarterly in accordance with those members’ membership interests. Accordingly, we are required to distribute a portion of Chipeta’s cash balances, which are included in the cash balances in our consolidated balance sheets, to the other Chipeta member.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we therefore are, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. Any loss of rights with respect to our real property, through our inability to renew existing rights-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position, and ability to make cash distributions to our unitholders.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in gathering, processing, compressing, treating, and transporting natural gas, crude oil, NGLs, and produced water, including (i) damage to our assets and surrounding properties by natural disasters or acts of terrorism; (ii) inadvertent damage from construction, farm, and utility equipment; (iii) leaks or losses of hydrocarbons or produced water; (iv) fires and explosions; and (v) other hazards that could also result in personal injury, loss of life, pollution, property or natural resource damages, and/or curtailment or suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural-resource damage. These risks also may result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks that may occur in our business. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to certain indemnification rights, for potential environmental liabilities.
We are subject to increased scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.
In recent years, certain institutional investors, including public pension funds, have placed increased importance on the implications and social cost of environmental, social, and governance (“ESG”) matters. ESG initiatives generally seek to divert investment capital from companies involved in certain industries or with disfavored governance structures. The energy industry as a whole has received the attention of such activists, as have companies with our partnership governance model.
Investors’ increased focus and activism related to ESG and similar matters may constrain our ability to raise capital. Any material limitations on our ability to access capital as a result of such scrutiny could limit our ability to
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obtain future financing on favorable terms, or at all, or could result in increased financing costs in the future. Similarly, such activism could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our or its business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

RISKS INHERENT IN AN INVESTMENT IN US

A reduction in Occidental’s ownership interest in us may reduce its incentive to support our operations.
As discussed in WES and WES Operating’s Relationship with Occidental Petroleum Corporation in Part I, Items 1 and 2 of this Form 10-K, we believe that one of our principal strengths is our affiliation with Occidental and that Occidental, through its significant economic interest in us, will continue to pursue projects that enhance the value of our business. To the extent Occidental’s net interest in us declines through the sale of its holdings or otherwise, Occidental may be less incentivized to support the continued growth of our business. Accordingly, a decrease in Occidental’s net holdings in us could have a material adverse effect on our business, results of operations, financial position, and ability to grow or make cash distributions to our unitholders.
Our general partner’s liability regarding our obligations is limited.
Our general partner has included provisions in its and our contractual arrangements that limit its liability so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may, therefore, cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner otherwise would be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner only to consider the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or our limited partners. By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above-described provisions.
Furthermore, our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership;
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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provides that, in the absence of bad faith, our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
The general partner interest in us may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, Occidental, the owner of our general partner, may transfer its ownership interest in our general partner to a third party, also without unitholder consent. Our new general partner or the new owner of our general partner would then be in a position to replace the Board of Directors and officers of our general partner and to control the decisions taken by the Board of Directors and officers.
We may issue additional units without unitholder approval, which would dilute existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will dilute our existing unitholders’ ownership interests and voting strength, and may reduce the market price for our common units and cash available for distribution or increase the ratio of taxable income to distributions.
The market price of our common units could be affected adversely by sales of substantial amounts of our common units in the public or private markets, including sales by Occidental or other large holders.
We had 413,839,863 common units outstanding as of December 31, 2020. Occidental currently holds 214,281,578 common units, representing 51.8% of our outstanding common units. Occidental’s shelf registration statement currently allows for the offer and sale of approximately 41.8 million common units, or 10.1% of our common units as of December 31, 2020, from time to time. Sales by Occidental or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, under our partnership agreement, our general partner and its affiliates, including Occidental, have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the impermissible distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that we were conducting business in a state, but had not complied with that particular state’s partnership statute, or such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitute “control” of our business.



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TAX RISKS TO COMMON UNITHOLDERS

Our taxation as a flow-through entity depends on our status as a partnership for U.S. federal income tax purposes, and our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be reduced substantially.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Notwithstanding our status as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as us to be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement and is not treated as an investment company. Based on our current operations, we believe that we satisfy the qualifying income requirement and are not treated as an investment company. Failing to meet the qualifying income requirement, being treated as an investment company, a change in our business activities, or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the applicable corporate tax rate and likely would pay state income tax at varying rates. Distributions to our unitholders generally would be taxed as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to our unitholders. If we are subject to corporate taxation, our cash available for distribution to our unitholders would be reduced substantially. Likewise, our treatment as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income or franchise taxes or other forms of taxation. For example, we are required to pay Texas margin tax on our gross income apportioned to Texas. Imposition of similar taxes on us in other jurisdictions in which we operate, or to which we may expand our operations, could reduce the cash available for distribution to our unitholders substantially.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.
The current U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial interpretation at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If the IRS were to contest the federal income tax positions we take, it may impact the market for our common units adversely, and the costs of any such contest would reduce the cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to the pricing of our related-party agreements with Occidental or our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
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Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be made, or applicable, in all circumstances. If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to our unitholders might be substantially reduced.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our unitholders are required to pay any U.S. federal income taxes on their share of our taxable income irrespective of whether they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability attributable to their share of our taxable income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder sells common units, the unitholder will recognize gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income result in a decrease in that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to that unitholder, if that unitholder sells such units at a price greater than that unitholder’s tax basis in those units, even if the price received is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if they sell their units, unitholders may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (or “IRAs”) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Upon the sale, exchange or other disposition of a common unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange, or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have recently issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to foreign unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of our common units occurring before January 1, 2022. Foreign unitholders should consult their tax advisor before investing in our common units.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based on the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based on the ownership of our common units on the first day of each month (the “Allocation
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Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets, and, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss, and deduction. The IRS may challenge these methodologies or the resulting allocations, which could affect the value of our common units adversely.
In determining items of income, gain, loss, and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss, and deduction.
A successful IRS challenge to these methods or allocations could diminish the amount of tax benefits available to our unitholders, affect the timing for recognition of these tax benefits or the amount of gain from any sale of common units, impact the value of our common units negatively, or result in audit adjustments to unitholders’ tax returns.
Our unitholders are subject to state and local taxes and return-filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, our unitholders are subject to other taxes, including foreign, state, and local taxes; unincorporated business taxes; and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders likely will be required to file tax returns and pay taxes in some or all of these various jurisdictions, or be subject to penalties for failure to comply with those requirements.

Item 1B.  Unresolved Staff Comments

None.

Item 3.  Legal Proceedings

On July 1, 2020, the U.S. Department of Justice, on behalf of the U.S. Environmental Protection Agency (the “EPA”), and the State of Colorado commenced an enforcement action in the United States District Court for the District of Colorado against Kerr-McGee Gathering LLC (“KMG”), a wholly owned subsidiary of WES, for alleged non-compliance with the leak detection and repair requirements of the federal Clean Air Act (“LDAR requirements”) at its Fort Lupton facility in the DJ Basin complex. KMG previously had been in negotiations with the EPA and the State of Colorado to resolve the alleged non-compliance at the Fort Lupton facility. Per the complaint, plaintiffs pray for injunctive relief, remedial action, and civil penalties. Management cannot reasonably estimate the outcome of this action at this time.

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On August 12, 2019, Sanchez Energy Corporation and certain of its affiliated companies (collectively, “Sanchez”) filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. While Sanchez holds a working interest in the acreage dedicated to our Springfield system, Sanchez also was the upstream operator for substantially all of the natural gas, crude oil, and NGLs that the Springfield system gathers and that WES processes in the Eagle Ford Shale Play. On April 29, 2020, we received notice that Sanchez filed a motion to reject a number of midstream and downstream agreements with commercial counterparties, including Sanchez’s Springfield gathering agreements and agreements obligating Sanchez to deliver the gas volumes gathered by the Springfield system to our Brasada processing plant. We do not believe the Springfield gathering and related agreements are eligible for rejection as a matter of law, and we have filed an objection to the proposed rejection and an adversary proceeding for a declaratory judgment that such agreements may not be rejected.
On May 15, 2020, Gavilan Resources LLC (“Gavilan”), an entity that owns a 25% working interest in the acreage where the Springfield gathering system and Brasada processing plant are located, also filed for Chapter 11 bankruptcy protection. As a part of this bankruptcy, Mesquite Energy, Inc. (the successor to Sanchez) (“Mesquite”) purchased Gavilan’s assets at auction. Gavilan did not assume and assign its agreements with Springfield as part of its asset sale. Instead, the assets sold to Mesquite remain subject to any covenants, servitudes, or similar agreements that could be equitable servitudes or covenants running with the land, pending a further order of the bankruptcy court. As with the Sanchez agreements, we do not believe Gavilan’s agreements may be rejected or left behind and believe they should remain attached to the Gavilan assets.
We cannot make any assurances regarding the ultimate outcome of these Sanchez and Gavilan proceedings and their resulting impact on WES due to the uncertainties associated with the bankruptcy process.
On October 29, 2020, WGR, on behalf of itself and derivatively on behalf of Mont Belvieu JV, filed suit against Enterprise Products Operating, LLC (“Enterprise”) and Mont Belvieu JV (as a nominal defendant) in the District Court of Harris County, Texas. Our lawsuit seeks a declaratory judgment regarding proper revenue allocation as set forth in the Operating Agreement between Mont Belvieu JV (of which WGR is a 25% owner) and Enterprise (the “Operating Agreement”) related to fractionation trains at the Mont Belvieu complex in Chambers County, Texas. Specifically, the Operating Agreement sets forth a revenue allocation structure, whereby revenue would be allocated to the various fracs at the Mont Belvieu complex in sequential order, with Fracs VII and VIII (which are owned by Mont Belvieu JV) following Fracs I through VI, but preceding any “Later Frac Facilities.” Subsequent to the construction of Fracs VII and VIII, Enterprise built Fracs IX, X, and XI, which it wholly owns, and has signaled its intention to treat such subsequent fracs as outside the Mont Belvieu revenue allocation. We do not believe Enterprise’s attempt to bypass the agreed-to revenue allocation is proper under the parties’ agreements and now seek judicial determination. We currently sue only for declaratory judgment to avoid potential future damages. We cannot make any assurances regarding the ultimate outcome of this proceeding and its resulting impact on WGR or WES.

Except as discussed above, we are not a party to any legal, regulatory, or administrative proceedings other than proceedings arising in the ordinary course of business. Management believes that there are no such proceedings for which a final disposition could have a material adverse effect on results of operations, cash flows, or financial condition, or for which disclosure is otherwise required by Item 103 of Regulation S-K.
    
Item 4.  Mine Safety Disclosures

Not applicable.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

MARKET INFORMATION

Our common units are listed on the NYSE under the symbol “WES.” As of February 22, 2021, there were 23 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We also have 9,060,641 general partner units issued and outstanding; there is no established public trading market for any such general partner units. All general partner units are held by our general partner.

OTHER SECURITIES MATTERS

Unregistered sales of equity securities and use of proceeds. Under the Exchange Agreement, WES issued 9,060,641 general partner units to the general partner in 2019. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Securities authorized for issuance under equity compensation plans. Our general partner has the authority to grant equity compensation awards under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WES LTIP”) and the Western Gas Partners, LP 2017 Long-Term Incentive Plan (assumed by us in connection with the Merger) to our independent directors, executive officers, and employees. The WES LTIP permits the issuance of up to 3,000,000 units, of which 2,823,967 units remained available for future issuance as of December 31, 2020. The Western Gas Partners, LP 2017 Long-Term Incentive Plan permits the issuance of up to 3,431,251 units, of which 3,431,251 units remained available for future issuance as of December 31, 2020. Read the information under Part III, Item 12 of this Form 10-K, which is incorporated by reference into this Item 5. See Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Purchases of equity securities by the issuer and affiliated persons. The following table sets forth information with respect to repurchases made by WES of its common units in the open market under the Purchase Program during the fourth quarter of 2020:
PeriodTotal number of units purchasedAverage price paid per unit
Total number of units purchased as part of publicly announced plans or programs (1)
Approximate dollar value of units that may yet be purchased under the plans or programs (1)
October 1-31, 2020— $— — $250,000,000 
November 1-30, 2020870,369 13.28 870,369 238,445,000 
December 1-31, 20201,498,342 14.00 1,498,342 217,466,000 
Total2,368,711 13.73 2,368,711 
______________________________________________________________________________________
(1)In November 2020, WES announced the $250.0 million Purchase Program that will extend through December 31, 2021. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details.

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SELECTED INFORMATION FROM OUR PARTNERSHIP AGREEMENT

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Available cash. Under our partnership agreement, we distribute all of our available cash (beyond proper reserves as defined in our partnership agreement) to unitholders of record on the applicable record date within 55 days following each quarter’s end. The amount of available cash 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 general partner to provide for the proper conduct of our business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments, or other agreements; or to provide funds for unitholder distributions 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 and are intended to be repaid or refinanced within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund unitholder distributions.

General partner interest. As of December 31, 2020, our general partner owned a 2.1% general partner interest in us, which entitles it to receive cash distributions. Our general partner may own our common units or other equity securities and would be entitled to receive cash distributions on any such interests.

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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, wherein WES Operating is fully consolidated, and which are included under Part II, Item 8 of this Form 10-K, and the information set forth in Risk Factors under Part I, Item 1A of this Form 10-K.
The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2020 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental; therefore, prior asset acquisitions from Anadarko were classified as transfers of net assets between entities under common control. As such, subsequent to asset acquisitions from Anadarko, we were required to recast our financial statements to include the activities of acquired assets from the date of common control.
For reporting periods that required recast, the consolidated financial statements for periods prior to the acquisition of assets from Anadarko were prepared from Anadarko’s historical cost-basis accounts and may not be necessarily indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership’s assets prior to the acquisitions from Anadarko as being “our” historical financial results.

EXECUTIVE SUMMARY

We are a midstream energy company organized as a publicly traded partnership, 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 our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our customers under certain contracts. We own or have investments in assets located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North-central Pennsylvania. As of December 31, 2020, our assets and investments consisted of the following:
Wholly
Owned and
Operated
Operated
Interests
Non-Operated
Interests
Equity
Interests
Gathering systems (1)
17 
Treating facilities39 — — 
Natural-gas processing plants/trains25 — 
NGLs pipelines— — 
Natural-gas pipelines— — 
Crude-oil pipelines— 
_________________________________________________________________________________________
(1)Includes the DBM water systems.

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Significant financial and operational events during the year ended December 31, 2020, included the following:

In January 2020, WES Operating completed an offering of $3.2 billion in aggregate principal amount of Fixed-Rate Senior Notes and $300.0 million in aggregate principal amount of Floating-Rate Senior Notes. Net proceeds from these offerings were used to repay and terminate the Term loan facility, repay outstanding amounts under the RCF, and for general partnership purposes. See Liquidity and Capital Resources within this Item 7 for additional information.

In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021. We repurchased 2,368,711 units for aggregate consideration of $32.5 million through December 31, 2020.

In October 2020, we (i) sold our 14.81% interest in Fort Union, which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility to a third party, exercisable during the first quarter of 2021.

On September 11, 2020, WES and Occidental entered into a Unit Redemption Agreement, pursuant to which (i) WES Operating transferred and assigned its interest in the Anadarko note receivable to its limited partners on a pro-rata basis, transferring 98% of its interest in (and accrued interest owed under) the Anadarko note receivable to WES and the remaining 2% to WGRAH, a subsidiary of Occidental, (ii) WES subsequently assigned the 98% interest in (and accrued interest owed under) the Anadarko note receivable to Anadarko, which Anadarko canceled and retired immediately upon receipt, in exchange for which Occidental caused certain of its subsidiaries to transfer an aggregate of 27,855,398 common units of WES to WES, and (iii) WES canceled such common units immediately upon receipt.

Our fourth-quarter 2020 distribution is unchanged from the first-, second-, and third-quarter 2020 per-unit distribution of $0.31100.

During the year ended December 31, 2020, WES Operating purchased and retired $218.0 million of certain of its senior notes and Floating-Rate Senior Notes. See Liquidity and Capital Resources within this Item 7 for additional information.

We commenced operations of Latham Train II at the DJ Basin complex (with capacity of 250 MMcf/d) during the first quarter of 2020 and Loving ROTF Trains III and IV at the DBM oil system (with capacity of 30 MBbls/d each) during the first and third quarters of 2020, respectively.

Effective with the execution of the December 2019 agreements, WES began the transition to a stand-alone midstream business resulting in efficiencies between our commercial, engineering, and operations teams, enabling our organization to realize operating and capital savings. This effort has involved, among other things, a transition from Occidental’s Enterprise Resource Planning (“ERP”) system to a stand-alone ERP system, and the transition to a WES-dedicated workforce with its own compensation and benefits structure.

Natural-gas throughput attributable to WES totaled 4,274 MMcf/d for the year ended December 31, 2020, representing a 1% increase compared to the year ended December 31, 2019.

Crude-oil and NGLs throughput attributable to WES totaled 698 MBbls/d for the year ended December 31, 2020, representing a 7% increase compared to the year ended December 31, 2019.

Produced-water throughput attributable to WES totaled 698 MBbls/d for the year ended December 31, 2020, representing a 28% increase compared to the year ended December 31, 2019.

Operating income (loss) was $878.9 million for the year ended December 31, 2020 (included goodwill and long-lived asset impairments of $644.9 million), representing a 29% decrease compared to the year ended December 31, 2019.
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Adjusted gross margin for natural-gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.16 per Mcf for the year ended December 31, 2020, representing an 8% increase compared to the year ended December 31, 2019.

Adjusted gross margin for crude-oil and NGLs assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $2.54 per Bbl for the year ended December 31, 2020, representing a 4% increase compared to the year ended December 31, 2019.

Adjusted gross margin for produced-water assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $0.98 per Bbl for the year ended December 31, 2020, representing a 1% increase compared to the year ended December 31, 2019.

The following table provides additional information on throughput for the periods presented below:
Year Ended December 31,
20202019Inc/
(Dec)
20202019Inc/
(Dec)
20202019Inc/
(Dec)
Natural gas
(MMcf/d)
Crude oil & NGLs
(MBbls/d)
Produced water
(MBbls/d)
Delaware Basin1,297 1,226 %189 150 26 %712 556 28 %
DJ Basin1,305 1,236 %101 118 (14)% — — %
Equity investments445 398 12 %381 343 11 % — — %
Other1,386 1,563 (11)%41 52 (21)% — — %
Total throughput4,433 4,423 — %712 663 %712 556 28 %

During 2020, the global outbreak of COVID-19 caused a sharp decline in the worldwide demand for oil, natural gas, and NGLs, which contributed significantly to commodity-price declines and oversupplied commodities markets. These market dynamics have an adverse impact on producers that provide throughput into our systems, and we have experienced decreased throughput at many of our locations.
Additionally, many of our employees have been and may continue to be subject to pandemic-related work-from-home requirements, which requires us to take additional actions to ensure that the number of personnel accessing our network remotely does not lead to excessive cyber-security risk levels. Similarly, we are working continually to ensure operational changes that we have made to promote the health and safety of our personnel during this pandemic do not unduly disrupt intracompany communications and key business processes. We consider our risk-mitigation efforts adequate; however, the ultimate impact of the ongoing pandemic is unpredictable, with direct and indirect impacts to our business. See Risk Factors under Part I, Item 1A of this Form 10-K for additional information on these and other risks.
WES continues to monitor the COVID-19 situation closely, and as state and federal governments issue additional guidance, we will update our own policy responses to ensure the safety and health of our workforce and communities. The federal government has provided guidance to states on how to safely return personnel to the workplace, which we are following as our workforce returns to WES locations. All WES facilities, including field locations, have been conducting enhanced routine cleaning and disinfecting of common areas and frequently touched surfaces using CDC- and EPA-approved products. Our return-to-work protocols include daily required application-based health self-assessments that must be completed prior to accessing WES work locations.


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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.

Commodity purchase and sale agreements. Effective April 1, 2020, changes to marketing-contract terms with AESC terminated AESC’s prior status as an agent of the Partnership for third-party sales and established AESC as a customer of the Partnership. Accordingly, we no longer recognize service revenues and/or product sales revenues and the equivalent cost of product expense for the marketing services performed by AESC. Year-over-year variances for the year ended December 31, 2020, include the following impacts related to this change (i) decrease of $130.9 million in Service revenues fee based, (ii) decrease of $29.7 million in Product sales, and (iii) decrease of $160.6 million in Cost of product expense. These changes had no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate our operations (see How We Evaluate Our Operations within this Item 7). See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Gathering and processing agreements. Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, Marcellus Interest systems, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Acquisitions and divestitures. In February 2019, WES Operating acquired AMA from Anadarko. In January 2019, we acquired a 30% interest in Red Bluff Express. In June 2018, we acquired a 20% interest in Whitethorn LLC and a 15% interest in Cactus II.
In October 2020, we (i) sold our 14.81% interest in Fort Union, which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility to a third party exercisable during the first quarter of 2021. In December 2018, the Newcastle system in Northeast Wyoming was sold to a third party. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments. We recognized long-lived asset and other impairments of $203.9 million, $6.3 million, and $230.6 million for the years ended December 31, 2020, 2019, and 2018, respectively. During the year ended December 31, 2020, we also recognized a goodwill impairment of $441.0 million, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero.
For a description of impairments recorded, see Note 9—Property, Plant, and Equipment, Note 7—Equity Investments, and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

General and administrative expenses. On December 31, 2019, we entered into the December 2019 Agreements, which helped facilitate our ability to operate more independently from Occidental. As a result, during 2020, we began incurring costs to (i) implement technology systems to manage the operations and administration of our day-to-day business, (ii) secure our dedicated workforce, and (iii) operate as a stand-alone entity. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Noncontrolling interests. For periods subsequent to Merger completion, our noncontrolling interests in the consolidated financial statements consist of (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating. For periods prior to Merger completion, our noncontrolling interests in the consolidated financial statements consisted of (i) the 25% third-party interest in Chipeta, (ii) the publicly held limited partner interests in WES Operating, (iii) the common units issued by WES Operating to subsidiaries of Anadarko as part of the consideration paid for prior acquisitions from Anadarko, and (iv) the Class C units issued by WES Operating to a subsidiary of Anadarko as part of the funding for the acquisition of DBM.


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Commodity-price swap agreements. The consolidated statements of operations and consolidated statements of equity and partners’ capital included the impacts of commodity-price swap agreements for the years ended December 31, 2019 and 2018. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information regarding the commodity-price swap agreements with Anadarko that expired without renewal on December 31, 2018.

Income taxes. With respect to assets acquired from Anadarko, we recorded Anadarko’s historic current and deferred income taxes for the periods prior to our ownership of the assets. For periods subsequent to asset 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.

OUR OPERATIONS

Our results primarily are driven 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 operate in Texas, New Mexico, Colorado, Utah, Wyoming, and North-central Pennsylvania, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains. For example, for the year ended December 31, 2020, our West Texas and DJ Basin assets provided (i) 46% and 38%, respectively, of Total revenues and other, (ii) 33% each of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 57% and 31%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.
For the year ended December 31, 2020, 66% of Total revenues and other, 41% of our throughput for natural-gas assets (excluding equity-investment throughput), 88% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications and/or minimum-volume commitments under certain of our contracts.
For the year ended December 31, 2020, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under 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 production facilities or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements.
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 to our systems. We also bear limited commodity-price risk through the settlement of imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K.
As a result of previous 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 (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) safety performance, (v) system availability, (vi) Adjusted gross margin (as defined below), (vii) Adjusted EBITDA (as defined below), and (viii) Free cash flow (as defined below).

Throughput. Throughput is a significant operating variable that we use to assess our ability to generate revenues. 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, crude-oil, NGLs, or produced-water volumes currently serviced by our competitors.

Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of these costs on asset profitability 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, fleet management, contract services, utility costs, and services provided to us or on our behalf. For periods commencing on the date of and subsequent to the acquisition of assets from Anadarko, certain of these expenses are incurred under our services and secondment agreement with Occidental, which was amended and restated on December 31, 2019. See further detail in Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

General and administrative expenses. To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods and to the annual budget. Pursuant to the Services Agreement entered into as part of the December 2019 Agreements, Occidental (i) seconded certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP paid a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees until their transfer to us and (ii) agreed to continue to provide certain administrative and operational services to us for up to a two-year transition period, for which Occidental is reimbursed accordingly. The Services Agreement also included provisions governing the transfer of certain employees to us and our assumption of liabilities relating to those employees at the time of their transfer. In late March 2020, seconded employees’ employment was transferred to us. Prior to the December 2019 Agreements, Occidental and our general partner performed centralized corporate functions for us pursuant to the now terminated WES and WES Operating omnibus agreements.

Safety performance. Maintaining a safe and incident free workplace is a critical component of our operational success. Our management team uses both lagging and leading indicators to measure and manage safety performance. Total Recordable Incident Rate is a key lagging indicator reviewed by management. Total Recordable Incident Rate includes injuries or illnesses that result in any of the following: days away from work, restricted work or transfer to another job, medical treatment beyond first aid, loss of consciousness, or death. We also review leading indicators such as unplanned releases, safety observations, occupational and process safety audits and inspections, training completion, and corrective action item completion to enhance our view of safety performance. Safety performance data is reported, tracked, and trended in a centralized database, which allows us to efficiently focus our incident prevention efforts.

System availability. By consistently monitoring the availability of our gathering, processing, and water disposal systems to provide critical midstream services to our customers, we can ensure we are maximizing the ability of our assets to generate revenues, while providing a reliable service to our producer customers. We define system availability as the measure of the “real” average availability experienced by our customers related to its gas systems, oil systems, and water-disposal wells. It considers the ratio of average actual daily volumes to expected daily volumes and includes all experienced sources of downtime, such as scheduled and unscheduled downtime, logistic downtime, etc.
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Non-GAAP financial measures

Adjusted gross margin. We define Adjusted gross margin attributable to Western Midstream 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 interests owners’ proportionate share of revenues and cost of product. We believe Adjusted gross margin is an important performance measure of our operations’ profitability and performance as compared to 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 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 per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets. See Key Performance Metrics within this Item 7.

Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), 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, gain (loss) on early extinguishment of debt, income from equity investments, interest income, income tax benefit, other income, and the noncontrolling interests owners’ proportionate share of revenues and expenses. We believe 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, among other measures, to assess the following:

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 expenditures and the returns on investment of various investment opportunities.

Free cash flow. We define “Free cash flow” as net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus distributions from equity investments in excess of cumulative earnings. Management considers Free cash flow an appropriate metric for assessing capital discipline, cost efficiency, and balance-sheet strength. Although Free cash flow is the metric used to assess WES’s ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period. Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes.

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Reconciliation of non-GAAP financial measures. Adjusted gross margin, Adjusted EBITDA, and Free 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). Net income (loss) 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 Free cash flow is net cash provided by operating activities. Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of operating income (loss), net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA, and Free cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income (loss), net income (loss), and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA, and Free 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 Free cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures.
Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and Free cash flow compared to (as applicable) operating income (loss), net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results.
The following tables present (i) a reconciliation of the GAAP financial measure of operating income (loss) to the non-GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Free cash flow:
Year Ended December 31,
thousands202020192018
Reconciliation of Operating income (loss) to Adjusted gross margin
Operating income (loss)$878,913 $1,231,343 $861,282 
Add:
Distributions from equity investments278,797 264,828 216,977 
Operation and maintenance580,874 641,219 480,861 
General and administrative155,769 114,591 67,195 
Property and other taxes68,340 61,352 51,848 
Depreciation and amortization491,086 483,255 389,164 
Impairments (1)
644,906 6,279 230,584 
Less:
Gain (loss) on divestiture and other, net8,634 (1,406)1,312 
Equity income, net – related parties226,750 237,518 195,469 
Reimbursed electricity-related charges recorded as revenues79,261 74,629 66,678 
Adjusted gross margin attributable to noncontrolling interests (2)
65,835 64,049 56,247 
Adjusted gross margin$2,718,205 $2,428,077 $1,978,205 
Adjusted gross margin for natural-gas assets$1,820,926 $1,656,041 $1,443,466 
Adjusted gross margin for crude-oil and NGLs assets647,390 578,100 447,131 
Adjusted gross margin for produced-water assets249,889 193,936 87,608 
_________________________________________________________________________________________
(1)Includes goodwill impairment for the year ended December 31, 2020. See Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests.

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Year Ended December 31,
thousands202020192018
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)$516,852 $807,700 $630,654 
Add:
Distributions from equity investments278,797 264,828 216,977 
Non-cash equity-based compensation expense22,462 14,392 7,310 
Interest expense380,058 303,286 183,831 
Income tax expense10,278 13,472 58,934 
Depreciation and amortization491,086 483,255 389,164 
Impairments (1)
644,906 6,279 230,584 
Other expense1,953 161,813 8,264 
Less:
Gain (loss) on divestiture and other, net8,634 (1,406)1,312 
Gain (loss) on early extinguishment of debt11,234 — — 
Equity income, net – related parties226,750 237,518 195,469 
Interest income – Anadarko note receivable11,736 16,900 16,900 
Other income2,785 37,792 2,749 
Income tax benefit4,280 — — 
Adjusted EBITDA attributable to noncontrolling interests (2)
50,607 45,131 42,843 
Adjusted EBITDA$2,030,366 $1,719,090 $1,466,445 
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities$1,637,418 $1,324,100 $1,348,175 
Interest (income) expense, net368,322 286,386 166,931 
Uncontributed cash-based compensation awards (1,102)879 
Accretion and amortization of long-term obligations, net(8,654)(8,441)(5,943)
Current income tax expense (benefit)2,702 5,863 (80,114)
Other (income) expense, net (3)
(1,025)(1,549)(3,209)
Cash paid to settle interest-rate swaps25,621 107,685 — 
Distributions from equity investments in excess of cumulative earnings – related parties32,160 30,256 29,585 
Changes in assets and liabilities:
Accounts receivable, net193,688 45,033 60,502 
Accounts and imbalance payables and accrued liabilities, net(144,437)30,866 (45,605)
Other items, net(24,822)(54,876)38,087 
Adjusted EBITDA attributable to noncontrolling interests (2)
(50,607)(45,131)(42,843)
Adjusted EBITDA$2,030,366 $1,719,090 $1,466,445 
Cash flow information
Net cash provided by operating activities$1,637,418 $1,324,100 $1,348,175 
Net cash used in investing activities(448,254)(3,387,853)(2,210,813)
Net cash provided by (used in) financing activities(844,204)2,071,573 875,192 
_________________________________________________________________________________________
(1)Includes goodwill impairment for the year ended December 31, 2020. See Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests.
(3)Excludes net non-cash losses on interest-rate swaps of $25.6 million and $8.0 million for the years ended December 31, 2019 and 2018, respectively. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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Year Ended December 31,
thousands202020192018
Reconciliation of Net cash provided by operating activities to Free cash flow
Net cash provided by operating activities$1,637,418 $1,324,100 $1,348,175 
Less:
Capital expenditures423,091 1,188,829 1,948,595 
Contributions to equity investments – related parties19,388 128,393 133,629 
Add:
Distributions from equity investments in excess of cumulative earnings – related parties32,160 30,256 29,585 
Free cash flow$1,227,099 $37,134 $(704,464)
Cash flow information
Net cash provided by operating activities$1,637,418 $1,324,100 $1,348,175 
Net cash used in investing activities(448,254)(3,387,853)(2,210,813)
Net cash provided by (used in) financing activities(844,204)2,071,573 875,192 

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the below-described 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 incorrect, our actual results may vary materially from expected results. See Risk Factors under Part I, Item 1A of this Form 10-K for additional information.

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. Commodity-price fluctuations affect the level of our customers’ activities and our customers’ allocations of capital within their own asset portfolios. During the first quarter of 2020, oil and natural-gas prices decreased significantly, driven by the expectation of increased supply and sharp declines in demand resulting from the worldwide macroeconomic downturn that followed the global outbreak of COVID-19. For example, NYMEX West Texas Intermediate crude-oil daily settlement prices ranged from a high of $63.27 per barrel in January 2020 to a low below $20.00 per barrel in April 2020, with prices rebounding to $48.52 per barrel at December 31, 2020. While the extent and duration of the recent commodity-price declines cannot be predicted, potential impacts to our business include the following:

We have exposure to increased credit risk to the extent any of our customers, including Occidental, is in financial distress. See Liquidity and Capital Resources—Credit risk within this Item 7 for additional information.

An extended period of diminished earnings may restrict our ability to fully access our RCF, which contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio based on Adjusted EBITDA (as defined in the covenant) related to the trailing twelve-month period. Further, any future waivers or amendments to the RCF also may trigger pricing increases for available credit. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7 for additional information.

As of December 31, 2020, it is reasonably possible that a prolonged depression of commodity prices, further commodity-price declines, changes to producers’ drilling plans in response to lower prices, and potential producer bankruptcies could result in future long-lived asset impairments.


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To the extent producers continue with development plans in our areas of operation, we will continue to connect new wells or production facilities to our systems to maintain throughput on our systems and mitigate the impact of production declines. 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. See risk factor, “The global outbreak of COVID-19 may have an adverse impact on our operations and financial results.” under Part I, Item 1A of this Form 10-K for additional information.

Liquidity and access to capital markets. 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, and the broader energy industry, have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable. If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our growth strategy may become 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 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 increase our operating costs and capital expenditures materially 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.

Impact of interest rates. Overall, short- and long-term interest rates decreased during 2020 and remained low relative to historical averages. Short-term interest rates experienced a sharp decrease in response to the Federal Open Market Committee (“FOMC”) lowering its target range for the federal funds rate twice during 2020. Long-term interest rates experienced a similar decrease in response to lower future economic growth expectations. Any future increases in interest rates likely will result in an increase in financing costs. Additionally, as with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates. 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 face similar interest-rate dynamics.


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Effects of credit-rating downgrade. Our costs of borrowing and ability to access the capital markets are affected by market conditions and the credit ratings assigned to WES Operating’s debt by the major credit rating agencies. In 2020, Fitch Ratings (“Fitch”) and Standard and Poor’s (“S&P”) downgraded WES Operating’s long-term debt from “BBB-” to “BB” and Moody’s Investors Service (“Moody’s”) downgraded WES Operating’s long-term debt from “Ba1” to “Ba2.” As a result of these downgrades, WES Operating’s credit rating is below investment grade for all three major credit rating agencies, which results in the following:

WES Operating’s annualized borrowing costs will increase by $43.0 million for the Fixed-Rate Senior Notes and Floating-Rate Senior Notes issued in January 2020 that provide for increased interest rates following downgrade events.

Beginning in the second quarter of 2020, the interest rate on outstanding RCF borrowings increased by 0.20% and the RCF facility-fee rate increased by 0.05%, from 0.20% to 0.25%.

We may be obligated to provide financial assurance of our performance under certain contractual arrangements requiring us to post collateral in the form of letters of credit or cash. At December 31, 2020, we had $5.1 million in letters of credit or cash-provided assurance of our performance outstanding under contractual arrangements with credit-risk-related contingent features.

Additional downgrades to WES Operating’s credit ratings will further impact its borrowing costs negatively, and may adversely affect WES Operating’s ability to issue public debt and effectively execute aspects of our business strategy.

Per-unit distribution and capital guidance. During 2020, we announced per-unit distribution and cost reductions that are expected to continue into 2021. These cash-preservation measures are intended to enhance our liquidity for the duration of the COVID-19 macroeconomic disruption and the weakened commodity-price environment; however, the duration and severity of this pandemic and concomitant economic downturn remains uncertain. There can be no assurance that these announced actions will provide sufficient liquidity for the required duration, and additional actions, including additional per-unit distribution reductions, may be necessary to manage through the current environment. On February 23, 2021, we provided 2021 guidance as follows:

Total capital expenditures between $275.0 million to $375.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta).

Full-year 2021 distribution of at least $1.24 per unit, subject to evaluation by the Board of Directors on a quarterly basis.

Acquisition opportunities. We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies. 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 per-unit cash flows from operations.

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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,
thousands202020192018
Total revenues and other (1)
$2,772,592 $2,746,174 $2,299,658 
Equity income, net – related parties226,750 237,518 195,469 
Total operating expenses (1)
2,129,063 1,750,943 1,635,157 
Gain (loss) on divestiture and other, net8,634 (1,406)1,312 
Operating income (loss)878,913 1,231,343 861,282 
Interest income – Anadarko note receivable11,736 16,900 16,900 
Interest expense(380,058)(303,286)(183,831)
Gain (loss) on early extinguishment of debt11,234 — — 
Other income (expense), net1,025 (123,785)(4,763)
Income (loss) before income taxes522,850 821,172 689,588 
Income tax expense (benefit)5,998 13,472 58,934 
Net income (loss)516,852 807,700 630,654 
Net income (loss) attributable to noncontrolling interests(10,160)110,459 79,083 
Net income (loss) attributable to Western Midstream Partners, LP (2)
$527,012 $697,241 $551,571 
Key performance metrics (3)
Adjusted gross margin$2,718,205 $2,428,077 $1,978,205 
Adjusted EBITDA2,030,366 1,719,090 1,466,445 
Free cash flow1,227,099 37,134 (704,464)
_________________________________________________________________________________________
(1)Total revenues and other includes amounts earned from services provided to related parties and from the sale of residue gas and NGLs to related parties. Total operating expenses includes amounts charged by related parties for services and reimbursements of amounts paid by related parties to third parties on our behalf. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7.
(3)Adjusted gross margin, Adjusted EBITDA, and Free 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 financial measures within this Item 7.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2020” refer to the comparison of the year ended December 31, 2020, to the year ended December 31, 2019, and any increases or decreases “for the year ended December 31, 2019” refer to the comparison of the year ended December 31, 2019, to the year ended December 31, 2018.
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Throughput
Year Ended December 31,
20202019Inc/
(Dec)
2018Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation543 528 %546 (3)%
Processing3,445 3,497 (1)%3,231 %
Equity investments (1)
445 398 12 %291 37 %
Total throughput4,433 4,423 — %4,068 %
Throughput attributable to noncontrolling interests (2)
159 175 (9)%170 %
Total throughput attributable to WES for natural-gas assets4,274 4,248 %3,898 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation331 320 %295 %
Equity investments (3)
381 343 11 %241 42 %
Total throughput712 663 %536 24 %
Throughput attributable to noncontrolling interests (2)
14 13 %11 18%
Total throughput attributable to WES for crude-oil and NGLs assets698 650 %525 24 %
Throughput for produced-water assets (MBbls/d)
Gathering and disposal712 556 28 %239 133 %
Throughput attributable to noncontrolling interests (2)
14 11 27 %175 %
Total throughput attributable to WES for produced-water assets698 545 28 %235 132 %
_________________________________________________________________________________________
(1)Represents the 14.81% share of average Fort Union throughput (until divested in October 2020, see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), 22% share of average Rendezvous throughput, 50% share of average Mi Vida and Ranch Westex throughput, and 30% share of average Red Bluff Express throughput.
(2)For all periods presented includes (i) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating and (ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES’s noncontrolling interests.
(3)Represents the 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 and Cactus II throughput.

Natural-gas assets

Gathering, treating, and transportation throughput increased by 15 MMcf/d for the year ended December 31, 2020, primarily due to increased production in areas around the Marcellus Interest systems, partially offset by production declines in areas around the Bison facility and Springfield gas-gathering system.
Gathering, treating, and transportation throughput decreased by 18 MMcf/d for the year ended December 31, 2019, primarily due to production declines in areas around the Springfield gas-gathering system. This decrease was offset partially by (i) increased throughput on the MIGC system due to new third-party customer volumes beginning in the second quarter of 2019 and (ii) increased production in areas around the Marcellus Interest systems.
Processing throughput decreased by 52 MMcf/d for the year ended December 31, 2020, primarily due to (i) third-party volumes being diverted away from the Granger straddle plant beginning in the fourth quarter of 2019 and the plant being held idle during the third and fourth quarters of 2020, (ii) lower throughput at the Chipeta complex due to production declines in the area and a third-party contract that terminated during the fourth quarter of 2019, and (iii) lower throughput at the Red Desert complex due to production declines in the area. These decreases were offset partially by (i) increased production in areas around the West Texas and DJ Basin complexes, (ii) the start-up of Latham Train II at the DJ Basin complex during the first quarter of 2020, and (iii) the start-up of Mentone Train II at the West Texas complex in March 2019.
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Processing throughput increased by 266 MMcf/d for the year ended December 31, 2019, primarily due to (i) the start-up of Mentone Trains I and II at the West Texas complex in November 2018 and March 2019, respectively, and (ii) increased production in areas around the West Texas and DJ Basin complexes. These increases were offset partially by (i) volumes being diverted away from the Granger straddle plant beginning in the fourth quarter of 2019 resulting from changes to the product mix of a third-party customer and (ii) downstream constraints during the third quarter of 2019 that impacted our DJ Basin complex.
Equity-investment throughput increased by 47 MMcf/d for the year ended December 31, 2020, primarily due to increased volumes on Red Bluff Express resulting from increased production in the area. This increase was offset partially by (i) decreased third-party volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020, and (ii) decreased volumes at the Rendezvous system due to production declines in the area.
Equity-investment throughput increased by 107 MMcf/d for the year ended December 31, 2019, primarily due to the acquisition of the interest in Red Bluff Express in January 2019, partially offset by decreased throughput at the Mi Vida and Ranch Westex plants due to related-party volumes being diverted to the West Texas complex for processing following the start-up of Mentone Trains I and II in November 2018 and March 2019, respectively.

Crude-oil and NGLs assets

Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2020, primarily due to increased throughput at the DBM oil system with the commencement of Loving ROTF Trains III and IV operations during the first and third quarters of 2020, respectively, and increased production, partially offset by lower throughput at the DJ Basin oil system due to production declines in the area.
Gathering, treating, and transportation throughput increased by 25 MBbls/d for the year ended December 31, 2019, primarily due to (i) increased throughput at the DBM oil system due to the commencement of ROTF operations in the second quarter of 2018 and increased production in the area and (ii) increased production in areas around the DJ Basin oil system.
Equity-investment throughput increased by 38 MBbls/d for the year ended December 31, 2020, primarily due to (i) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020. These increases were offset partially by decreased volumes on the Whitethorn pipeline.
Equity-investment throughput increased by 102 MBbls/d for the year ended December 31, 2019, primarily due to (i) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline due to additional committed volumes in 2019, (ii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (iii) increased volumes on the Saddlehorn pipeline due to incentive tariffs and additional committed volumes effective beginning in the third quarter of 2019.

Produced-water assets

Gathering and disposal throughput increased by 156 MBbls/d for the year ended December 31, 2020, due to increased throughput at the DBM water systems resulting from additional (i) production, (ii) water-disposal facilities, and (iii) offload connections that increased capacity of the systems.
Gathering and disposal throughput increased by 317 MBbls/d for the year ended December 31, 2019, due to increased throughput at the DBM water systems resulting from new water-disposal systems that commenced operations during the third and fourth quarters of 2018.


80

Service Revenues
Year Ended December 31,
thousands except percentages20202019Inc/
(Dec)
2018Inc/
(Dec)
Service revenues – fee based$2,584,323 $2,388,191 %$1,905,728 25 %
Service revenues – product based48,369 70,127 (31)%88,785 (21)%
 Total service revenues$2,632,692 $2,458,318 %$1,994,513 23 %

Service revenues – fee based

Service revenues – fee based increased by $196.1 million for the year ended December 31, 2020, primarily due to increases of (i) $98.1 million at the West Texas complex and $97.9 million at the DJ Basin complex from increased throughput, (ii) $63.6 million at the DBM oil system from increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, (iii) $59.3 million at the DBM water systems from increased throughput, and (iv) $21.4 million at the Springfield system due to annual cost-of-service rate adjustments that increased revenue in the fourth quarter of 2020 and decreased revenue in the fourth quarter of 2019, partially offset by decreased volumes. These increases were offset partially by a decrease of $130.9 million, resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).
Service revenues – fee based increased by $482.5 million for the year ended December 31, 2019, primarily due to increases of (i) $266.8 million at the West Texas complex due to a higher average gathering fee effective January 2019 ($186.3 million) and increased throughput ($80.5 million), (ii) $106.1 million at the DBM water systems due to increased throughput and new gathering and disposal agreements effective July 1, 2018, (iii) $67.9 million at the DJ Basin complex due to increased throughput and a higher average processing fee, (iv) $48.6 million at the DBM oil system due to increased throughput and a higher average gathering fee due to a new agreement effective May 2018, and (v) $37.2 million at the DJ Basin oil system due to increased throughput, a higher average gathering fee, and an annual cost-of-service rate adjustment made during the fourth quarter of 2019. These increases were offset partially by a decrease of $32.6 million at the Springfield system due to decreased volumes and an annual cost-of-service rate adjustment in the fourth quarter of 2019.

Service revenues – product based

Service revenues – product based decreased by $21.8 million for the year ended December 31, 2020, primarily due to (i) decreased third-party volumes at the DJ Basin complex and MGR assets and (ii) decreased pricing across several systems.
Service revenues – product based decreased by $18.7 million for the year ended December 31, 2019, primarily due to (i) a decrease in volumes and pricing across several systems and (ii) a third-party producer contract termination at the West Texas complex at the end of the first quarter of 2019.


81

Product Sales
Year Ended December 31,
thousands except percentages and
per-unit amounts
20202019Inc/
(Dec)
2018Inc/
(Dec)
Natural-gas sales$30,527 $66,557 (54)%$85,015 (22)%
NGLs sales108,032 219,831 (51)%218,005 %
Total Product sales$138,559 $286,388 (52)%$303,020 (5)%
Per-unit gross average sales price:
Natural gas (per Mcf)$1.45 $1.65 (12)%$2.16 (24)%
NGLs (per Bbl)13.14 20.93 (37)%31.55 (34)%

Natural-gas sales

Natural-gas sales decreased by $36.0 million for the year ended December 31, 2020, primarily due to decreases of (i) $15.2 million at the DJ Basin complex attributable to a decrease in average prices, (ii) $9.8 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (iii) $6.2 million at the Hilight system resulting from an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown (further discussed below), and (iv) $2.6 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).
Natural-gas sales decreased by $18.5 million for the year ended December 31, 2019, primarily due to decreases of $24.0 million and $7.2 million at the West Texas and DJ Basin complexes, respectively, due to decreases in average prices, partially offset by increases in volumes sold. These decreases were offset partially by an increase of $13.7 million at the Hilight system primarily due to the reversal of a portion of an accrual for anticipated product-purchase costs recorded in 2018 associated with the shutdown of the Kitty Draw gathering system.

NGLs sales

NGLs sales decreased by $111.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $34.0 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (ii) $27.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (iii) $17.7 million at the DJ Basin complex attributable to a decrease in average prices, and (iv) $14.7 million at the Brasada complex, $6.7 million at the Chipeta complex, and $6.1 million at the MGR assets resulting from decreases in average prices and volumes sold.
NGLs sales increased by $1.8 million for the year ended December 31, 2019, primarily due to increases of (i) $17.7 million at the DJ Basin complex due to an increase in volumes sold, (ii) $7.1 million related to commodity-price swap agreements that expired in December 2018, and (iii) $3.2 million at the DBM water systems due to an increase in volumes sold related to byproducts from the treatment of produced water. These increases were offset partially by decreases of (i) $14.3 million and $7.6 million at the MGR assets and Granger complex, respectively, due to decreases in average prices and volumes sold, and (ii) $6.1 million at the Chipeta complex due to a decrease in average price.

82

Equity Income, Net – Related Parties
Year Ended December 31,
thousands except percentages20202019Inc/
(Dec)
2018Inc/
(Dec)
Equity income, net – related parties$226,750 $237,518 (5)%$195,469 22 %

Equity income, net – related parties decreased by $10.8 million for the year ended December 31, 2020, primarily due to a decrease in equity income from Whitethorn LLC related to commercial activities and decreased volumes, and decreased rates at White Cliffs. These decreases were offset partially by increases related to the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and increased volumes on TEP, FRP, Ranch Westex, and Red Bluff Express.
Equity income, net – related parties increased by $42.0 million for the year ended December 31, 2019, primarily due to (i) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline due to additional committed volumes in 2019, (ii) increased volumes at FRP and the Saddlehorn pipeline, and (iii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019. These increases were offset partially by a decrease in volumes at TEP.

Cost of Product and Operation and Maintenance Expenses
Year Ended December 31,
thousands except percentages20202019Inc/
(Dec)
2018Inc/
(Dec)
NGLs purchases$131,964 $331,872 (60)%$292,698 13 %
Residue purchases65,193 100,570 (35)%125,106 (20)%
Other(9,069)11,805 (177)%(2,299)NM
Cost of product188,088 444,247 (58)%415,505 %
Operation and maintenance580,874 641,219 (9)%480,861 33 %
Total Cost of product and Operation and maintenance expenses$768,962 $1,085,466 (29)%$896,366 21 %
_________________________________________________________________________________________
NMNot meaningful

NGLs purchases

NGLs purchases decreased by $199.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $139.5 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $32.6 million at the West Texas complex attributable to average-price decreases, partially offset by purchased-volume increases, (iii) $13.8 million at the Brasada complex attributable to purchased-volume decreases, partially offset by average-price increases, and (iv) $6.9 million at the Chipeta complex attributable to average-price and purchased-volume decreases.
NGLs purchases increased by $39.2 million for the year ended December 31, 2019, primarily due to increases of (i) $48.1 million and $10.6 million at the West Texas and DJ Basin complexes, respectively, primarily due to increases in volumes purchased and (ii) $3.3 million at the DBM water systems due to an increase in volumes purchased related to byproducts from the treatment of produced water. These increases were offset partially by decreases of (i) $9.8 million and $6.3 million at the MGR assets and Granger complex, respectively, due to decreases in average prices and volumes purchased and (ii) $7.4 million at the Chipeta complex due to a decrease in average price.

83

Residue purchases

Residue purchases decreased by $35.4 million for the year ended December 31, 2020, primarily due to decreases of (i) $21.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $11.3 million at the DJ Basin complex attributable to average-price decreases, and (iii) $4.3 million at the MGR assets attributable to average-price and purchased-volume decreases. These decreases were offset partially by an increase of $3.2 million at the Chipeta complex primarily due to purchased-volume and average-price increases.
Residue purchases decreased by $24.5 million for the year ended December 31, 2019, primarily due to decreases of (i) $16.8 million at the West Texas complex due to a decrease in average price, partially offset by an increase in volumes purchased, (ii) $3.8 million at the MGR assets due to a decrease in volumes purchased, and (iii) $2.7 million at the Hilight system due to decreases in volumes purchased and average price.

Other items

Other items decreased by $20.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $10.3 million at the West Texas complex due to changes in imbalance positions and (ii) $10.0 million at the DJ Basin complex due to a decrease in transportation costs and changes in imbalance positions.
Other items increased by $14.1 million for the year ended December 31, 2019, primarily due to increases of (i) $8.4 million at the West Texas complex due to changes in imbalance positions and an increase in volumes purchased and (ii) $4.0 million at the DJ Basin complex due to an increase in transportation costs.

Operation and maintenance expense

Operation and maintenance expense decreased by $60.3 million for the year ended December 31, 2020, primarily as a result of focused cost-savings initiatives related to the stand-up of WES as an independent organization, resulting in decreases of (i) $34.2 million at the West Texas complex primarily resulting from decreased salaries and wages, contract labor and consulting services, and surface maintenance and plant repairs expense, (ii) $6.1 million and $3.3 million at the Springfield and DBM oil systems, respectively, primarily due to decreased salaries and wages and surface maintenance and plant repairs expense, partially offset by increases in other field expenses, (iii) $4.6 million at the Chipeta complex primarily attributable to decreased surface maintenance and plant repairs and utilities expense, and (iv) $3.2 million and $2.4 million at the Hilight system and Granger complex, respectively, primarily due to decreased salaries and wages, surface maintenance and plant repairs, and safety expense.
Operation and maintenance expense increased by $160.4 million for the year ended December 31, 2019, primarily due to increases of (i) $51.1 million at the DBM water systems due to new water-disposal systems that commenced operations during the third and fourth quarters of 2018 and higher surface-use fees, (ii) $39.0 million, $32.3 million, and $17.9 million at the West Texas complex, DJ Basin complex, and DBM oil system, respectively, primarily due to increases in surface maintenance and plant repairs, salaries and wages, utilities expense, and contract labor and consulting services, (iii) $6.9 million at the DJ Basin oil system due to increases in surface maintenance and plant repairs, salaries and wages, and utilities expense, and (iv) $5.9 million at the Springfield system due to increases in surface maintenance and plant repairs and safety expense.

84

Other Operating Expenses
Year Ended December 31,
thousands except percentages20202019Inc/
(Dec)
2018Inc/
(Dec)
General and administrative (1)
$155,769 $114,591 36 %$67,195 71 %
Property and other taxes68,340 61,352 11 %51,848 18 %
Depreciation and amortization491,086 483,255 %389,164 24 %
Long-lived asset and other impairments203,889 6,279 NM230,584 (97)%
Goodwill impairment441,017 — NM— NM
Total other operating expenses$1,360,101 $665,477 104 %$738,791 (10)%
_________________________________________________________________________________________
(1)Includes general and administrative expenses incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets.

General and administrative expenses

For the years ended December 31, 2019 and 2018, General and administrative expenses were determined by rate estimation and allocated to us from Occidental pursuant to the omnibus agreements. Effective with the December 2019 Agreements, WES began to incur such costs directly, or via direct charge from Occidental, pursuant to the terms of the Services Agreement.
General and administrative expenses increased by $41.2 million for the year ended December 31, 2020, primarily due to (i) $21.2 million related to information technology services provided by Occidental to WES and (ii) $16.4 million in personnel costs primarily resulting from WES securing its own dedicated workforce as of December 31, 2019. General and administrative expenses also increased by $6.0 million for the year ended December 31, 2020, primarily due to increases in corporate expenses and professional fees. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
General and administrative expenses increased by $47.4 million for the year ended December 31, 2019, primarily due to increases of (i) $46.1 million of personnel costs for which we reimbursed Occidental pursuant to the omnibus agreements, primarily as a result of the rate-redetermination provisions in the omnibus agreements with Occidental, resulting in a 30% increase in reimbursements for general and administrative expenses incurred on our behalf, which took effect January 1, 2019, and (ii) $6.3 million of expenses related to equity awards. These amounts were offset partially by a decrease of $4.4 million in legal and consulting fees.

Property and other taxes

Property and other taxes increased by $7.0 million for the year ended December 31, 2020, primarily due to ad valorem tax increases of $6.5 million at the DJ Basin complex due to capital projects being placed into service, including the completion of Latham Train I in November 2019. This increase was offset partially by ad valorem tax decreases in Utah and West Texas due to lower valuations and lower tax rates.
Property and other taxes increased by $9.5 million for the year ended December 31, 2019, primarily due to ad valorem tax increases (i) at the West Texas complex due to the start-up of Mentone Train I in November 2018 and (ii) at the DJ Basin complex due to the completion of capital projects.


85

Depreciation and amortization expense

Depreciation and amortization expense increased by $7.8 million for the year ended December 31, 2020, primarily due to increases of (i) $11.9 million and $5.9 million at the West Texas complex and DBM oil system, respectively, resulting from capital projects being placed into service, (ii) $7.8 million of amortization expense related to finance leases, and (iii) $3.3 million for a pipeline in Wyoming due to revisions in cost estimates related to asset retirement obligations. These amounts were offset partially by decreases of (i) $10.6 million at the DJ Basin complex primarily as a result of a change in estimate for asset retirement obligations for the Third Creek gathering system of $32.7 million, offset by increased depreciation expense of $22.1 million for capital projects being placed into service, (ii) $10.3 million at the Hilight system primarily attributable to revisions in cost estimates related to asset retirement obligations and an acceleration of depreciation expense in the comparative prior period, and (iii) $5.3 million at the Chipeta complex primarily due to lower depreciation as a result of the impairment incurred during the first quarter of 2020. See Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information regarding asset retirement obligations.
Depreciation and amortization expense increased by $94.1 million for the year ended December 31, 2019, primarily due to increases of (i) $36.4 million at the West Texas complex, (ii) $24.8 million at the DBM water systems, (iii) $13.6 million at the DBM oil system, and (iv) $8.2 million at the DJ Basin complex, all due to capital projects being placed into service. In addition, for the year ended December 31, 2019, there was an increase of $7.5 million at the Hilight system, primarily due to an acceleration of depreciation expense and revisions in cost estimates related to asset retirement obligations. For further information regarding capital projects, see Liquidity and Capital Resources—Capital expenditures within this Item 7.

Long-lived asset and other impairment expense

Long-lived asset and other impairment expense for the year ended December 31, 2020, was primarily due to (i) $150.2 million of impairments for assets located in Wyoming and Utah, (ii) a $29.4 million other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of $16.7 million at the DJ Basin complex primarily due to the cancellation of projects and impairments of rights-of-way, and (iv) impairments of $3.8 million at the DBM oil system primarily due to the cancellation of projects.
Long-lived asset and other impairment expense for the year ended December 31, 2019, was primarily due to impairments of $4.9 million at the DJ Basin complex due to impairments of rights-of-way and cancellation of projects.
    Long-lived asset and other 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, (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, (v) $5.6 million at the Chipeta complex, and (vi) $2.6 million at the DBM oil system.
For further information on Long-lived asset and other impairment expense for the periods presented, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Goodwill impairment expense

During the three months ended March 31, 2020, an interim goodwill impairment test was performed due to significant unit-price declines triggered by the combined impacts from the global outbreak of COVID-19 and the oil-market disruption. As a result of the interim impairment test, a goodwill impairment of $441.0 million was recognized for the gathering and processing reporting unit. For additional information, see Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

86

Interest Income – Anadarko Note Receivable and Interest Expense
Year Ended December 31,
thousands except percentages20202019Inc/
(Dec)
2018Inc/
(Dec)
Interest income – Anadarko note receivable$11,736 $16,900 (31)%$16,900 — %
Third parties
Long-term and short-term debt$(369,815)$(315,872)17 %$(200,454)58 %
Finance lease liabilities(1,510)— NM— NM
Amortization of debt issuance costs and commitment fees(13,501)(12,424)%(9,110)36 %
Capitalized interest4,774 26,980 (82)%32,479 (17)%
Related parties
APCWH Note Payable (1,833)(100)%(6,746)(73)%
Finance lease liabilities(6)(137)(96)%— NM
Interest expense$(380,058)$(303,286)25 %$(183,831)65 %

Interest income

Interest income - Anadarko note receivable decreased by $5.2 million for the year ended December 31, 2020, due to the exchange of the Anadarko note receivable under the Unit Redemption Agreement. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Interest expense

Interest expense increased by $76.8 million for the year ended December 31, 2020, primarily due to (i) $150.9 million of interest incurred on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, 5.250% Senior Notes due 2050, and Floating-Rate Senior Notes due 2023 that were issued in January 2020 and (ii) a decrease of $22.2 million in capitalized interest due to decreased capital expenditures. These increases were offset partially by decreases of (i) $75.0 million that occurred as a result of the repayment and termination of the Term loan facility in January 2020 and (ii) $15.5 million due to lower outstanding borrowings under the RCF in 2020. See Liquidity and Capital Resources—Debt and credit facilities within this Item 7.
Interest expense increased by $119.5 million for the year ended December 31, 2019, primarily due to (i) $74.9 million of interest incurred on the Term loan facility entered into in December 2018, (ii) $23.4 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, (iii) $18.5 million due to higher outstanding borrowings on the RCF in 2019, and (iv) $9.5 million due to interest incurred on the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 that were issued in March 2018.

87

Other Income (Expense), Net
Year Ended December 31,
thousands except percentages20202019Inc/
(Dec)
2018Inc/
(Dec)
Other income (expense), net$1,025 $(123,785)NM$(4,763)NM

Other income (expense), net increased by $124.8 million for the year ended December 31, 2020, primarily due to non-cash losses of $125.3 million on interest-rate swaps incurred during the year ended December 31, 2019. All outstanding interest-rate swap agreements were settled in December 2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
Other income (expense), net decreased by $119.0 million for the year ended December 31, 2019, primarily due to non-cash losses of $125.3 million on interest-rate swaps that were settled in December 2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Income Tax Expense (Benefit)
Year Ended December 31,
thousands except percentages20202019Inc/
(Dec)
2018Inc/
(Dec)
Income (loss) before income taxes$522,850$821,172(36)%$689,58819 %
Income tax expense (benefit)5,99813,472(55)%58,934(77)%
Effective tax rate1 %%%

We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax. Income attributable to the AMA assets prior to and including February 2019 was subject to federal and state income tax. Income earned on the AMA assets for periods subsequent to February 2019 was subject only to Texas margin tax on income apportionable to Texas.
For the year ended December 31, 2020, the variance from the federal statutory rate primarily was due to our Texas margin tax liability. For the years ended December 31, 2019 and 2018, the variance from the federal statutory rate primarily was due to federal and state taxes on pre-acquisition income attributable to assets previously acquired from Anadarko, and our share of applicable Texas margin tax.


88

KEY PERFORMANCE METRICS
Year Ended December 31,
thousands except percentages and per-unit amounts20202019Inc/
(Dec)
2018Inc/
(Dec)
Adjusted gross margin for natural-gas assets$1,820,926 $1,656,041 10 %$1,443,466 15 %
Adjusted gross margin for crude-oil and NGLs assets647,390 578,100 12 %447,131 29 %
Adjusted gross margin for produced-water assets249,889 193,936 29 %87,608 121 %
Adjusted gross margin2,718,205 2,428,077 12 %1,978,205 23 %
Per-Mcf Adjusted gross margin for natural-gas assets (1)
1.16 1.07 %1.01 %
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (2)
2.54 2.44 %2.40 %
Per-Bbl Adjusted gross margin for produced-water assets (3)
0.98 0.97 %1.02 (5)%
Adjusted EBITDA2,030,366 1,719,090 18 %1,466,445 17 %
Free cash flow1,227,099 37,134 NM(704,464)(105)%
_________________________________________________________________________________________
(1)Average for period. Calculated as Adjusted gross margin for natural-gas assets, divided by total throughput (MMcf/d) attributable to WES for natural-gas assets.
(2)Average for period. Calculated as Adjusted gross margin for crude-oil and NGLs assets, divided by total throughput (MBbls/d) attributable to WES for crude-oil and NGLs assets.
(3)Average for period. Calculated as Adjusted gross margin for produced-water assets, divided by total throughput (MBbls/d) attributable to WES for produced-water assets.

Adjusted gross margin, Adjusted EBITDA, and Free 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 financial measures within this Item 7.

Adjusted gross margin. Adjusted gross margin increased by $290.1 million for the year ended December 31, 2020, primarily due to (i) increased throughput at the West Texas and DJ Basin complexes and the DBM water systems, (ii) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system, (iii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, (iv) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020, and (v) annual cost-of-service rate adjustments at the Springfield system that increased revenues in the fourth quarter of 2020 and decreased revenues in the fourth quarter of 2019 (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). These increases were offset partially by (i) a decrease in distributions from Whitethorn LLC related to commercial activities and (ii) a decrease at the Hilight system resulting from lower throughput and an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown.
Adjusted gross margin increased by $449.9 million for the year ended December 31, 2019, primarily due to (i) increased throughput at the West Texas and DJ Basin complexes, (ii) the start-up of new water-disposal systems during the third and fourth quarters of 2018, (iii) increased throughput and a higher average gathering fee due to a new agreement effective May 2018 at the DBM oil system, (iv) increased throughput, a higher average gathering fee, and an annual cost-of-service rate adjustment made during the fourth quarter of 2019 at the DJ Basin oil system, and (v) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline. These increases were offset partially by decreased throughput and an annual cost-of-service rate adjustment in the fourth quarter of 2019 at the Springfield system (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

89

Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.09 for the year ended December 31, 2020, primarily due to increased throughput at the West Texas and DJ Basin complexes, which have higher-than-average per-Mcf margins as compared to our other natural-gas assets.
Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.06 for the year ended December 31, 2019, primarily due to increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.10 for the year ended December 31, 2020, primarily due to (i) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020. These increases were offset partially by a decrease in distributions from Whitethorn LLC related to commercial activities.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.04 for the year ended December 31, 2019, primarily due to (i) increased throughput, a higher average gathering fee, and an annual cost-of-service rate adjustment made during the fourth quarter of 2019 at the DJ Basin oil system, (ii) increased throughput and a higher average gathering fee due to a new agreement effective May 2018 at the DBM oil system, and (iii) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline.
Per-Bbl Adjusted gross margin for produced-water assets decreased by $0.05 for the year ended December 31, 2019, primarily due to increased throughput on volumes with lower-than-average per-Bbl margin.

Adjusted EBITDA. Adjusted EBITDA increased by $311.3 million for the year ended December 31, 2020, primarily due to (i) a $256.1 million decrease in cost of product (net of lower of cost or market inventory adjustments), (ii) a $60.3 million decrease in operation and maintenance expenses, (iii) a $26.4 million increase in total revenues and other, and (iv) a $14.0 million increase in distributions from equity investments. These amounts were offset partially by (i) a $33.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense and (ii) a $7.0 million increase in property taxes.
The above-described variances in cost of product and total revenues and other include the impacts resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020, which had no net impact on Adjusted EBITDA (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).
Adjusted EBITDA increased by $252.6 million for the year ended December 31, 2019, primarily due to (i) a $446.5 million increase in total revenues and other and (ii) a $47.9 million increase in distributions from equity investments. These amounts were offset partially by (i) a $160.4 million increase in operation and maintenance expenses, (ii) a $40.3 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, (iii) a $29.3 million increase in cost of product (net of lower of cost or market inventory adjustments), and (iv) a $9.5 million increase in property taxes.

Free cash flow. Free cash flow increased by $1,190.0 million for the year ended December 31, 2020, primarily due to (i) a decrease of $765.7 million in capital expenditures, (ii) an increase of $313.3 million in net cash provided by operating activities, and (iii) a decrease of $109.0 million in contributions to equity investments.
Free cash flow increased by $741.6 million for the year ended December 31, 2019, primarily due to (i) a decrease of $759.8 million in capital expenditures and (ii) a decrease of $5.2 million in contributions to equity investments. These amounts were offset partially by a decrease of $24.1 million in net cash provided by operating activities.
See Capital Expenditures and Historical Cash Flow within this Item 7 for further information.

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LIQUIDITY AND CAPITAL RESOURCES

Our primary cash uses include capital expenditures, debt service, customary operating expenses, quarterly distributions, and distributions to our noncontrolling interest owners. Our sources of liquidity as of December 31, 2020, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, and potential 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 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. We may rely on external financing sources, including equity and debt issuances, to fund capital expenditures and future acquisitions. However, we also may use operating cash flows to fund capital expenditures or acquisitions, which could result in borrowings under the RCF to pay distributions or to fund other short-term working capital requirements.
Under our partnership agreement, we distribute all of our available cash (beyond proper reserves as defined in our partnership agreement) within 55 days following each quarter’s end. Our cash flow and resulting ability to make cash distributions are dependent on our ability to generate cash flow from operations. Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter. The general partner establishes cash reserves to provide for the proper conduct of our business, including (i) reserves to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters. We have made cash distributions to our unitholders each quarter since our IPO in 2012. The Board of Directors declared a cash distribution to unitholders for the fourth quarter of 2020 of $0.31100 per unit, or $131.3 million in the aggregate. The cash distribution was paid on February 12, 2021, to our unitholders of record at the close of business on February 1, 2021. See General Trends and Outlook within this Item 7.
In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of the common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time. As of December 31, 2020, we had repurchased 2,368,711 common units through open-market purchases for a total of $32.5 million. The units were canceled by the Partnership immediately upon receipt.
Management continuously monitors our leverage position and coordinates our capital expenditures and quarterly distributions with expected cash inflows and projected debt service requirements. 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 maturing debt balances with longer-term debt issuances. 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 this Form 10-K.

Working capital. As of December 31, 2020, we had a $17.9 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Working capital is an indication of liquidity and potential needs for short-term funding. Working capital requirements are driven by changes in accounts receivable and accounts payable and other factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for acquisitions, maintenance, and capital activities. As of December 31, 2020, there was $2.0 billion available for borrowing under the RCF. See Note 11—Selected Components of Working Capital and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. Capital expenditures includes maintenance capital expenditures, which include those expenditures required to maintain 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; and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to extend the useful lives of our assets, reduce costs, increase revenues, or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.
Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:
Year Ended December 31,
thousands202020192018
Acquisitions$511 $2,101,229 $162,112 
Capital expenditures (1) (2)
423,091 1,188,829 1,948,595 
Capital incurred (1) (3)
307,644 1,055,151 1,910,508 
_________________________________________________________________________________________
(1)For the years ended December 31, 2020, 2019, and 2018 included $4.8 million, $23.3 million, and $31.1 million respectively, of capitalized interest.
(2)Capital expenditures for the year ended December 31, 2018, included $762.8 million of pre-acquisition capital expenditures for AMA.
(3)Capital incurred for the year ended December 31, 2018, included $733.1 million of pre-acquisition capital incurred for AMA.

Acquisitions during 2019 included AMA and the 30% interest in Red Bluff Express. Acquisitions during 2018 included a 20% interest in Whitethorn LLC, a 15% interest in Cactus II, and related-party asset contributions. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Capital expenditures decreased by $765.7 million for the year ended December 31, 2020, primarily due to decreases of (i) $362.5 million at the DJ Basin complex primarily related to the completion of Latham Trains I and II that commenced operations in November 2019 and February 2020, respectively, as well as decreases in pipeline, well connection, and compression projects, (ii) $186.8 million at the West Texas complex primarily attributable to the completion of Mentone Train II that commenced operations in March 2019 and decreases in pipeline and well connection projects, (iii) $107.5 million at the DBM oil system primarily related to the completion of the Loving ROTF Train III that commenced operations in January 2020 and decreases in pipeline and well connection projects, and (iv) $90.4 million at the DBM water systems primarily due to reduced construction of additional water-disposal facilities and gathering projects.
Capital expenditures decreased by $759.8 million for the year ended December 31, 2019, primarily due to decreases of (i) $427.1 million at the West Texas complex primarily due to the completion of Mentone Trains I and II that commenced operations in November 2018 and March 2019, respectively, (ii) $240.1 million at the DBM oil system primarily due to the completion of the ROTFs that commenced operations in the second quarter of 2018, and (iii) $194.8 million at the DBM water systems due to the completion of the water systems that commenced operations in the third and fourth quarters of 2018. These decreases were offset partially by an increase of $91.3 million at the DJ Basin complex, primarily due to continued construction of the Latham processing plant.

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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, investing, and financing activities:
Year Ended December 31,
thousands202020192018
Net cash provided by (used in):
Operating activities$1,637,418 $1,324,100 $1,348,175 
Investing activities(448,254)(3,387,853)(2,210,813)
Financing activities(844,204)2,071,573 875,192 
Net increase (decrease) in cash and cash equivalents$344,960 $7,820 $12,554 

Operating activities. Net cash provided by operating activities increased for the year ended December 31, 2020, primarily due to higher cash operating income, lower cash paid to settle interest-rate swap agreements, and higher distributions from equity-investment earnings. These increases were offset partially by higher interest expense. Net cash provided by operating activities decreased for the year ended December 31, 2019, primarily due to cash paid to settle interest-rate swap agreements, partially offset by increases in distributions from equity investments and the impact of other 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, 2020, included the following:

$423.1 million of capital expenditures, primarily related to construction, expansion, and asset-integrity projects at the West Texas and DJ Basin complexes, DBM water systems, and DBM oil system;

$57.8 million of additions to materials and supplies inventory;

$19.4 million of capital contributions primarily paid to Cactus II and FRP for construction activities;

$32.2 million of distributions received from equity investments in excess of cumulative earnings; and

$20.3 million in proceeds primarily from the sale of Fort Union.

Net cash used in investing activities for the year ended December 31, 2019, included the following:

$2.0 billion of cash paid for the acquisition of AMA;

$1.2 billion of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM oil system, and DBM water systems;

$128.4 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Red Bluff Express, Whitethorn LLC, and White Cliffs for construction activities;

$92.5 million of cash paid for the acquisition of our interest in Red Bluff Express; and

$30.3 million of distributions received from equity investments in excess of cumulative earnings.

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 our interests in Whitethorn LLC and Cactus II;

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

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

Financing activities. Net cash used in financing activities for the year ended December 31, 2020, included the following:

$3.0 billion of repayments of outstanding borrowings under the Term loan facility;

$600.0 million of repayments of outstanding borrowings under the RCF;

$695.8 million of distributions paid to WES unitholders;

$203.9 million to purchase and retire portions of WES Operating’s 5.375% Senior Notes due 2021, 4.000% Senior Notes due 2022, and Floating-Rate Senior Notes via open-market repurchases;

$32.5 million of unit repurchases;

$15.4 million of distributions paid to the noncontrolling interest owners of WES Operating;

$14.2 million of finance lease payments;

$8.6 million of distributions paid to the noncontrolling interest owner of Chipeta;

$3.5 billion of net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes issued in January 2020, which were used to repay the $3.0 billion outstanding borrowings under the Term loan facility, repay outstanding amounts under the RCF, and for general partnership purposes;

$220.0 million of borrowings under the RCF, which were used for general partnership purposes, including the funding of capital expenditures;

$20.7 million of increases in outstanding checks due mostly to ad valorem tax payments made at the end of the year; and

$20.0 million of a one-time cash contribution from Occidental received in January 2020, pursuant to the Services Agreement, for anticipated transition costs required to establish stand-alone human resources and information technology functions.

Net cash provided by financing activities for the year ended December 31, 2019, included the following:

$3.0 billion of borrowings under the Term loan facility, net of issuance costs, which were used to fund the acquisition of AMA, to repay the APCWH Note Payable, and to repay amounts outstanding under the RCF;

$1.2 billion of borrowings under the RCF, which were used for general partnership purposes, including the funding of capital expenditures;

$458.8 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;

$11.0 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;

$7.4 million of capital contributions from Anadarko related to the above-market component of swap agreements;
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$1.0 billion of repayments of outstanding borrowings under the RCF;

$969.1 million of distributions paid to WES unitholders;

$439.6 million of repayments of the total outstanding balance under the APCWH Note Payable;

$118.2 million of distributions paid to the noncontrolling interest owners of WES Operating;

$28.0 million of repayments of the total outstanding balance under the WGP RCF, which matured in March 2019; and

$9.7 million of distributions paid to the noncontrolling interest owner of Chipeta.

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;

$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;

$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;

$321.8 million of 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 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;

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

$502.5 million of distributions paid to WES unitholders;

$386.3 million of distributions paid to the noncontrolling interest owners of WES Operating;

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

$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 Term loan facility.
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Debt and credit facilities. As of December 31, 2020, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $376.9 million in 2021. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating Senior Notes. In January 2020, WES Operating issued the following notes:

Fixed-Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050, offered to the public at prices of 99.962%, 99.900%, and 99.442%, respectively, of the face amount. Including the effects of the issuance prices, underwriting discounts, and interest-rate adjustments (described below), the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 4.291%, 5.173%, and 6.375%, respectively, at December 31, 2020. These effective interest rates will increase by 0.25% on February 1, 2021, due to credit-rating downgrades. Interest is paid on each such series semi-annually on February 1 and August 1 of each year, beginning August 1, 2020; and

Floating-Rate Senior Notes due 2023. As of December 31, 2020, the interest rate on the Floating-Rate Senior Notes was 2.07%. Interest is paid quarterly in arrears on January 13, April 13, July 13, and October 13 of each year. Interest is determined at a benchmark rate (which is initially a three-month LIBOR rate) on the interest determination date plus an initial spread of 0.85%.

Net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes were used to repay the $3.0 billion in outstanding borrowings under the Term loan facility and outstanding amounts under the RCF, and for general partnership purposes. The interest payable on each of the Fixed-Rate Senior Notes and Floating-Rate Senior Notes is subject to adjustment from time to time if the credit rating assigned to such notes declines below certain specified levels or if credit-rating downgrades are subsequently followed by credit-rating upgrades. As a result of credit-rating downgrades received from Fitch, S&P, and Moody’s, annualized borrowing costs will increase by $43.0 million. See General Trends and Outlook within this Item 7.
During the year ended December 31, 2020, WES Operating purchased and retired $218.0 million of certain of its senior notes and Floating-Rate Senior Notes via open-market repurchases, and gains of $13.5 million were recognized for the early retirement of these notes.
As of December 31, 2020, the 5.375% Senior Notes due 2021 were classified as short-term debt on the consolidated balance sheet. Subsequent to December 31, 2020, WES Operating delivered notice to redeem the 5.375% Senior Notes due 2021 on March 1, 2021, as per the optional redemption terms in WES Operating’s indenture. At December 31, 2020, WES Operating was in compliance with all covenants under the relevant governing indentures.
We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open-market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors. The amounts involved may be material.

WGP RCF. The WGP RCF, which previously was available to purchase WES Operating common units and for general partnership purposes, matured in March 2019, and the $28.0 million of outstanding borrowings were repaid.

Revolving credit facility. The RCF is expandable to a maximum of $2.5 billion 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 on WES Operating’s senior unsecured debt rating. A required quarterly facility fee is paid ranging from 0.125% to 0.250% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating. In December 2019, WES Operating entered into an amendment to the RCF to, among other things, exercise the final one-year extension option to extend the maturity date of the RCF from February 2024 to February 2025, for each extending lender. The maturity date with respect to each non-extending lender, whose commitments represent $100.0 million out of $2.0 billion of total commitments from all lenders, remains February 2024. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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As of December 31, 2020, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $2.0 billion of available borrowing capacity under the RCF. At December 31, 2020, the interest rate on any outstanding RCF borrowings was 1.64% and the facility-fee rate was 0.25%. At December 31, 2020, WES Operating was in compliance with all covenants under the RCF. As a result of credit-rating downgrades, beginning in the second quarter of 2020, the interest rate on our outstanding RCF borrowings increased by 0.20% and the RCF facility-fee rate increased by 0.05%, from 0.20% to 0.25%. See General Trends and Outlook within this Item 7.
The RCF contains certain covenants that limit, among other things, WES Operating’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related-party transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, certain 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 EBITDA 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 a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited. See General Trends and Outlook within this Item 7.

Term loan facility. In December 2018, WES Operating entered into the Term loan facility, the proceeds from which were 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 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). In January 2020, WES Operating repaid the outstanding borrowings with proceeds from the issuance of the Fixed-Rate Senior Notes and Floating-Rate Senior Notes and terminated the Term loan facility. During the first quarter of 2020, a loss of $2.3 million was recognized for the early termination of the Term loan facility. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Finance lease liabilities. WES subleased equipment from Occidental via finance leases that extended through April 2020. During the first quarter of 2020, WES entered into finance leases with third parties for equipment and vehicles extending through 2029. As of December 31, 2020, we have future finance-lease payments of $8.6 million in 2021 and a total of $28.1 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

APCWH Note Payable. In June 2017, in connection with funding the construction of the APC water systems that were acquired as part of the AMA acquisition, APCWH entered into an eight-year note payable agreement with Anadarko. This note payable had a maximum borrowing limit of $500.0 million, including accrued interest. The APCWH Note Payable was repaid at Merger completion. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Interest-rate swaps. In December 2018 and March 2019, WES Operating entered into interest-rate swap agreements with an aggregate notional principal amount of $750.0 million and $375.0 million, respectively, to manage interest-rate risk associated with anticipated debt issuances. Pursuant to these swap agreements, WES Operating received a floating interest rate indexed to the three-month LIBOR and paid a fixed interest rate. In November and December 2019, WES Operating entered into additional interest-rate swap agreements with an aggregate notional principal amount of $1,125.0 million, effectively offsetting the swap agreements entered into in December 2018 and March 2019.
In December 2019, all outstanding interest-rate swap agreements were settled. As part of the settlement, WES Operating made cash payments of $107.7 million and recorded an accrued liability of $25.6 million to be paid quarterly in 2020. For the year ended December 31, 2020, WES Operating made cash payments of $25.6 million. These cash payments were classified as cash flows from operating activities in the consolidated statements of cash flows.
We did not apply hedge accounting and, therefore, gains and losses associated with the interest-rate swap agreements were recognized in earnings. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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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, plant, and equipment. Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. As of December 31, 2020, we expect to incur asset retirement costs of $20.2 million in 2021 and a total of $260.3 million in years thereafter. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Operating leases. We have entered into operating leases that extend through 2039 for corporate offices, shared field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors. As of December 31, 2020, we have future operating-lease payments of $4.0 million in 2021 and a total of $46.5 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Pipeline commitments. In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline. As of December 31, 2020, we have estimated future minimum-volume-commitment fees of $3.7 million in 2021 and a total of $14.8 million in years thereafter.

Credit risk. We bear credit risk through exposure to non-payment or non-performance by our counterparties, including Occidental, 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, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to gas-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. A substantial portion of our throughput is sourced from producers, including Occidental, that recently received credit-rating downgrades. We are subject to the risk of non-payment or late payment by producers for gathering, processing, transportation, and disposal fees. Through December 31, 2020, we were also dependent on Occidental to remit payments to us for the value of volumes of residue gas, NGLs, crude oil, and condensate that it purchased from us under our commodity purchase and sale agreements. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our rights to request adequate assurance.
We expect our exposure to the concentrated risk of non-payment or non-performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues. While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. We also are party to agreements with Occidental under which Occidental 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 previously acquired from Anadarko. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements; commodity purchase and sale agreements; the contribution agreements; or the December 2019 Agreements.

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ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING

Our consolidated financial statements include the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below.

Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows:
Year Ended December 31,
thousands202020192018
Net income (loss) attributable to WES$527,012 $697,241 $551,571 
Limited partner interests in WES Operating not held by WES (1)
10,830 103,364 70,474 
General and administrative expenses (2)
3,552 6,819 4,029 
Other income (expense), net(17)(79)(192)
Interest expense 245 2,035 
Net income (loss) attributable to WES Operating$541,377 $807,590 $627,917 
_________________________________________________________________________________________
(1)Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES. The public held a 0% limited partner interest in WES Operating as of December 31, 2020 and 2019, and a 59.2% limited partner interest in WES Operating as of December 31, 2018. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating as of December 31, 2020 and 2019, and a 9.7% limited partner interest in WES Operating as of December 31, 2018. Immediately prior to the Merger closing, the WES Operating IDRs and the general partner units were converted into a non-economic general partner interest in WES Operating and WES Operating common units, and at Merger completion, all WES Operating common units held by the public and subsidiaries of Anadarko (other than common units held by WES, WES Operating GP, and 6.4 million common units held by a subsidiary of Anadarko) were converted into WES common units. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.

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Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows:
Year Ended December 31,
thousands202020192018
WES net cash provided by operating activities$1,637,418 $1,324,100 $1,348,175 
General and administrative expenses (1)
3,552 6,819 4,029 
Non-cash equity-based compensation expense(7,858)(1,259)(278)
Changes in working capital7,556 2,383 (854)
Other income (expense), net(17)(79)(192)
Interest expense 245 2,035 
Debt related amortization and other items, net (20)(801)
WES Operating net cash provided by operating activities$1,640,651 $1,332,189 $1,352,114 
WES net cash provided by (used in) financing activities$(844,204)$2,071,573 $875,192 
Distributions to WES unitholders (2)
695,834 969,073 502,457 
Distributions to WES from WES Operating (3)
(756,112)(1,006,163)(507,323)
Increase (decrease) in outstanding checks(35)— — 
Registration expenses related to the issuance of WES common units 855 — 
Unit repurchases32,535 — — 
WGP RCF costs — 
WGP RCF repayments 28,000 — 
WES Operating net cash provided by (used in) financing activities$(871,982)$2,063,338 $870,333 
_________________________________________________________________________________________
(1)Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
(2)Represents distributions to WES common unitholders paid under WES’s partnership agreement. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(3)Difference attributable to elimination in consolidation of WES Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third-party interest in Chipeta (see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

WES Operating distributions. WES Operating distributes all of its available cash (beyond proper reserves as defined in its partnership agreement) to WES Operating unitholders of record on the applicable record date within 45 days following each quarter’s end.
Immediately prior to the Merger closing, the WES Operating IDRs and general partner units were converted into WES Operating common units and a non-economic general partner interest in WES Operating, and at Merger completion, all WES Operating common units held by the public and subsidiaries of Anadarko (other than common units held by WES, WES Operating GP, and 6.4 million common units held by a subsidiary of Anadarko) were converted into WES common units. Beginning with the first quarter of 2019, WES Operating has made quarterly cash distributions to WES and WGRAH, a subsidiary of Occidental, in proportion to their share of limited partner interests in WES Operating. For each quarter ended March 31, 2020, June 30, 2020, and September 30, 2020, WES Operating distributed $143.4 million to its limited partners. For the quarter ended December 31, 2020, WES Operating distributed $127.5 million to its limited partners. See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating LTIP. Concurrent with the Merger closing, we assumed the Western Gas Partners, LP 2017 Long-Term Incentive Plan. See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to property, plant, and equipment, other intangible assets, goodwill, equity investments, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues, and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances, or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with our general partner’s Audit Committee. For additional information concerning accounting policies, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Service revenues fee based. Certain of our midstream services contracts have minimum-volume commitment demand fees and fees that require periodic rate redeterminations based on 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 based on the total expected variable consideration under the contract. The cost-of-service 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. If management determines it is probable that a significant reversal in the cumulative catch-up revenue adjustment could occur, the variable consideration may be constrained up to the amount of the probable significant reversal. During the year ended December 31, 2020, revenue was constrained under one of our gas-gathering and oil-gathering contracts due to uncertainty related to ongoing legal proceedings and commercial negotiations with the counterparties to the contracts. Future revenue reversals could occur to the extent the outcome of the legal proceedings and commercial negotiations differ from our current assumptions. See Revenue and cost of product in Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Contract balances in Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments of property, plant, and equipment and other intangible assets. Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Because prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control, the assets acquired were 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.
Management assesses property, plant, and equipment, together with any associated materials and supplies inventory and intangible assets, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable. Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values. Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate an impairment assessment.
Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset. When alternative courses of action for future use of a long-lived asset are under consideration, estimates of future undiscounted net cash flows incorporate the possible outcomes and probabilities of their occurrence. The primary assumptions used to estimate undiscounted future net cash flows include long-range customer production forecasts and revenue, capital, and operating expense estimates. Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets.

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If an impairment exists, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value, such that the asset’s carrying value is adjusted down to its estimated fair value with an offsetting charge to impairment expense. Management’s estimate of the asset’s fair value may be determined based on the estimates of future discounted net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.
We recognized long-lived asset and other impairments of $203.9 million (which includes an other-than-temporary impairment expense of an equity investment), $6.3 million, and $230.6 million for the years ended December 31, 2020, 2019, and 2018, respectively. See Note 9—Property, Plant, and Equipment and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the years ended December 31, 2020, 2019, and 2018.

Impairment of goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. Goodwill also includes the allocated historic carrying value of midstream goodwill attributed to assets previously acquired from Anadarko. Our goodwill has been allocated to two reporting units: (i) gathering and processing and (ii) transportation.
We evaluate goodwill for impairment at the reporting unit level 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 goodwill is impaired and if deemed necessary based on this assessment, a quantitative assessment is then performed. If the quantitative assessment indicates that the carrying value of the reporting unit, including goodwill, exceeds its fair value, a goodwill impairment is recorded for the amount by which the reporting unit’s carrying value exceeds its fair value.
When qualitatively evaluating whether the fair value of a reporting unit is less than its carrying value, relevant events and circumstances are assessed, including significant changes in our unit price, significant declines in commodity prices, significant increases in operating and capital costs, impairments recognized, acquisitions and disposals of assets, changes in throughput and producer activity, and significant declines in trading multiples for our peers.
Quoted market prices for our reporting units are not available. Management determines fair value using various valuation techniques, including market EBITDA multiples and discounted cash-flow analysis. Management considers observable transactions in the market, and trading multiples for peers, to determine an appropriate multiple to apply against our projected EBITDA. The EBITDA multiples are based on current and historic multiples for comparable midstream companies of similar size and business profit to WES. The EBITDA projections require significant assumptions including, among others, future throughput volumes based on current expectations of producer activity and operating costs. This approach may be supplemented by a discounted cash-flow analysis. Key assumptions in this analysis include the use of an appropriate discount rate, terminal-year multiples, and estimated future cash flows, including estimates of throughput, capital expenditures, operating, and general and administrative costs. Different assumptions regarding these key inputs could have a significant impact on fair value and the amount of recorded impairment, if any.
During the three months ended March 31, 2020, we performed an interim goodwill impairment test due to a significant decline in the trading price of our common units, triggered by the combined impacts from the global outbreak of COVID-19 and the oil-market disruption resulting from significantly lower global demand and corresponding oversupply of crude oil. We primarily used the market approach and Level-3 inputs to estimate the fair value of our two reporting units. The market approach was based on multiples of EBITDA and our projected future EBITDA. The reasonableness of the market approach was tested against an income approach that was based on a discounted cash-flow analysis. We also reviewed the reasonableness of the total fair value of both reporting units to the market capitalization as of March 31, 2020, and the reasonableness of an implied acquisition premium. As a result of the interim impairment test, we recognized a goodwill impairment of $441.0 million during the first quarter of 2020, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero. Goodwill allocated to the transportation reporting unit of $4.8 million as of March 31, 2020, was not impaired.

Fair value. Impairment analyses for long-lived assets, goodwill, equity investments and the initial recognition of asset retirement obligations and environmental obligations use Level-3 inputs. Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions, and interest-rate swaps. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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RECENT ACCOUNTING DEVELOPMENTS

See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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. 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, 2020, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under 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 the below-described imbalances.
We bear a limited degree of commodity-price risk with respect to settlement of natural-gas imbalances that arise from differences in gas volumes received into our systems and gas volumes delivered by us to customers, and for instances where actual liquids recovery or fuel usage varies from 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 settlement timing of the imbalances. See General Trends and Outlook under Part II, Item 7 and Risk Factors under Part I, Item 1A of this Form 10-K.

Interest-rate risk. The FOMC decreased its target range for the federal funds rate three times during 2019 and twice in 2020. Any future increases in the federal funds rate likely will result in an increase in short-term financing costs. As of December 31, 2020, we had (i) no outstanding borrowings under the RCF that bear interest at a rate based on LIBOR or an alternative base rate at WES Operating’s option, and (ii) the Floating-Rate Senior Notes that bear interest at a rate based on LIBOR. While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on our outstanding borrowings, it would impact the fair value of the senior notes at December 31, 2020. See General Trends and Outlook under Part II, Item 7 and Risk Factors under Part I, Item 1A of this Form 10-K.
Additional variable-rate debt may be issued in the future, either under the RCF or other financing sources, including commercial bank borrowings or debt issuances.

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Item 8.  Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS











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WESTERN MIDSTREAM PARTNERS, LP
WESTERN MIDSTREAM OPERATING, LP

REPORT OF MANAGEMENT

Management of Western Midstream Partners, LP’s (the “Partnership”) general partner and Western Midstream Operating, LP’s (“WES Operating”) general partner prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the Partnership’s and WES Operating’s financial positions, results of operations, and cash flows in conformity with accounting principles generally accepted in the United States (“GAAP”). In preparing the consolidated financial statements, the Partnership and WES Operating include amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Partnership’s and WES Operating’s consolidated financial statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to KPMG LLP all of the Partnership’s and WES Operating’s financial records and related data, and the minutes of the meetings of the Board of Directors.

MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s and WES Operating’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Partnership’s and WES Operating’s internal control over financial reporting as of December 31, 2020. This assessment was based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on our assessment using the COSO criteria, we concluded the Partnership’s and WES Operating’s internal control over financial reporting was effective as of December 31, 2020.
KPMG LLP, the Partnership’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2020.

WESTERN MIDSTREAM PARTNERS, LP
/s/ Michael P. Ure
Michael P. Ure
President, Chief Executive Officer and Chief Financial Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
WESTERN MIDSTREAM OPERATING, LP
/s/ Michael P. Ure
Michael P. Ure
President, Chief Executive Officer and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)

February 26, 2021


105

WESTERN MIDSTREAM PARTNERS, LP

Report of Independent Registered Public Accounting Firm

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

Opinion on Internal Control Over Financial Reporting

We have audited Western Midstream Partners, LP and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2020 and 2019, 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, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated February 26, 2021 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.


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Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ KPMG LLP
Houston, Texas
February 26, 2021

107

WESTERN MIDSTREAM PARTNERS, LP

Report of Independent Registered Public Accounting Firm

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

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Western Midstream Partners, LP and subsidiaries (the Partnership) as of December 31, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2021 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

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 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impairment assessment of long-lived assets

As discussed in Note 9 to the consolidated financial statements, the Partnership’s consolidated property, plant, and equipment balance was $8.7 billion as of December 31, 2020. During the year ended December 31, 2020, the Partnership recognized long-lived asset and other impairment charges of $203.9 million, a portion of which related
108

to impairment of a specific long-lived asset group located in Wyoming and Utah. On at least a quarterly basis, management reviews its asset groups for indicators of impairment that would indicate the carrying value of an asset group might not be recoverable. If an asset group displays an indicator of impairment, it is tested for recoverability by comparing the sum of the estimated future undiscounted cash flows attributable to the asset group to the carrying value of the asset group. An impairment loss is determined if the carrying value of the asset group is not recoverable and is measured as the excess of the carrying value over the asset group’s fair value.

We identified the evaluation of the impairment assessment for a specific long-lived asset group in Wyoming and Utah as a critical audit matter. Subjective auditor judgment was required to evaluate the Partnership’s estimate of the fair value of the asset group, specifically the assessment of the projected throughput and discount rate assumptions. Specialized skills and knowledge were required to evaluate the discount rate used in the valuation model.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Partnership’s long-lived asset impairment process. This included certain controls over the determination of the forecasted throughput and the discount rate. We compared historical forecasted volumes to actual volumetric results to assess the Partnership’s ability to forecast. We evaluated the forecasted throughput included in the valuation model by comparing it to external market and industry data related to producer drilling activity in the relevant basin. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the discount rate used in the valuation model by developing a range of independent estimates that was determined using publicly available market data for comparable entities, and comparing the discount rate selected by management to the range of independently developed estimates.

Goodwill impairment assessment for the gathering and processing reporting unit

As discussed in Note 10 to the consolidated financial statements, the Partnership recognized a goodwill impairment of $441.0 million related to the gathering and processing reporting unit during the first quarter of 2020. The Partnership conducts an impairment test annually on October 1 and when events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. An impairment charge will be recognized to the extent that the fair value of a reporting unit is less than its carrying value. The fair value of the reporting unit is estimated using both the market approach and the income approach. The market approach estimates fair value by applying a market multiple, determined by reference to market multiples for comparable publicly traded companies, to the expected earnings before interest, taxes, depreciation, and amortization (“EBITDA”) of the gathering and processing reporting unit. The income approach is based on forecasted future cash flows that are discounted to present value using a discount rate that considers timing and risk of future cash flows.

We identified the evaluation of the goodwill impairment assessment for the gathering and processing reporting unit as a critical audit matter. A higher degree of subjective auditor judgment was required to evaluate the fair value of the gathering and processing reporting unit based on the market and income approaches. Specifically, subjective auditor judgment and specialized skills and knowledge were required to evaluate the Partnership’s estimate of EBITDA multiples for comparable publicly traded companies and the discount rate used in determining the fair value of the reporting unit.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Partnership’s goodwill impairment process. This included certain controls over the determination of the EBITDA multiples and discount rate used in the estimation of the fair value of the gathering and processing reporting unit. We involved valuation professionals with specialized skills and knowledge, who assisted in assessing the EBITDA multiples used by management in the valuation, including examining the guideline public companies used to determine the market multiples and rationale for selected multiples used by management in the valuation analysis. Further, the valuation professionals assisted in evaluating the discount rate used in the discounted cash flow model by developing a range of independent estimates that was determined using publicly available market data for comparable entities and comparing the discount rate selected by management to the range of independently developed estimates. We tested the reconciliation of the aggregate estimated fair value of the reporting units to the market capitalization of the Partnership.
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Estimated constraint on variable consideration related to a certain gas-gathering revenue contract and oil-gathering revenue contract with a customer

As discussed in Notes 1 and 2 to the consolidated financial statements, certain of the Partnership’s midstream services agreements have minimum-volume commitment demand fees and fees that require periodic rate redeterminations based on the related midstream facility cost-of-service rate provisions. Annual adjustments are made to the cost-of-service rates charged to certain of its customers, and as a result, a cumulative catch-up revenue adjustment related to services already provided may be recorded. The Partnership assesses whether a significant reversal of the cumulative catch-up revenue adjustment is probable of occurring and if so, the variable consideration may be constrained up to the amount of the probable significant reversal.

We identified the assessment of the estimated constraint on variable consideration related to one gas-gathering contract and one oil-gathering revenue contract as a critical audit matter. A high degree of challenging auditor judgment was required to evaluate the probability of a significant reversal in the amount of variable consideration recognized due to the uncertainty related to ongoing legal proceedings and commercial negotiations with the counterparties to the contracts.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Partnership’s annual re-determination of the cost-of-service rate. This included certain controls over the determination of the constraint on the variable consideration expected to be received under the contracts. We evaluated responses received from external legal counsel to our audit inquiry on the progress of the Partnership’s legal proceedings with the counterparties to the contracts. We examined publicly available court filings to assess the development of the legal proceedings. We made inquiries of management and inspected information available regarding the status of negotiations with the counterparties and the resulting impact on the determination of the estimated constraint on variable consideration. We evaluated the accuracy of the data used by the Partnerships to calculate the variable consideration constraint.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2012.

Houston, Texas
February 26, 2021
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WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands except per-unit amounts202020192018
Revenues and other
Service revenues – fee based$2,584,323 $2,388,191 $1,905,728 
Service revenues – product based48,369 70,127 88,785 
Product sales138,559 286,388 303,020 
Other1,341 1,468 2,125 
Total revenues and other (1)
2,772,592 2,746,174 2,299,658 
Equity income, net – related parties226,750 237,518 195,469 
Operating expenses
Cost of product188,088 444,247 415,505 
Operation and maintenance580,874 641,219 480,861 
General and administrative155,769 114,591 67,195 
Property and other taxes68,340 61,352 51,848 
Depreciation and amortization491,086 483,255 389,164 
Long-lived asset and other impairments203,889 6,279 230,584 
Goodwill impairment441,017 
Total operating expenses (2)
2,129,063 1,750,943 1,635,157 
Gain (loss) on divestiture and other, net8,634 (1,406)1,312 
Operating income (loss)878,913 1,231,343 861,282 
Interest income – Anadarko note receivable11,736 16,900 16,900 
Interest expense(380,058)(303,286)(183,831)
Gain (loss) on early extinguishment of debt11,234 
Other income (expense), net (3)
1,025 (123,785)(4,763)
Income (loss) before income taxes522,850 821,172 689,588 
Income tax expense (benefit)5,998 13,472 58,934 
Net income (loss)516,852 807,700 630,654 
Net income (loss) attributable to noncontrolling interests(10,160)110,459 79,083 
Net income (loss) attributable to Western Midstream Partners, LP$527,012 $697,241 $551,571 
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Midstream Partners, LP$527,012 $697,241 $551,571 
Pre-acquisition net (income) loss allocated to Anadarko0 (29,279)(182,142)
General partner interest in net (income) loss(11,104)(5,637)
Limited partners’ interest in net income (loss) (4)
515,908 662,325 369,429 
Net income (loss) per common unit – basic and diluted (4)
$1.18 $1.59 $1.69 
Weighted-average common units outstanding – basic and diluted435,554 415,794 218,936 
_________________________________________________________________________________________
(1)Total revenues and other includes related-party amounts of $1.8 billion, $1.6 billion, and $1.4 billion for the years ended December 31, 2020, 2019, and 2018, respectively. See Note 6.
(2)Total operating expenses includes related-party amounts of $182.7 million, $503.2 million, and $334.2 million for the years ended December 31, 2020, 2019, and 2018, respectively. See Note 6.
(3)Other income (expense), net includes losses associated with the interest-rate swap agreements for the years ended December 31, 2019 and 2018. See Note 13.
(4)See Note 5.
See accompanying Notes to Consolidated Financial Statements.
111

WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
December 31,
thousands except number of units20202019
ASSETS
Current assets
Cash and cash equivalents$444,922 $99,962 
Accounts receivable, net452,880 260,512 
Other current assets45,262 41,938 
Total current assets943,064 402,412 
Anadarko note receivable0 260,000 
Property, plant, and equipment
Cost12,641,745 12,355,671 
Less accumulated depreciation3,931,800 3,290,740 
Net property, plant, and equipment8,709,945 9,064,931 
Goodwill4,783 445,800 
Other intangible assets776,409 809,391 
Equity investments1,224,813 1,285,717 
Other assets (1)
171,013 78,202 
Total assets (2)
$11,830,027 $12,346,453 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$210,691 $293,128 
Short-term debt438,870 7,873 
Accrued ad valorem taxes41,427 35,160 
Accrued liabilities269,947 149,793 
Total current liabilities960,935 485,954 
Long-term liabilities
Long-term debt7,415,832 7,951,565 
Deferred income taxes22,195 18,899 
Asset retirement obligations260,283 336,396 
Other liabilities275,570 208,346 
Total long-term liabilities7,973,880 8,515,206 
Total liabilities (3)
8,934,815 9,001,160 
Equity and partners’ capital
Common units (413,839,863 and 443,971,409 units issued and outstanding at December 31, 2020 and 2019, respectively)2,778,339 3,209,947 
General partner units (9,060,641 units issued and outstanding at December 31, 2020 and 2019) (4)
(17,208)(14,224)
Total partners’ capital2,761,131 3,195,723 
Noncontrolling interests134,081 149,570 
Total equity and partners’ capital2,895,212 3,345,293 
Total liabilities, equity, and partners’ capital$11,830,027 $12,346,453 
________________________________________________________________________________________
(1)Other assets includes $4.2 million and $4.5 million of NGLs line-fill inventory as of December 31, 2020 and 2019, respectively. Other assets also includes $71.9 million of materials and supplies inventory as of December 31, 2020. See Note 1.
(2)Total assets includes related-party amounts of $1.6 billion and $1.7 billion as of December 31, 2020 and 2019, respectively, which includes related-party Accounts receivable, net of $291.3 million and $113.3 million as of December 31, 2020 and 2019, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $164.7 million and $108.8 million as of December 31, 2020 and 2019, respectively. See Note 6.
(4)See Note 1.
See accompanying Notes to Consolidated Financial Statements.
112

WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
 Partners’ Capital  
thousandsNet
Investment
by Anadarko
Common
Units
General
Partner
Units
Noncontrolling
Interests
Total
Balance at December 31, 2017$1,050,171 $1,061,125 $$2,883,754 $4,995,050 
Cumulative effect of accounting change (1)
629 (14,200)— (30,179)(43,750)
Net income (loss)182,142 369,429 — 79,083 630,654 
Above-market component of swap agreements with Anadarko (2)
— 51,618 — — 51,618 
WES Operating equity transactions, net (3)
— (19,577)— 19,577 
Distributions to Chipeta noncontrolling interest owner— — — (13,529)(13,529)
Distributions to noncontrolling interest owners of WES Operating— — — (386,326)(386,326)
Distributions to Partnership unitholders— (502,457)— — (502,457)
Contributions of equity-based compensation from Anadarko— 5,741 — — 5,741 
Net pre-acquisition contributions from (distributions to) related parties97,755 — — — 97,755 
Net contributions from (distributions to) related parties58,835 — — — 58,835 
Adjustments of net deferred tax liabilities(1,514)— — — (1,514)
Other— 209 — 397 606 
Balance at December 31, 2018$1,388,018 $951,888 $$2,552,777 $4,892,683 
Net income (loss)29,279 662,325 5,637 110,459 807,700 
Cumulative impact of the Merger transactions (4)
— 3,169,800 — (3,169,800)
Issuance of general partner units (5)
— 19,861 (19,861)— 
Above-market component of swap agreements with Anadarko (2)
— 7,407 — — 7,407 
WES Operating equity transactions, net (3)
— (755,197)— 755,197 
Distributions to Chipeta noncontrolling interest owner— — — (9,663)(9,663)
Distributions to noncontrolling interest owners of WES Operating— — — (118,225)(118,225)
Distributions to Partnership unitholders— (969,073)— — (969,073)
Acquisitions from related parties (6)
(2,149,218)112,872 — 28,845 (2,007,501)
Contributions of equity-based compensation from Occidental— 13,968 — — 13,968 
Net pre-acquisition contributions from (distributions to) related parties458,819 — — — 458,819 
Net contributions from (distributions to) related parties— (90)— — (90)
Adjustments of net deferred tax liabilities273,102 (4,375)— — 268,727 
Other— 561 — (20)541 
Balance at December 31, 2019$$3,209,947 $(14,224)$149,570 $3,345,293 
Net income (loss) 515,908 11,104 (10,160)516,852 
Distributions to Chipeta noncontrolling interest owner   (8,644)(8,644)
Distributions to noncontrolling interest owners of WES Operating   (15,434)(15,434)
Distributions to Partnership unitholders (681,746)(14,088) (695,834)
Unit exchange with Occidental (2)
 (256,640) (5,238)(261,878)
Unit repurchases (5)
 (32,535)  (32,535)
Acquisitions from related parties (3,987) 3,987 0 
Contributions of equity-based compensation from Occidental 14,604   14,604 
Equity-based compensation expense 7,857   7,857 
Net contributions from (distributions to) related parties (7)
 4,466  20,000 24,466 
Other 465   465 
Balance at December 31, 2020$0 $2,778,339 $(17,208)$134,081 $2,895,212 
_________________________________________________________________________________________
(1)Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018.
(2)See Note 6.
(3)For the years ended December 31, 2019 and 2018, the $755.2 million and $19.6 million decrease to partners’ capital, respectively, together with net income (loss) attributable to Western Midstream Partners, LP, totaled $(58.0) million and $532.0 million, respectively.
(4)See Note 1.
(5)See Note 5.
(6)The amounts allocated to common unitholders and noncontrolling interests represent a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.
(7)See December 2019 Agreements—Services, Secondment, and Employee Transfer Agreement within Note 1.


See accompanying Notes to Consolidated Financial Statements.
113

WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202020192018
Cash flows from operating activities
Net income (loss)$516,852 $807,700 $630,654 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization491,086 483,255 389,164 
Long-lived asset and other impairments203,889 6,279 230,584 
Goodwill impairment441,017 
Non-cash equity-based compensation expense22,462 15,494 6,431 
Deferred income taxes3,296 7,609 139,048 
Accretion and amortization of long-term obligations, net8,654 8,441 5,943 
Equity income, net – related parties(226,750)(237,518)(195,469)
Distributions from equity-investment earnings – related parties246,637 234,572 187,392 
(Gain) loss on divestiture and other, net(8,634)1,406 (1,312)
(Gain) loss on early extinguishment of debt(11,234)
(Gain) loss on interest-rate swaps0 125,334 7,972 
Cash paid to settle interest-rate swaps(25,621)(107,685)
Other193 236 752 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(193,688)(45,033)(60,502)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net144,437 (30,866)45,605 
Change in other items, net24,822 54,876 (38,087)
Net cash provided by operating activities1,637,418 1,324,100 1,348,175 
Cash flows from investing activities
Capital expenditures(423,091)(1,188,829)(1,948,595)
Acquisitions from related parties0 (2,007,926)(254)
Acquisitions from third parties(511)(93,303)(161,858)
Contributions to equity investments – related parties(19,388)(128,393)(133,629)
Distributions from equity investments in excess of cumulative earnings – related parties32,160 30,256 29,585 
Proceeds from the sale of assets to third parties20,333 342 3,938 
Additions to materials and supplies inventory and other(57,757)
Net cash used in investing activities(448,254)(3,387,853)(2,210,813)
Cash flows from financing activities
Borrowings, net of debt issuance costs (1)
3,681,173 4,169,695 2,671,337 
Repayments of debt (2)
(3,803,888)(1,467,595)(1,040,000)
Increase (decrease) in outstanding checks20,699 1,571 (3,206)
Registration expenses related to the issuance of Partnership common units0 (855)
Distributions to Partnership unitholders (3)
(695,834)(969,073)(502,457)
Distributions to Chipeta noncontrolling interest owner(8,644)(9,663)(13,529)
Distributions to noncontrolling interest owners of WES Operating(15,434)(118,225)(386,326)
Net contributions from (distributions to) related parties24,466 458,819 97,755 
Above-market component of swap agreements with Anadarko (3)
0 7,407 51,618 
Finance lease payments (4)
(14,207)(508)
Unit repurchases(32,535)
Net cash provided by (used in) financing activities(844,204)2,071,573 875,192 
Net increase (decrease) in cash and cash equivalents344,960 7,820 12,554 
Cash and cash equivalents at beginning of period99,962 92,142 79,588 
Cash and cash equivalents at end of period$444,922 $99,962 $92,142 
Supplemental disclosures
Non-cash unit exchange with Occidental (3)
$(261,878)$$
Net distributions to (contributions from) Anadarko of other assets0 90 (58,835)
Interest paid, net of capitalized interest349,913 293,795 140,720 
Taxes paid (reimbursements received)(384)96 2,408 
Accrued capital expenditures25,126 140,954 274,632 
_________________________________________________________________________________________
(1)For the years ended December 31, 2019 and 2018, includes $11.0 million and $321.8 million of borrowings, respectively, under the APCWH Note Payable.
(2)For the year ended December 31, 2019, includes a $439.6 million repayment to settle the APCWH Note Payable. See Note 6.
(3)See Note 6.
(4)For the year ended December 31, 2020, includes related-party payments of $6.4 million.
See accompanying Notes to Consolidated Financial Statements.
114

WESTERN MIDSTREAM OPERATING, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of
Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP):

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Western Midstream Operating, LP and subsidiaries (WES Operating) as of December 31, 2020 and 2019, 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, 2020, 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 WES Operating as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of WES Operating’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 WES Operating 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. WES Operating is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of WES Operating’s internal control over financial reporting. Accordingly, we express no such opinion.

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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impairment assessment of long-lived assets

As discussed in Note 9 to the consolidated financial statements, WES Operating’s consolidated property, plant, and equipment balance was $8.7 billion as of December 31, 2020. During the year ended December 31, 2020, WES Operating recognized long-lived asset and other impairment charges of $203.9 million, a portion of which related to impairment of a specific long-lived asset group located in Wyoming and Utah. On at least a quarterly basis,
115

management reviews its asset groups for indicators of impairment that would indicate the carrying value of an asset group might not be recoverable. If an asset group displays an indicator of impairment, it is tested for recoverability by comparing the sum of the estimated future undiscounted cash flows attributable to the asset group to the carrying value of the asset group. An impairment loss is determined if the carrying value of the asset group is not recoverable and is measured as the excess of the carrying value over the asset group’s fair value.

We identified the evaluation of the impairment assessment for a specific long-lived asset group in Wyoming and Utah as a critical audit matter. Subjective auditor judgment was required to evaluate WES Operating’s estimate of the fair value of the asset group, specifically the assessment of the projected throughput and discount rate assumptions. Specialized skills and knowledge were required to evaluate the discount rate used in the valuation model.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over WES Operating’s long-lived asset impairment process. This included certain controls over the determination of the forecasted throughput and the discount rate. We compared historical forecasted volumes to actual volumetric results to assess WES Operating’s ability to forecast. We evaluated the forecasted throughput included in the valuation model by comparing it to external market and industry data related to producer drilling activity in the relevant basin. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the discount rate used in the valuation model by developing a range of independent estimates that was determined using publicly available market data for comparable entities, and comparing the discount rate selected by management to the range of independently developed estimates.

Goodwill impairment assessment for the gathering and processing reporting unit

As discussed in Note 10 to the consolidated financial statements, WES Operating recognized a goodwill impairment of $441.0 million related to the gathering and processing reporting unit during the first quarter of 2020. WES Operating conducts an impairment test annually on October 1 and when events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. An impairment charge will be recognized to the extent that the fair value of a reporting unit is less than its carrying value. The fair value of the reporting unit is estimated using both the market approach and the income approach. The market approach estimates fair value by applying a market multiple, determined by reference to market multiples for comparable publicly traded companies, to the expected earnings before interest, taxes, depreciation, and amortization (“EBITDA”) of the gathering and processing reporting unit. The income approach is based on forecasted future cash flows that are discounted to present value using a discount rate that considers timing and risk of future cash flows.

We identified the evaluation of the goodwill impairment assessment for the gathering and processing reporting unit as a critical audit matter. A higher degree of subjective auditor judgment was required to evaluate the fair value of the gathering and processing reporting unit based on the market and income approaches. Specifically, subjective auditor judgment and specialized skills and knowledge were required to evaluate WES Operating’s estimate of EBITDA multiples for comparable publicly traded companies and the discount rate used in determining the fair value of the reporting unit.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over WES Operating’s goodwill impairment process. This included certain controls over the determination of the EBITDA multiples and discount rate used in the estimation of the fair value of the gathering and processing reporting unit. We involved valuation professionals with specialized skills and knowledge, who assisted in assessing the EBITDA multiples used by management in the valuation, including examining the guideline public companies used to determine the market multiples and rationale for selected multiples used by management in the valuation analysis. Further, the valuation professionals assisted in evaluating the discount rate used in the discounted cash flow model by developing a range of independent estimates that was determined using publicly available market data for comparable entities and comparing the discount rate selected by management to the range of independently developed estimates. We tested the reconciliation of the aggregate estimated fair value of the reporting units to the market capitalization of Western Midstream Partners, LP.
116


Estimated constraint on variable consideration related to a certain gas-gathering revenue contract and oil-gathering revenue contract with a customer

As discussed in Notes 1 and 2 to the consolidated financial statements, certain of WES Operating’s midstream services agreements have minimum-volume commitment demand fees and fees that require periodic rate redeterminations based on the related midstream facility cost-of-service rate provisions. Annual adjustments are made to the cost-of-service rates charged to certain of its customers, and as a result, a cumulative catch-up revenue adjustment related to services already provided may be recorded. WES Operating assesses whether a significant reversal of the cumulative catch-up revenue adjustment is probable of occurring and if so, the variable consideration may be constrained up to the amount of the probable significant reversal.

We identified the assessment of the estimated constraint on variable consideration related to one gas-gathering contract and one oil-gathering revenue contract as a critical audit matter. A high degree of challenging auditor judgment was required to evaluate the probability of a significant reversal in the amount of variable consideration recognized due to the uncertainty related to ongoing legal proceedings and commercial negotiations with the counterparties to the contracts.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over WES Operating’s annual re-determination of the cost-of-service rate. This included certain controls over the determination of the constraint on the variable consideration expected to be received under the contracts. We evaluated responses received from external legal counsel to our audit inquiry on the progress of WES Operating’s legal proceedings with the counterparties to the contracts. We examined publicly available court filings to assess the development of the legal proceedings. We made inquiries of management and inspected information available regarding the status of negotiations with the counterparties and the resulting impact on the determination of the estimated constraint on variable consideration. We evaluated the accuracy of the data used by WES Operating to calculate the variable consideration constraint.

/s/ KPMG LLP

We have served as WES Operating’s auditor since 2007.

Houston, Texas
February 26, 2021

117

WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
thousands except per-unit amounts202020192018
Revenues and other
Service revenues – fee based$2,584,323 $2,388,191 $1,905,728 
Service revenues – product based48,369 70,127 88,785 
Product sales138,559 286,388 303,020 
Other1,341 1,468 2,125 
Total revenues and other (1)
2,772,592 2,746,174 2,299,658 
Equity income, net – related parties226,750 237,518 195,469 
Operating expenses
Cost of product188,088 444,247 415,505 
Operation and maintenance580,874 641,219 480,861 
General and administrative152,217 107,772 63,166 
Property and other taxes68,340 61,352 51,848 
Depreciation and amortization491,086 483,255 389,164 
Long-lived asset and other impairments203,889 6,279 230,584 
Goodwill impairment441,017 
Total operating expenses (2)
2,125,511 1,744,124 1,631,128 
Gain (loss) on divestiture and other, net8,634 (1,406)1,312 
Operating income (loss)882,465 1,238,162 865,311 
Interest income – Anadarko note receivable11,736 16,900 16,900 
Interest expense(380,058)(303,041)(181,796)
Gain (loss) on early extinguishment of debt11,234 
Other income (expense), net (3)
1,008 (123,864)(4,955)
Income (loss) before income taxes526,385 828,157 695,460 
Income tax expense (benefit)5,998 13,472 58,934 
Net income (loss)520,387 814,685 636,526 
Net income (loss) attributable to noncontrolling interest(20,990)7,095 8,609 
Net income (loss) attributable to Western Midstream Operating, LP$541,377 $807,590 $627,917 
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Midstream Operating, LP$541,377 $807,590 $627,917